summary of the bhp field test and update work€¦ · 26/10/2011 · (bhp-10 to bhp-13) and 14 to...

i | SRK Consulting (U.S.), Inc.

Summary of the BHP Copper Florence ISR Field Test and Updated Work

PRELIMINARY DRAFT

(Never completed in 2010. Selected discussion may now be out of date)

Report Prepared for

Curis Resources Ltd.

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SWVP-0640

ii | SRK Consulting (U.S.), Inc.

Report Prepared by

SRK Consulting (U.S.), Inc.

204400.03

October 22, 2010

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SRK_BHPFieldTest_SummaryRpt_Jul2010-Draft__ckh_20111026_dmj October 2010

Summary of the BHP Copper Florence ISR Field Test and Updated Work

Curis Resources Ltd. 1020-800 West Pender Street Vancouver, BC Canada V6C 2V6

SRK Consulting (U.S.), Inc.

3275 West Ina Road, Suite 240 Tucson, AZ 85741

e-mail: [email protected] website: www.srk.com

Tel: 1.520 544 3688 Fax: 1.520 544 9853

SRK Project Number 204400.03 October 2010 Author:

Corolla Hoag, R.G.

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Preliminary Draft SRK_BHPFieldTest_SummaryRpt_Jul2010-Draft__ckh_20111026_dmj October 2010

Executive Summary Between 1969 and 1975, an extensive, low-grade porphyry copper deposit was delineated by

Continental Oil Company. The deposit, located north of the Gila River and north-northwest of the Town of Florence, was subsequently owned by Magma Copper Company (Magma) and BHP Copper

Inc. (BHP). These companies invested significant efforts in performing additional exploration

drilling, metallurgical test work, aquifer tests, environmental permitting, biological and cultural

resource studies, geochemical modeling, and pre-feasibility level engineering design work (BHP, 1997a-d).

The deposit is buried by a minimum of 370 feet of unconsolidated basin-fill formations. The pre-

feasibility studies reviewed operational alternatives including open pit-heap leach and in-situ copper recovery (ISCR) methods. The physical characteristics of the deposit made the latter method both

possible and the most economic approach. Extensive aquifer testing was performed to support

environmental permitting, but a field test with raffinate injection and copper dissolutions and

recovery was needed to provide additional data for the economic model and life-of-mine plan. BHP initiated an ISCR field test in 1997. The summary sections below provide a brief overview of the

test goals and results; details are provided in Sections 2 through 8. The intent was to compile and

review the available data and reports, summarize the findings, and provide comments on the lessons learned and recommendations for the future production field test (PTF) to be performed by Curis

Resources Ltd. Additional information on the site history and current status is presented in the NI

43-101 Preliminary Economic Assessment for the Florence Project (SRK, 2010b).

Field Test Overview and Goals

From 1997 through 1999, BHP conducted a field test study for an in-situ copper solution project near Florence, Arizona. The field test design used a wellfield of four injection wells and nine recovery

wells with associated monitoring wells to observe the surrounding water levels and chemical

reactions. The wells were installed in a 5-spot pattern with a distance of 50 ft between each injection and recovery well and 71 ft between each injection well. The wellfield location was situated in a

representative portion of the deposit with a typical oxide zone thickness and an average total copper

grade. The well design was developed to protect the local aquifers and was approved by the Arizona Department of Environmental Quality (ADEQ), the U.S. Environmental Protection Agency, and the

Arizona Department of Water Resources. A tank farm, 7-acre lined pond, and pipeline corridor were

built to support the test. Data collected during the test included well construction records, water

quality analyses, and field records, which were entered into a project database. Instrumentation and software was used and developed to record the:

Flows in and out of the wellfield, pond, and tank farm;

Data from pressure transducer in the wells and conductivity probe measurements;

Water levels in the wellfield, pond, and tanks; and

Measurements from the leak collection and recovery system in the pond.

A dilute injectate using raffinate from the BHP San Manuel solvent extraction/electrowinning (SX/EW) Plant mixed with groundwater from a nearby well was injected into the oxide mineralized

deposit via the four injection wells. The injected solution traveled through fractures and porous spaces in the highly fractured bedrock, reacted with the copper-bearing minerals, and dissolved and

transported the copper in solution. The solution was then recovered by a series of recovery wells

(also known as production or pumping wells) surrounding the injection wells and sent to the

evaporation pond; copper cathode was not produced. During the test, the injection rate into the wellfield was approximately 121 gallons per minute (gpm) and the recovery rate was 150 gpm – a 20

percent over-pumping rate. This was done to maintain an inward hydraulic gradient towards the

center recovery well BHP-1. The demonstration that inward hydraulic gradient could be maintained

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through differential pumping rates was required by ADEQ as a condition of the test and future

operations.

The goals of the test were to demonstrate that copper could be economically extracted via the ISCR

method while ensuring compliance with environmental regulatory requirements. The test was

intended to continue until enough data were collected to forecast the ultimate copper recovery, rate of copper recovery, and acid consumption that would occur during the planned 5-year operation of a

representative mine block. It would provide information about the build-up of other constituents in

the raffinate and pregnant solution and provide actual operations experience related to this deposit. Additionally, the test was to provide field experience on the best method to install the wells, prove

that the design would meet the mechanical integrity requirements, and provide cost data to apply to

an estimate of capital and operating costs. With recovery data in hand, BHP would have the

necessary information to estimate mineral reserves for the project and prepare a feasibility level life-of-operations plan and economic model.

Field Test Results

Although the raffinate-injection phase was originally intended to run approximately 9 to 12 months,

it was truncated prematurely after only 101 days owing to changes in corporate BHP objectives. As a result some major goals of the test, such as a determination of expected metal recovery and other

metallurgical results, were not achieved. The field test did, however, successfully demonstrate other

aspects relevant to the operation of a copper ISR facility, and the experience can be applied to the

future PTF.

The test operated during a learning period when the best installation and data recording methods

were still being developed, operators were being trained, and experiments were made with the ratio

of raffinate in the injectate. After an initial learning curve to work through the best installation methods, an effective technique and routine was developed to drill the borehole and install grouted

casing, perform the mechanical integrity tests, log and collect assay samples, develop the formation,

install the necessary compliance monitoring and production infrastructure, and operate the wells, tank farm, evaporation system, and other test facilities in a safe manner. Results of the test are

briefly summarized below.

Well Design and Mechanical Integrity

The basic well design was shown to meet mechanical integrity and production performance

standards required for Class III wells during the time they were in use. The design was at a cost-

effective level during the late 1990s when copper prices were much lower than they are today. The

5-year well performance audit of mechanical integrity has not performed so no conclusions can be drawn yet on the ultimate durability of the pumps, well casing and joints, and the cement bond

between the borehole wall and the polyvinyl chloride (PVC) casing during the post-test period.

Injection and Leaching Effectiveness

Average injection rates in injection wells BHP-6 to BHP-9 ranged from 21 to 35 gpm during the

period of raffinate injection. Pumping rates ranged from 10 to 13 gpm in the outer recovery wells

(BHP-10 to BHP-13) and 14 to 19 gpm in the inner recovery wells (BHP-2 to BHP-5). The central recovery well BHP-1 was pumped at a rate of 39 gpm to maintain an inward gradient. Some well

clogging occurred during the leaching phase, which decreased the pumping rates over time. The

clogging was caused by a gelatinous alumino-silicate precipitate that apparently developed because the area under leach was at intermediate pH levels and was not acid-equilibrated. The problem was

solved with the injection of raffinate around the pumps, which dissolved the precipitates.

The pH of the injectate was generally kept between 1.5 and 1.7; the composition of the injectate became more dilute over time – starting at an 8.5% raffinate to water ratio and ending at 4.1%

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raffinate to water. Low-pH injectate traveled from the injection wells and interacted with the gangue

minerals encountered along the flow path. During the raffinate injection phase the groundwater within the inner recovery wells gradually decreased from background values (pH 7-8) to pH 3.04

measured in BHP-1 and BHP-5 at test termination. Chrysocolla was dissolved and recovered as

copper-bearing pregnant solution in the inner and outer recovery wells to varying degrees of effectiveness. Water quality samplers placed within the two chemical monitor well CH-2 and CH-2

provided information on the breakthrough across the flow path at three discrete elevations.

Breakthrough and development of acid-equilibrated conditions developed within two weeks in the upper two thirds of the injection zone at CH-2 but was delayed in the bottom one-third – perhaps

indicating the presence of less fractured or less conductive rock. Recovery wells BHP-2, BHP-3,

and BHP-4 were still showing intermediate pH values (5.7-6.3) at test end with resulting limited

copper recovery. The outer recovery wells experienced continuous in-flow and dilution of neutral pH groundwater, which prevented effective copper recovery.

Estimate of Acid Consumption

Metallurgical test work (vat leach tests, bottle roll, column tests) performed by Conoco, Magma, and

BHP indicated that acid consumption ranged from a minimum of 7.6 to a maximum of 43.7 lbs acid

per lb copper produced. BHP estimated the average net acid consumption to be 3 lb acid per lb

copper produced based on the results of column tests. The correlation between these laboratory results in terms of acid consumption and copper recovery, however, and what would be seen in the

field conditions with much lower porosity and flow rate relative to column tests was uncertain (and a

major goal of the field test). Raffinate injection did not continue long enough in the field test to achieve free acid breakthrough (pH~<3.5) in most of the inner recovery wells so acid consumption

and copper recovery rates were not confirmed. Based on a review of the historic metallurgical tests,

however, SRK Consulting (SRK) believes the average net acid consumption will likely be higher at

5 lb acid per lb copper produced. This includes 4 lb acid consumption in the wellfield and 1 lb acid consumption in the plant.

Rinsing Effectiveness

Following the cessation of the raffinate injection phase on February 8, 1998, a period of rinsing

began in order to restore the water quality in the oxide bedrock aquifer to meet regulatory

requirements. The Underground Injection Control Permit required the resource block (field test) to

be restored to the primary maximum contaminant level or to pre-mining background concentrations. The ADEQ Aquifer Protection Permit required restoration to meet Arizona Aquifer Water Quality

Standards (AWQS). Rinsing was completed using the residual pond water and water from nearby

water well WW-4; no rinsing amendments were used.

SRK compiled the water quality and flow records for the field test through May 1999. This included

the period of raffinate injection, injection of the residual pond water, and injection of groundwater

through May 12, 1998. It also includes the year-long period through May 11, 1999 where groundwater withdrawal occurred with no injection. Although limited pumping did continue

through the end of December 1999, SRK does not have complete flow records for dates past May

1999. An internal memorandum prepared by BHP (Kline, 2001) provides recovery information on

the period through December 2001.

Modeling performed in 1995 by Brown and Caldwell (B & C, 1996b) predicted what the water

quality of the wellfield and downgradient areas would be after closure. Their model indicated that

rinsing the injection zone to bring the sulfate concentration to below 750 mg/L would ensure that the concentrations of the various associated constituents would meet the maximum regulatory limits.

BHP rinsed the oxide aquifer in the field test area until the water quality within the test area met the

AWQSs. This was achieved for all inorganic trace metals within 12 months. Elevated gross alpha and adjusted gross alpha particle activity were detected in a number of wells through 2004. No

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process-related organic constituents were measured during the rinsing phase. As of 2007, the pH in

the injection wells was increasing but was still below 5.5 indicating that hydrogen release is still occurring; all other wells are at neutral, background pH levels.

Extraction Mass Balance – Sulfate and Copper

Sulfate was introduced through several sources including infiltration groundwater in the oxide

bedrock, and from the combination of sulfuric acid, raffinate, and WW-4 groundwater that was used

in the injectate. Sulfate was deemed to be negligible in the sodium hydroxide solution used to

neutralize the pond water.

Sulfate is a conservative tracer that can be used to monitor the effectiveness of the recovery wells

and environmental impacts related to operations. Some loss in sulfate mass was expected to occur,

but it is difficult to assign the percentage loss to each mechanism. The loss mechanisms include:

Flare-up of injected solutions into the Lower Basin-Fill Unit (LBFU) at the bedrock-LBFU

contact and potential transport away from the recovery wells;

Precipitation of epsomite or other insoluble minerals within the formation;

Precipitation of gypsum from sulfate-saturated solutions in the evaporation pond; and

Minor windborne loss during operation of the mister system in the pond (Kline, 2001).

A mass balance was performed by SRK using primarily the injection/pumping flow records and the water quality analyses of injectate and recovered solutions. Based on the data available to SRK,

approximately 89 percent of the net sulfate injected into the field test area was recovered by May 11, 1999. The sulfate mass balance information compiled by BHP indicates that 94 percent of the

injected sulfate was accounted for by August 1999 and 98% of was accounted for by June 2001

(Kline, 2001).

SRK prepared an estimate of the mass of copper recovered during the leaching and rinsing phases through May 11, 1999. The majority of the copper recovered from the field test was in the inner

recovery wells (BHP-1 and BHP-5). Groundwater dilution kept pH levels at neutral values in the

outer recovery wells BHP-10 through BHP-13, which caused low copper recoveries. The total copper extracted from October 31, 1997 to May 11, 1999 was 41,966 lbs. The net cumulative

copper mass recovered after the subtraction of copper contained in the injectate was approximately

39,743 lbs through May 1999. Approximately 2,223 lbs of copper mass (5.2% of the total extracted)

was injected back into the wellfield and not recovered – probably through precipitation in fractures or re-adsorption in montmorillonite or other clay minerals during the injection of intermediate pH,

copper-bearing pond water during the rinsing phase. The net copper recovery represents a small

fraction (3%) of the 1.34 million lbs copper estimated to be contained in the volume of rock within the inner recovery wells.

Conclusions and Recommendations for the PTF

The first field test was successful at achieving many of the hydrological, engineering, and

environmental goals that were set for the project. Significant effort was spent by the BHP science

and engineering staff to design the wellfield and plant facilities, develop the well construction methods, and perform hydrological and geochemical modeling to understand the results. Pre-test

geology and geophysical test work identified the rock and pre-test conditions. Pre-leaching injection

tests and post-leaching tracer tests added valuable information about the behavior of the wellfield before and after the raffinate injection phase. Chemical analysis of waters derived during and after

the raffinate injection phase revealed complex hydrochemical and mineralogical reactions were

occurring during the interaction of groundwater and injectate, not all of which are fully understood at this time.

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The test was operated in a representative area of E-NE trending granodiorite dikes and quartz

monzonite porphyry host rocks containing average copper grade; copper mineralization consists primarily of chrysocolla and Cu-impregnated clay and iron hydroxide minerals. After sulfide

mineralization, the rock was faulted, weathered, and heavily fractured leading to a condition in

which an oxide zone was created that has a porosity of 6 to 8 percent and aquifer properties (on a global deposit scale) resembling “equivalent porous media.” On a site-specific basis, local

heterogeneities do exist that may dominate the behavior seen in any particular test cell.

Heterogeneities may include the presence of a fault zone (aquitard or high-flow zone), a low-conductive zone within various fault zones, or host rock mineral compositions with greater than

average calcite or exchangeable clays. These local heterogeneities, including potential short-circuits

and preferred pathways, will be difficult to forecast on a site-specific basis and may be encountered

in any single field test cell selected.

The scale of an isolated test cell surrounded by recovery wells that continuously draw in fresh, non-

acidified groundwater makes determination of economic copper recovery difficult and will be of

concern in the future Curis PTF. Total copper recovery and the recovery rate in a single cell will be best understood from reactions seen in an inner set of pumping wells with companion chemical

monitoring wells. The outer recovery wells will likely not achieve the low pH required to dissolve

copper and will primarily function as an intermediate-level pH “fence” protecting the inner recovery wells from dilution by higher pH background formation waters.

Geochemical evidence during the BHP field test points to a significant amount of dilute solutions

being mixed with raffinate even at BHP-1. No combination of known cation exchange, surface

complexation, and dissolution/precipitation was discovered or modeled that could explain the chemistry in the production wells without mixing with dilute groundwater (BHP, 1999). During full

production, the injection zones in contiguous areas will reach acid-equilibration conditions that will

enable dissolution of the copper contained on fractures and within the broken rock. The behavior seen in several sets of inter-connected injection and recovery wells will provide average results that

would diminish the effects of local heterogeneity.

Although the raffinate injection phase was not of sufficient length to assess the economic concepts,

the field test provided invaluable ground-based experience to consider in the operation of the Curis PTF. The PTF ideally would operate long-enough to see breakthrough of acidified injectate and the

complete development of the copper recovery curve within the inner recovery wells. Of prime

importance is the fact that it appears that the aquifer quality can be restored to meet regulatory requirements primarily through flushing with local groundwater. Additional metallurgical test work

is recommended in regards to pre-treatment options to address cation exchange behaviors and

potentially accelerate copper dissolution. A review of post-leach rinsing treatments is also recommended to address elevated gross alpha particle activity.

The PTF should assess more than one construction method as related to drilling and casing costs,

benefits of various casing materials, installation time needed, ease of construction, and effectiveness

in adhering to environmental restrictions. The life-of-operations plan requires a large number of wells to be constructed in the year before operations begin and in each year following for the first

few years. Adjustments in borehole and casing diameters and casing materials will have a

substantial effect on the capital costs.

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Table of Contents

Executive Summary ................................................................................................................... ii

1 Introduction .................................................................................................................. 1

1.1 Available Field Test Data and Acknowledgments .............................................................. 2

1.2 Site Selection for BHP Field Test Area .............................................................................. 3

2 Geology ......................................................................................................................... 4

2.1 Deposit Geology and Mineralogy ....................................................................................... 4

2.2 Geologic Characterization of Field Test Area..................................................................... 5

2.2.1 Summary of Drilling Methods .................................................................................. 5

2.2.2 Downhole Geophysical Methods and Data Interpretation ...................................... 10

2.2.3 Geologic, Structural, and Mineralogy Logging Methods......................................... 11

2.2.4 Sampling and Analysis Methods ........................................................................... 13

2.3 Preparation of Geology Model for Field Test Area ........................................................... 13

2.3.1 Structure Compilation ............................................................................................ 13

2.3.2 Detailed Lithologic Model ...................................................................................... 14

2.3.3 Summary of the Field Test Area Geology .............................................................. 15

2.3.4 Mineral Resources of Field Test Area – 2010 Estimate ......................................... 15

2.4 Conclusions and Lessons Learned .................................................................................. 20

2.5 Recommendations for New Field Test ............................................................................. 20

2.5.1 Proposed Location of PTF and Associated Surface Disturbance........................... 20

2.5.2 Drilling Methods .................................................................................................... 21

2.5.3 Geology of Curis PTF ............................................................................................ 22

2.5.4 Logging, Sampling, and Assaying Protocols.......................................................... 25

3 Design of Test Facilities ............................................................................................ 26

3.1 Well Construction Design ................................................................................................ 27

3.1.1 Injection and Recovery Wells ................................................................................ 27

3.1.2 Chemical Monitoring Wells .................................................................................... 27

3.1.3 Observation Wells ................................................................................................. 28

3.1.4 Cementing Practices ............................................................................................. 28

3.1.5 Mechanical Integrity Tests ..................................................................................... 29

3.1.6 Wellhead Design ................................................................................................... 29

3.2 Test Facilities Design ...................................................................................................... 35

3.2.1 Tank Farm ............................................................................................................ 36

3.2.2 Piping and Surface Layout .................................................................................... 36

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3.2.3 Fluid Management and Filtration ........................................................................... 40

3.2.4 In-ground Environmental Monitoring Methods ....................................................... 41



4 Hydrologic Site Characterization .............................................................................. 45

4.1 Hydrogeological Characterization of the Deposit ............................................................. 45

4.1.1 Pump Tests ........................................................................................................... 46

4.1.2 Measurement of Anisotropy .................................................................................. 47

4.1.3 Well Capacity ........................................................................................................ 47

4.1.4 Hydrophysical Logging .......................................................................................... 47

4.1.5 Regional Flow and Transport Model ...................................................................... 49

4.2 Hydrogeological Characterization of Field Test ................................................................ 50

4.2.1 Field Measurements and Data Management ......................................................... 50

4.2.2 Pre-Leach Aquifer Pump Tests ............................................................................. 51

4.2.3 Groundwater Injection Tracer Test ........................................................................ 52

4.2.4 Numerical Modeling .............................................................................................. 54

4.2.5 Estimation of Porosity and Dispersivity .................................................................. 54

4.2.6 Evaluation of Hydraulic Control ............................................................................. 55

4.2.7 Sweep Efficiency Estimation ................................................................................. 56

4.2.8 Well Clogging Considerations ............................................................................... 56

4.2.9 Well Bromide Tracer Test Post-Leaching .............................................................. 57

4.2.10 Summary of Injection and Tracer Tests ................................................................. 59

4.2.11 Flow and Transport Modeling ................................................................................ 62

4.2.12 Hydraulic Containment Results ............................................................................. 66



4.4.1 Data Management................................................................................................. 68

5 Geochemical Characterization .................................................................................. 70

5.1 Summary of Metallurgical Test Work ............................................................................... 70

5.1.1 Summary of Previous Test Work ........................................................................... 70

5.1.2 Bottle Roll Tests .................................................................................................... 71

5.1.3 Large-Scale Column Tests .................................................................................... 73

5.1.4 Summary of Fracture Mineralogy Studies ............................................................. 77

5.2 Geochemical Modeling .................................................................................................... 78

5.2.1 Summary of Pre-test Geochemical Modeling ........................................................ 78

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5.2.2 Summary of Post-Leach Geochemical Modeling ................................................... 78

5.3 Conclusions ..................................................................................................................... 81

5.4 Basis of Design ............................................................................................................... 82

5.5 Recommendations........................................................................................................... 83

6 Operations Activities through Reclamation Phase ................................................. 84

6.1 Field Test Duration .......................................................................................................... 84

6.2 Field Test Operation Procedures ..................................................................................... 84

6.3 Manpower Requirements and Duties ............................................................................... 84

6.4 Evolution of the Water Quality in the Field Test through Rinsing Phase ........................... 85

6.4.1 Sulfate................................................................................................................... 86

6.4.2 pH ......................................................................................................................... 88

6.5 Copper Recovery and Mass Balance............................................................................... 91

6.6 Sulfate Recovery and Mass Balance ............................................................................... 94


6.8 Recommendations for the New Field Test ....................................................................... 96

7 Environmental and Safety Findings ......................................................................... 98

7.1 Environmental Issues during Operation of Field Test ....................................................... 98

7.2 Environmental Issues following the Test - Post-Rinsing Water Quality ............................ 98

7.3 Safety Issues ................................................................................................................... 98



8 References ................................................................................................................ 105

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List of Tables

Table 1-1 Current Florence Project in-situ mineral resources (SRK, 2010b) ................................ 2

Table 2-1 Summary of drilling method and downhole surveys ..................................................... 8

Table 2-2 Development schedule for 5-spot drillholes, July-November 1996 ............................... 9

Table 2-3 Drillhole assay statistics for the field test area ........................................................... 16

Table 2-4 Mineral resources in BHP field test area .................................................................... 16

Table 3-1 Summary of well construction details......................................................................... 34

Table 3-2 System problems and resolutions .............................................................................. 43

Table 4-1 Correlation of geologic and hydrogeologic units in the basin fill formations................ 46

Table 4-2 Hydraulic parameters of hydrogeological units .......................................................... 46

Table 4-3 Hydraulic conductivity and storativity from the oxide aquifer tests ............................. 51

Table 4-4 Duration of injection tests .......................................................................................... 60

Table 4-5 Average injection and pumping well rates during leaching phase .............................. 66

Table 5-1 Summary of test parameters for bottle roll tests ........................................................ 72

Table 5-2 Statistical summary of bottle roll tests ........................................................................ 73

Table 5-3 Summary of results from scoping phase columns, METCON .................................... 74

Table 5-4 Summary of results from Phase I column tests .......................................................... 75

Table 5-5 Summary of results from Phase II column tests, BHP San Manuel ............................ 76

Table 6-1 Field test shift schedules ........................................................................................... 85

Table 6-2 Mass of copper injected and recovered during leaching and rinsing phases.............. 92

Table 6-3 Mass of sulfate injected and recovered during leaching and rinsing phases .............. 95

Table 6-4 Timeline for leaching and reclamation activities ......................................................... 97

Table 7-1 Post-rinsing water quality results – All wells, 4th Quarter 2000 ................................ 100

Table 7-2 Post-rinsing water quality results – All wells, 2nd Quarter 2001 ............................... 101



Table 7-5 Post-rinsing water quality data – All wells, 2nd Quarter 2007 .................................. 104

List of Figures

Figure 1-1 Location map – Curis Resources Ltd. Florence Project .............................................. 1

Figure 2-1 Geology plan map at 700 ft elevation above mean sea level ....................................... 6

Figure 2-2 East-west geology cross section 744870N looking north ............................................. 7

Figure 2-3 North-south geology cross section 649500E looking east............................................ 7

Figure 2-4 Selected core photos of BHP-1 through BHP-4 ......................................................... 10

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Figure 2-5 Geology plan map through field test area; 700ft amsl ................................................ 17

Figure 2-6 N-S geology section 649370E through field test area looking east (L) and E-W section 744925N through field test area looking north (R) ..................................................... 18

Figure 2-8 Perspective views of the Tgdp dikes looking due W, -60 degrees (left) and S45°E, -75 degrees (right) ........................................................................................................... 19

Figure 2-9 Plan view of volume of rock within field test designated for resource calculation ....... 19

Figure 2-10 Proposed location of Curis PTF and associated disturbance ..................................... 23

Figure 2-11 Geology plan map of PTF, 900 ft amsl (upper); E-W geology profile 744600N looking north (left) and N-S geology profile 649250E looking east; (Tgdp is blue, Yqm is buff)24

Figure 3-1 Field test layout ......................................................................................................... 26

Figure 3-2 Well construction design – Injection and recovery wells ............................................ 31

Figure 3-3 Well construction design – Chemical monitor wells ................................................... 32

Figure 3-4 Discrete sampler for chemical monitoring wells ......................................................... 33

Figure 3-5 Wellhead infrastructure design .................................................................................. 35

Figure 3-6 Excavated pond, earth pile to northwest, tank farm, and wellfield to west .................. 37

Figure 3-7 Evaporation pond, floating dock, and boat for access to pond and sprayers.............. 38

Figure 3-8 Evaporation pond embankment, liner keyed into berm, and 8-foot anchor fence ....... 38

Figure 3-9 Senniger high-evaporation sprayers floating on 3-in welded HDPE piping. Yellow Jerry cans are for flotation support ............................................................................ 39

Figure 3-10 Ratio of San Manuel raffinate to injectate during field tests ....................................... 40

Figure 3-11 Annular resistivity in Kohms ...................................................................................... 42

Figure 4-1 Aquifer test locations in the deposit area ................................................................... 48

Figure 4-2 Horizontal anisotropic test at the P13 well cluster ...................................................... 48

Figure 4-3 Horizontal anisotropic test at the P19 well cluster ...................................................... 49

Figure 4-4 Percentage of permeable intervals as a function of threshold length ......................... 49

Figure 4-5 Electrical conductivity breakthrough curves during groundwater injection test ........... 52

Figure 4-6 Sulfate breakthrough curves during the groundwater injection test ............................ 53

Figure 4-7 Diagonal NW-SE section (looking southwest) showing screened intervals in undifferentiated bedrock and the faults between BHP-1 and BHP-2 .......................... 53

Figure 4-8 Hydraulic conductivity zones within the oxide bedrock in the 5-spot .......................... 54

Figure 4-9 Simulated vertical concentration profile between injection wells BHP-6 and BHP-8 ... 56

Figure 4-10 Relative Br concentration vs. time curves (BHP, 1999).............................................. 58

Figure 4-11 Diagram representation of Br percentage reaching pumping wells ............................ 59

Figure 4-12 Contoured percentage of sulfate mass recovered during pre-leach groundwater injection test (3/12/1997). BHP-1 is the injection well. .............................................. 61

Figure 4-13 Contoured percentage of sulfate mass recovered during raffinate injection and rinsing phase (10/31/1998 to 5/12/1998). BHP-6 through BHP-9 are injection wells. ........... 61

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Figure 4-14 Contoured percentage of bromide recovered by well during bromide tracer test (5/13/1998 to 7/17/1998) ........................................................................................... 62

Figure 4-15 Field drawdown curves and the calibrated drawdown curves .................................... 64

Figure 4-16 Relative concentrations seen in sulfate field data and calibration results ................... 65

Figure 4-17 Simulated (magenta) and measured (dark blue) bromide concentrations in BHP-6, BHP-7, BHP-8, and BHP-9 ........................................................................................ 65

Figure 4-18 Net positive pumping rate in the wellfield (BHP, 1999) .............................................. 67

Figure 4-19 Potentiometric map for February 2, 1998 (contours in ft amsl)................................... 67

Figure 5-1 Copper recovery curves for column tests .................................................................. 77

Figure 5-2 Copper recovery curves of the long-term forecast model........................................... 80

Figure 5-3 Copper and pH curves from long-term forecast model. Case A production shown as solid lines, Case B shown as dashed. ....................................................................... 81

Figure 6-1 Planar view showing field test layout and location of the wells in mine coordinates (ft)87

Figure 6-2 Planar view showing SO4 (mg/L) concentration near the start of raffinate injection on November 7, 1997 (left) and end on February 1, 1998 (right) .................................... 87

Figure 6-3 Planar view showing SO4 (mg/L) concentration at the end of pond water injection on March 21, 1998 (left) and the end of groundwater injection on May 14, 1998 ............ 88

Figure 6-4 Planar view showing pH (su) on October 31, 1997 (left) and November 3, 1997 (right)89

Figure 6-5 Vertical E-W profile from BHP12 though BHP10 looking north showing pH on November 7, 1997 (left) and at the end of the raffinate injection phase (February 8, 1998) ......................................................................................................................... 90

Figure 6-6 Vertical E-W profile from BHP-12 though BHP-10 looking north showing pH on March 21, 1998 (left) at the end of pond water injection and at the end of the groundwater injection phase (May 14, 1998). ................................................................................. 91

Figure 6-7 Daily and cumulative injection and extraction – Net copper (lbs) recovery vs. time through May 11, 1998 ............................................................................................... 93

Figure 6-8 Daily and cumulative injection and extraction – Net copper (lbs) recovery vs. time through May 12, 1999 ............................................................................................... 94

Figure 6-9 Mass injection and extraction - Net sulfate recovery vs. time through May 12, 1999 . 96

Appendices

Appendix A: Wellfield Extraction Graphs

Appendix B: Water Quality Graphs

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SRK Consulting Summary of BHP Field Test and Updated Work Page 1


1 Introduction The Florence Project hosts a shallowly buried porphyry copper deposit located in Pinal County,

Arizona near the town of Florence (Figure 1-1). The deposit contains a Measured + Indicated

mineral resource of oxide material in bedrock of 429.5 million tons grading 0.331 percent total copper (%TCu) for a contained 2.84 billion pounds copper (Table 1-1, SRK, 2010). The deposit was

discovered in 1969, and underwent extensive exploration drilling and evaluation for development

during the 1970s by Continental Oil Company (Conoco). During the 1990s, the project was acquired by Magma Copper Company, which was then acquired by BHP Copper Inc. (BHP Copper or BHP)

in 1996. The project was taken to a pre-feasibility-study level by BHP as a proposed in-situ copper

solution recovery (ISCR) operation. Curis Resources (Arizona) Inc. (Curis), a wholly owned subsidiary of Curis Resources Ltd., acquired a 100 percent interest in the project on February 24,

2010, and seeks to reactivate the project toward eventual ISCR copper production.

Curis requested that SRK review the results of the BHP field test performed from October 31, 1997

through February 8, 1998. The field injection and recovery test was prematurely concluded after 101 days, so a full recovery curve for copper extraction was not developed. The raffinate injection

(leaching) phase of the field test was preceded by a pump interference test and groundwater injection

test with M10-GU water. The raffinate injection phase was followed by a bromide tracer test using WW-4 groundwater, and finally a rinsing and reclamation pumping phase. The intent of this report

is to summarize the results, findings, and “lessons learned” with the goal that this information may

be relevant to the operation of a future planned ISCR test.

Figure 1-1 Location map – Curis Resources Ltd. Florence Project

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Table 1-1 Current Florence Project in-situ mineral resources (SRK, 2010b)

All Oxide in Bedrock at 0.05% TCu cutoff

Class Mtons %TCu Grade MLbs Cu

Measured 296.395 0.354 2,100

Indicated 133.091 0.278 741

M+I 429.486 0.331 2,841

Inferred 92.752 0.267 496

Note: All oxide includes the copper oxide zone and iron-oxide leached cap zone including the bedrock exclusion zone. Contained metal

values assume 100% metallurgical recoveries.

1.1 Available Field Test Data and Acknowledgments

SRK has compiled a significant amount of the available technical reports and historic field data related to the BHP field test. The hard copy geology drill logs, downhole geophysical data, well

construction records, and other data were scanned as was the environmental management of the

facility including the daily/week inspections. Curis scanned the 35-mm photos of the drill core

boxes and provided copies of backups from the BHP computer files. BHP field test records were stored in a Microsoft Access database and supplementary Excel spreadsheets; the water quality and

flow data were then consolidated by SRK into a unified database. SRK prepared a 3-dimensional

(3-D) geology and structural model for the field test area using the BHP drillhole data. Animations were prepared to understand the spatial and temporal water quality changes during the leaching and

rinsing phases.

Some field test records such as a schematic drawing of the test facilities and as-built drawings for the tank farm, evaporation pond, and wellfield are not currently available. The manuals for operation of

the facility are available in hard copy format but were not scanned or transcribed for this effort.

Hard copy records for field measurements (water level, chemistry) and analytical laboratory reports

do exist but were not scanned. Data logger records do exist digitally but were not extracted from the BHP backups. The computer programs that controlled the wellfield operations are available but

have not been reviewed for effectiveness or updates that may be needed.

A number of reports by BHP and their consultants were scanned including internal reports and memoranda, two University of Arizona theses, the results of metallurgical tests, and results from

downhole aquifer tests. BHP summarized their field tests and simulations in two documents – the

1997 Final-Prefeasibility Report (BHP, 1997a, b, c, d), and the 1999 Field Test – Goals, Results, and Conclusions (draft dated October 1999). The 1999 report was never finalized but does contain

extensive geochemical and hydrological summaries, some of which were incorporated into the

current report. The major contributors to the two BHP reports were:

Corolla Hoag and Jacqueline Seguin, Geology and Mineral Resources,

Dr. Guoliang Chen, Dr. Shlomo Orr, and Damaris Chong-Diaz, Hydrology and Wellfield

Design;

Dr. Richard Beane and Richard Preece, Geochemistry and Mineralogy; and

John Kline, Environmental and Legal, Plant Design, Processing, and Economic Model.

Contributors to the summary presented herein include:

Corolla Hoag, Geology and Mineral Resources, Operations,

Daniel Russin, Geology Model, Geology Sections,

Michael Sieber, Vladimir Ugorets, and Matt Hartmann, Hydrogeology,

Dr. Terry McNulty, Metallurgy; and

SWVP-026362



John Kline, Operations and Recovery Summary.

1.2 Site Selection for BHP Field Test Area

The process to select the location of the BHP field test area included a careful review of a number of physical characteristics including the deposit geology and structure, surface features, and proximity

to existing and future infrastructures. The intent was to install the wellfield in an area with

representative bedrock and oxide mineralization containing an average total copper (TCu) grade based on the BHP geology and resource model completed in 1997. BHP elected to avoid the

complexities imposed by siting the field test above the underground workings, in a major fault zone,

or on Arizona State Mineral Lease land. No disturbance to the North Canal was allowed.

The selected site was conveniently located near an existing water well (WW-4) and nearby electrical lines. It was inconveniently located south of a large, producing irrigation well (BIA-10B) that was

not controlled by BHP and that would cycle on at 1,500 gpm with no notice. The chosen site was

west of the area planned for construction of the future evaporation ponds and would have been integrated into future ISR operations had the project been continued. The 7 acre pond that was

constructed to support the field test was moved north relative to the location specified in the

preliminary engineering designs to avoid disturbing Hohokam cultural features.

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2 Geology The sections below provide an overview of the deposit geology (Section 2.1), drilling methods and

downhole geophysical tools used within the BHP field test area (Sections 2.2.1 and 2.2.2), the

geology logging, sampling, and assaying methods (Sections 2.2.3 and 2.2.4), and the preparation of a geology model and resource estimate in 2010 for the field test (Section 2.3). Conclusions and

recommendations related to the proposed Curis Production Test Facility (PTF) are found in Sections

2.4 and 2.5.

2.1 Deposit Geology and Mineralogy

The Florence porphyry copper deposit formed when numerous Laramide-age dike swarms of

granodiorite porphyry intruded Proterozoic quartz monzonite near Poston Butte (see geologic plan

map in Figure 2-1 and cross sections in Figure 2-2 and Figure 2-3). The dike swarm strikes E-W to

N75-80ºE and dips steeply to the south. The dike swarms may have been fed by a larger intrusive mass at depth that has not been identified to date. Hydrothermal solutions associated with the

intrusive dikes altered the host rock and deposited copper and iron sulfide minerals in disseminations

and thin quartz-sulfide veinlets. Hydrothermal alteration and copper mineralization were most intense along the edges and flanks of the dike swarms and intrusive mass.

The region was later faulted and much of the Florence deposit was isolated as a horst block. This

horst block, as well as the downthrown fault blocks to the west, was exposed to weathering, intense fracturing, and erosion. The center of the deposit was eventually eroded to a gently undulating

topographic surface while a deep basin formed to the west.

Fluctuations occurred in the water table level over time, and the rock was exposed to oxygen. The

iron and copper sulfide minerals were naturally dissolved by naturally formed acids and were remobilized along fractures and redeposited, generally at a lower elevation. The copper sulfide

minerals in the oxidized zone above the water table were converted to copper silicates and copper

oxides, such as chrysocolla and tenorite. Enriched supergene copper minerals such as chalcocite, minor native copper and cuprite are present at a thin, partially oxidized transitional zone above the

top of the sulfide zone. A majority of the copper oxide mineralization is located along fracture

surfaces, but chrysocolla and copper-bearing clay minerals also replace clay-altered feldspar crystals located within the granodiorite porphyry and quartz monzonite. A barren or low-grade zone,

dominated by iron/manganese oxides and clay minerals, caps some portions of the top of bedrock

especially in the western portion of the deposit above the Sidewinder fault. The thickness of the

oxide mineralized zone ranges from 100 to 1,200 feet, with an average thickness of around 400 feet.

The bedrock units have been covered by an average of 350 feet of Tertiary-Quaternary gravels, fines,

and alluvium. These overburden units are flat lying and rest unconformably on the erosion surfaces.

The Whitetail Conglomerate overlies the porphyry deposit in the deep graben to the west. The Whitetail is described as a poorly to moderately indurated, poorly sorted conglomerate composed of

angular and sub-angular igneous pebbles in a brown arkosic matrix (Nason and others, 1983).

Overlying the Whitetail Conglomerate is a poorly indurated, poorly sorted terrestrial deposit

consisting of pebbles and cobbles and commonly, volcanic clasts and basalt flows. This formation may be correlative with the Gila Conglomerate some 30 miles east of Florence. Within the

conglomerate is a flat-lying, aerially extensive clay layer with a palynological age of Pliocene. The

layer is typically 20 to 30 feet thick and occurs 60 to 70 feet above the present bedrock surface. Aquifer testing has demonstrated that this clay layer acts as an aquitard between the bedrock aquifer

below and the overburden aquifer above. Photos of drill core examples of the rock and

mineralization types are shown in Figure 2-4.

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2.2 Geologic Characterization of Field Test Area

The sections below provide a summary of the methods used by BHP to characterize the field test

area prior to the leaching phase. SRK reviewed the available data and prepared cross sections and a detailed three-dimensional digital model to provide the framework to understand the results of

aquifer tests and the ISR results.

2.2.1 Summary of Drilling Methods

The 26 holes in and near the leach test area were drilled by more than one contractor using a

combination of mud rotary, diamond drill core, and reverse circulation (RC) as described in Table

2-1. The mud rotary drilling was performed by Stewart Brothers Drilling of Milan, New Mexico. The core and some RC drilling were performed by Boyles Brothers/Layne Christensen of Chandler,

Arizona. The majority of the RC drilling was performed by Lang Exploratory Drilling of Salt Lake

City. All the historic Conoco and Magma holes in the vicinity are diamond core (cored from a few feet above bedrock), as are BHP-1 through BHP-5. All BHP holes were drilled using mud rotary

methods through the basin-fill units until they reached 40 feet below the top of bedrock. The

remaining holes (BHP-6 through BHP-13) were drilled with reverse circulation methods in bedrock,

with the exception of limited intervals where mud rotary was required to ensure borehole stability. Chemical monitor wells CH-1 and CH-2 were drilled by rotary methods.

Mud rotary methods were avoided in the bedrock portion of the injection and recovery wells to

ensure that the fractures did not become plugged with bentonite and other fine-grained mineral residues. The borehole development techniques remove most, but not all, of the mud cake on the

borehole wall. Fine-grain residual mud was viewed to have the potential to reduce the formation

permeability if not completely removed. In addition, the rotary samples were not viewed to be

reliable samples for assaying.

The borehole diameters allowed the recovery of NX/NQ or HX/HQ-diameter core with the exception

of BHP-2, which is a 6-in diameter hole. The diamond drill portions of the NX and HX holes were

later reamed using RC methods to allow well installation. Well development washed any residual drilling fluids from the well. Practice and a good touch was needed during well development phase

to avoid formation damage as was experienced in BHP-1; the heavily fractured bedrock produced a

hole approximately 3-ft in diameter during the swabbing and development of the hole to remove drilling fluids.

The time to drill and install the first five wells (BHP-1 through BHP-5) was 128 days including

drilling, reaming, well installation, and integrity testing. Three drill rigs operating in tight space

requirements were used initially thereafter decreasing to one rig at the conclusion of well development. The drilling schedule was on a 24-hr, continuous schedule. Rotary drilling and well

installation, and cementing in the basin-fill and top 40 ft of bedrock took approximately 8 days per

well; RC drilling and well installation took approximately 6 days. A detailed description of drilling and installation of the 5-spot is presented in Table 2-2.

SWVP-026365



Figure 2-1 Geology plan map at 700 ft elevation above mean sea level

SWVP-026366



Figure 2-2 East-west geology cross section 744870N looking north

Figure 2-3 North-south geology cross section 649500E looking east

SWVP-026367



Table 2-1 Summary of drilling method and downhole surveys

Drill hole Date drilled Depth (ft.)

Drill type Downhole surveys Other surveys

BHP-1 Magma 1996 830 Rotary 0-340'; HX Core

340-830'

Sperry Sun Dips and

Azimuths

Gamma Ray-Neutron,

Cement Bond, Televiewer

BHP-1 BHP 1997 830 RC/Ream Sperry Sun and Est. Dips and Azimuths

BHP-2 Magma 1996 894 Rotary 0-345'; 6" Core

345-496'; NX Core 496-894'

Sperry Sun Dips and

Azimuths

Gamma Ray-Neutron,

Sonic-VDL, Televiewer

BHP-2 BHP 1997 894 RC/Ream None HydroPhysical Log

BHP-3 Magma 1996 872.5 Rotary 0-340'; HX Core

340-872.5'

Sperry Sun Dips and

Azimuths

Gamma Ray-Neutron,

Sonic-VDL, Televiewer

BHP-3 BHP 1997 872.5 RC/Ream None HydroPhysical Log

BHP-4 Magma 1996 834 Rotary 0-430'; HX Core 430-834'

Sperry Sun Dips and Azimuths

Gamma Ray-Neutron, Sonic-VDL, Televiewer

BHP-4 BHP 1997 834 RC/Ream None HydroPhysical Log

BHP-5 BHP 1997 798 Rotary 0-403'; RC 403-798'

None Cement Bond Log, Colog HydroPhysical

Log

BHP-6 BHP 1997 820 Rotary 0-415'; RC 415-820'

Totco and Est. Dips; Sperry Sun and Est.

Azimuths

Gamma Ray-Neutron

BHP-7 BHP 1997 810 Rotary 0-415'; RC 415-810'


Azimuths

Gamma Ray-Neutron

BHP-8 BHP 1997 790 Rotary 0-415'; RC 415-790'


Azimuths

Gamma Ray-Neutron

BHP-9 BHP 1997 850 Rotary 0-415'; RC 415-850'


Azimuths

Gamma Ray-Neutron

BHP-10 BHP 1997 840 Rotary 0-406'; RC 680-

840'

Totco and Est. Dips;

Est. Azimuths

Gamma Ray-Neutron

BHP-11 BHP 1997 805 Rotary 0-405'; RC 405-805'

Welenco to TD Gamma Ray-Neutron

BHP-12 BHP 1997 770 Rotary 0-405; RC 405-770'


BHP-13 BHP 1997 840 Rotary 0-405; RC 405-

840'


CH1 BHP 1997 789 Rotary Welenco to TD Gamma Ray-Neutron

CH2 BHP 1997 775 Rotary Welenco to TD Gamma Ray-Neutron

OWB1 BHP 1997 830 Rotary 0-425'; 760-830'

RC 425-760'


OWB2 BHP 1997 225 Rotary Totco Dips; Est. Azim. None

OWB3 BHP 1997 820 Rotary 0-425', RC 425-820'

Totco and Est. Dips; Est. Azim.

Gamma Ray-Neutron

OWB4 BHP 1997 755 Rotary 0-415'; RC 415-755'

Totco and Est. Dips; Est. Azim.

Gamma Ray-Neutron

OWB5 BHP 1997 765 Rotary 0-425'; RC 425-

765'

Totco, SureShot, Est

Dips; Sperry Sun and Est. Azim.

Gamma Ray-Neutron

OWB6 BHP 1997 925 Rotary 0-425'; RC 425-925'

Totco Dips; SureShot and Est. Azim.

Gamma Ray-Neutron

MCC427 Magma1993 Rotary 0-366'; NX Core

366-833

Welenco to TD Gamma Ray-Neutron,

Sonic-VDL, Televiewer, HydroPhysical Log

MCC524 Magma 1993 1034 Rotary 0-320'; NX Core

320-1024'

Estimated Dips and

Azimuths

None

MCC524 BHP 1997 410 Rotary 0-410 None Screened 320-340'

MCC534 Magma1994 900 Rotary 0-260'; 6" Core 260-900'

Welenco to TD `

Source: BHP, 1997a

SWVP-026368



Table 2-2 Development schedule for 5-spot drillholes, July-November 1996

From To Days Well ID

Notes

8-Jul 10-Jul 2 BHP3 Mud rotary (5 7/8 inches) to a total depth of 340 feet. Install 4 in. steel casing

10-Jul 12-Jul 2 BHP2 Mud rotary (9 7/8 inches) to a total depth of 345 f.

10-Jul 16-Jul 6 BHP3 Drill HX core to a total depth of 872.5 feet

12-Jul 16-Jul 4 BHP2 Open hole to 12 ¼ inches to a total depth of 345 ft. Install 8-in steel casing

17-Jul 19-Jul 2 BHP4 Mud rotary (5 7/8 inches) to a total depth of 340 ft. Install 4-in steel casing

22-Jul 24-Jul 2 BHP1 Mud rotary (5 7/8 inches) to a total depth of 340 feet. Install 4-in steel casing

23-Jul 27-Jul 4 BHP4 Drill HX core to a total depth of 834 ft

25-Jul 2-Aug 7 BHP2 Drill 6 inch core to a total depth of 496 ft

28-Jul 1-Aug 3 BHP1 Drill HX core to a total depth of 830 ft

6-Aug 7-Aug 1 Pulled 4-in steel casing from BHP1, BHP3, and BHP 4 then installed casing in BHP2

8-Aug 20-Aug 12 BHP2 Drill HX core to a total depth of 894 ft.

13-Aug 15-Aug 2 Schramm standing by

16-Aug 19-Aug 3 Install 21 ft of conductor casing in BHP1, BHP3, BHP4 and BHP5

20-Aug 21-Aug 1 Schramm standing by

27-Aug 28-Aug 1 BHP4 Reaming hole to 12 inches. Stopped at 380 ft

28-Aug 31-Aug 3 BHP2 COLOG conducting hydrophysical tests

29-Aug 30-Aug 1 Stand by and pull 8-inch casing from BHP2

4-Sep 10-Sep 6 BHP4 Finishing reaming hole to a total depth of 403 feet. Cement 8 inch PVC.

11-Sep 12-Sep 1 BHP3 Install 21 ft conductor casing and ream 12-in hole to 408 ft

12-Sep 16-Sep 4 BHP3 Ream 12-in hole to 403 ft.

17-Sep 19-Sep 2 BHP1 Ream 12-in hole to 403 ft.

19-Sep 24-Sep 5 BHP2 Install and cement 8 inch PVC annulus, wash out weighted mud

23-Sep 1-Oct 8 BHP5 Mud rotary to 403 ft then install and cement 8-in PVC

1-Oct 4-Oct 3 BHP3 Install 8-in PVC and cement annulus

4-Oct 8-Oct 4 BHP1 Install 8-in PVC and cement annulus

8-Oct 10-Oct 2 Tremie all 5 holes. Convert rig to reverse circulation set-up

14-Oct 22-Oct 8 BHP1 Attempted to install 4-in PVC to 830 ft, not possible so moved rig

22-Oct 28-Oct 6 BHP5 Installed 4-in PVC to 776 ft

28-Oct 1-Nov 3 BHP4 Install 4-in PVC to 742 ft

2-Nov 8-Nov 6 BHP1 Install 1 ½ inch PVC through RC rods to 720 ft

19-Nov 23-Nov 4 BHP3 Install 1 ½ inch PVC through RC rods to 860 ft

23-Nov 26-Nov 3 BHP2 Install 4 inch PVC to 770 ft. Drillers finished.

27-Nov 30-Nov 3 Develop wells: pour pads, install pumps, purge wells, install 4 by 6 adapters

29-Nov 3-Dec 4 COLOG conducting hydrophysical tests on BHP5, BHP4, then BHP2

Total Days

128

Source: BHP drill geology log files

SWVP-026369



Notes: BHP-1 Chrysocolla mineralization in fractured monzonite (Yqm), 0.44 %TCu, 0.40 %ASCu, Metzone=2 (Mixed), FRACI=5 (>15

fx/ft), Scale in cm and in units is at top of core box.

BHP-2 Contact of Lower cemented conglomerate overlying the Yqm, 6-in core; one half of the 5-ft long core box is shown.

BHP-3 Tgdp dike in contact w. Yqm. Chrysocolla mineralization is concentrated in the Tgdp in this interval. No core recovery in 4-ft

interval from 510-514’; 0.50%TCu, 0.35%TCu;

BHP-4 Low-grade, iron-stained Yqm, 0.11 %TCu, 0.03 %ASCu, Metzone=2, FRACI=2 (6-10 fx/ft)

Figure 2-4 Selected core photos of BHP-1 through BHP-4

2.2.2 Downhole Geophysical Methods and Data Interpretation

Several downhole geophysical techniques were used by Magma during exploration drilling program; the geophysical surveying services were provided by Welenco (now Southwest Geophysical) of

Gilbert, Arizona. BHP ranked the data acquired from each type of downhole survey according its

usefulness in understanding the character of the rocks in the field test area or necessity in supporting

the well construction activities. The downhole survey tools ultimately used for the field test drilling program included:

Caliper – measures borehole diameter and indicates where washout zones occur;

Cement bond log – sonic tool that detects the bond of cement to the casing and formation;

Gamma ray-neutron – measures the naturally occurring gamma radiation of the borehole wall. It

helped to identify or confirm the contracts for the clay unit, which contains potassium isotopes,

and the top of bedrock; and

Acoustic borehole televiewer (BHTV) – a sonic tool that generates an acoustic image of the

borehole wall, from which the dip angle and azimuths of structures can be measured

The gamma-neutron logs were essential in confirming the geologic contacts especially in the basin-fill formations where cuttings were all that was available to delineate the geologic contacts. The

BHTV was used to correlate structures between drillholes, as detailed in Section 2.3.1 below. Other

SWVP-026370



tested methods (gamma ray, spectral gamma ray, sonic/variable density log, spinner surveys,

induction, and heat pulse) did not add sufficient value to warrant continued use.

2.2.3 Geologic, Structural, and Mineralogy Logging Methods

The detail of logging for rock types, structure, and mineralogy varied according to drilling method as described below. Costs for the field test program are provided where documentation was available.

Rotary

Rotary drilling was performed by Stewart Brothers and cost $55/ft for 14-in surface borings and $26.50/ft for 10 5/8-in diameter boreholes. The average cost per foot including materials (mud,

surface casing, PVC) was $59.60. Mud rotary drilling uses a fairly viscous fluid (primarily bentonite

and water), injected through the drill pipe, to circulate cuttings out of the drill hole. The drill method helped keep the boreholes open in the basin-fill formations (and in washout zones in bedrock).

Several biases occurred as cuttings and mud travel up the drill hole between the string of drill pipe

and the wall of the drill hole. These included:

Overlap of material from adjacent samples caused by incomplete removal of the sample,

Contamination caused by caving or tear out of the borehole wall,

Concentration of coarse-size particles in the sample collection trough and fines in the

recirculation pit or tank,

Travel lag time in deep holes (minor problem in holes less than 1,500 feet), and

Cutting size bias when sieving/washing the sample prior to logging (fines washed through the

sieve).

For all these reasons, the rotary holes were sampled and logged at Florence but were not assayed. Logging of the rotary portion of the holes consisted of noting color, grain size, rounding/angularity,

the dominant grain composition, and the percentages of silt, sand, and gravel in the samples of the

basin-fill formations. A kitchen sieve and bucket of water were typically used, which allowed everything finer than the ~1mm sieve opening to be washed away. This was not a problem when

drilling in bedrock as the fines usually have the same constituents as the coarse material. When

drilling sediment, however, the fines provide information about the conglomerate matrix or overall composition (silt, clay unit) and may be distinct from the clast composition.

It was not possible or practical to correct some or all of these biases, so the most efficient method of

logging was to note them, and try to use other observations to infer the scale of the bias. Lithology

changes were noted based on new rock types seen in the sample rather than waiting for cuttings from the previous unit to disappear, as contamination could mask lithology changes for several tens of

feet.

Another useful observation was to look at the color and consistency of the sample before it was washed, in order to estimate silt and clay content. Silty formations tended to make the bentonite

mud (i.e. drilling fluid) very brown and opaque, whereas clean bentonite mud is a very pale tan color

and slightly translucent. Cuttings from the Clay unit (also known as the middle fine-grained unit) or more clay-rich intervals tended to ball up and behave like larger clasts. Even if there is a gross

sampling bias, the presence of the Clay unit may be noted from plastic balls of clay showing up in

the sample.

Structural measurements were a challenge in the basin-fill formations and bedrock owing to lack of detail seen in rotary chips, but the geologists did detect the presence of post-deposit faults seen in

bedrock within the top 40 feet of bedrock and the basin-fill formations immediately overlying the top

of the eroded bedrock. Faults in bedrock were detected in cuttings by the sudden appearance of clay (typically red colored) or dominance of clay in an interval well below the Clay unit with possible

changes in drill speed.

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Diamond Drill Core

Diamond drill core was intended to be used in the bedrock in BHP-1 through BHP-5 for what was envisioned to be the original injection/recovery 5-spot cell. Ultimately, HX core was drilled in BHP-

1, BHP-3, and BHP-4; 6-in core was drilled in BHP-2. Significantly greater detail could be gained with diamond drill core but the downsides included significantly higher cost per foot and lower

drilling speed. The average cost per ft was $33.50.

After cleaning the core drilled for the BHP field test, the core was photographed using a 35mm

camera attached to a photography stand at a set distance above the core box. Note for the future…make sure the photographer has good eyesight and can focus the camera! After slide

development, some sets of photos were discovered to be out of focus, but the core had already been

cut/split and sent for assaying. Out-of-focus slides should not be such a problem with the instant feedback provided by a digital camera. Footages were marked with permanent marker pens in 1-foot

increments on the drill core to tally overall core recovery in each interval and to assess the exact

location of any core lost. The marked intervals then were used as standard footages geology and

geotechnical logging, fracture logging, sampling, and assaying purposes.

All holes were logged for rock type, mineral percentages, fracture intensity, and metallurgical zone

in accordance with the standard procedures used previously (BHP, 1997a; Section 3.5) and following

coding conventions previously developed by Conoco. Rigorous structural logging occurred including recording percent recovery, rock quality designation (RQD), and depth below surface of

fractures and faults. Goniometers and protractors were used to measure dip angles in NX, HX, and

six-inch core. Dip angles were measured parallel to the core axis and then subtracted from 90° to convert them to dip angles perpendicular to the core axis (true dip). No adjustments were made for

the 0.5 to 2.0 degrees of downhole deviation. The data were recorded on hard copy, entered into

Excel, checked by a second person, and then ultimately imported into the MineSight drillhole

database.

Data collected for the fracture mineralogy studies included the depth of the fracture, the fracture

angle measured parallel to the core axis, and mineral coatings. The mineral coatings in the fracture

mineralogy study included the following minerals: hematite, goethite, jarosite, calcite, chlorite, biotite, chalcopyrite, pyrite, gypsum, clay, Cu-clay, chrysocolla, and tenorite. The minerals were

entered as abundances relative to each other as there was no reliable way to estimate actual

percentages. The fracture data were then entered into a spreadsheet, and a hard copy filed in the appropriate geological log. Plots and graphs were prepared showing the vertical distribution and

intensity of various mineral assemblages in the drillhole and the correlation of various mineralogy

assemblages to fracture dips (sorted into 5-degree and 10-degree bins). The elevation of the

fractures above sea level was calculated by subtracting the footage (depth below surface) from the measured or estimated elevation of ground surface next to the well. The mineralogy depth and dip

angle data was later correlated to the fracture azimuth and dip data set digitized from the acoustic

borehole televiewer output.

Reverse Circulation

RC drilling methods were used to drill injection wells BHP-6 through BHP-8 and a number of the

other recovery and observation wells. The cost for RC drilling by Lang Exploratory Drilling of a 6 ¼-inch diameter borehole was an average of $23.60/ft with a maximum of $30.65/ft. Because this

drill method uses compressed air to lift the sample and any fluids out of the hole, often at greater

speeds than with conventional mud rotary drilling, there is less likelihood of segregation errors at the sample collection stage. Contamination is less than with mud rotary because the sample does not

come in contact with the walls of the drill hole as it travels to the surface. Local contamination from

one sample to the next (i.e. “smearing”) can also be considerable, but depends almost entirely on the

diligence of the driller in clearing all of a sample before drilling the next interval. Large amounts of

SWVP-026372



ground water (>50 gpm), and also the fairly light viscosity mud used in RC drilling tend to amplify

these inaccuracies.

The samples collected from RC drilling were judged to be of good quality for sampling and assaying

purposes but less detailed data were generated. Drilling difficulties associated with RC methods

included greater downhole deviation from vertical and a few significant hole washouts that required switching to mud rotary methods for short intervals.

2.2.4 Sampling and Analysis Methods

Sample intervals in RC drill holes adhered to a 10-foot sample interval. Sample intervals in core holes were 10 ft in length for continuous stretches of uniform rock type. The sample lengths of

selected core intervals could vary from 1 to 11 feet in length based on changes in rock type or

position with respect to model bench elevations. The goal was to ensure that one rock type was coded per assay interval for ease of statistical calculations (rock type, grade, fracture intensity, and

Metzone). A 1-ft interval, for example would only have been delineated if a significant change in

rock type to a thin andesite or diabase dike was encountered; the andesite or diabase would not have

been composited with Tgdp or monzonite.

Additionally, the site geologists knew that after logging and assaying were completed, the 10-ft

assay intervals would be composited into 50-ft bench composites that matched the bench toes/crests

in elevation above mean sea level (amsl). Shorter or longer core intervals would be generated so that the sample intervals in the near vertical holes would match the 10-ft increments that would fall

within the 50-foot bench height elevations (amsl).

Actlabs-Skyline (now Skyline Assayers and Laboratories) of Tucson was the sole laboratory for analyzing the RC chips and diamond drill core. A hydraulic splitter and diamond-blade saw were

used to divide the core samples into equal portions – one of which was sent to the lab. The core

samples were bagged and tagged by on-site technicians. Splits (A and B) from the same interval

were taken on every 20th sample. Pulps of known site-specific standards at seven grade ranges were prepared in pulp envelopes and inserted into the sampling stream for both core and RC samples. The

pulps were weighed before and after shipment to ensure the sample was actually assayed by Skyline.

Samples were analyzed for %TCu and %ASCu using a standard method. The site geologists reviewed the results against what was seen in the core and compared the QA/QC results against the

list of acceptable deviations for each standard. If there were no QA/QC problems, the assay results

were posted to the drill log; QA/QC problems were infrequent and quickly resolved with Skyline.

2.3 Preparation of Geology Model for Field Test Area

BHP was in process of preparing geology cross sections and a digital geology model using MineSight software when the staff was laid off, so the post-drilling model was never finalized.

Using the geologic logs for the 19 leach test holes and 7 nearby Conoco and Magma exploration

drillholes, SRK generated a 3-D model of the subsurface geology of the BHP field test area. MineSight software was used for the 3-D geology modeling; Vulcan software was used to prepare

the updated resource estimate.

2.3.1 Structure Compilation

The only opportunity to inspect and map the structures visually at Florence was provided during the

development of the Conoco underground pilot mine. Geologic mapping performed by Conoco

during the operation of their pilot mine gives a more complete picture of the structural fabric of the rock than vertical drillholes are able to provide. BHP reviewed the Conoco maps and divided the

faults observed in the pilot mine into groupings based on their strike and dip directions (Maher,

1999). This study showed that E-NE striking faults with steep dips are the most common orientations recorded in the pilot underground mine while the N-NW striking faults were the most

SWVP-026373



common structures delineated in the Magma and BHP deposit-scale geology models. Because all

drilling conducted in the Florence deposit is vertical, steep structures such as the ones physically measured in the Conoco pilot mine will be under-represented in drill core. Maher speculated that

one or more structures with this orientation may have influenced the hydraulic connection between

wells in the field test – especially between the injection wells and BHP-5.

Borehole televiewer logs were available for four of the field test boreholes (BHP-1, BHP-2, BHP-3,

and BHP-4). The televiewer logs provide an acoustic image of the borehole wall that highlights

zones of fractured rock as well as the aperture width and orientation of individual fractures and faults. The fractures and faults were digitized by BHP technicians using software provided by

Welenco. The digitized output includes the downhole depth of each digitized feature, the sinusoidal

trace of the feature, and the dip angle and dip azimuth of each digitized joint or fault. The technician

did the on-screen digitizing at the same time the core was being logged so had good opportunity to “ground truth” the digitized features.

There was good correlation in the downhole depths of fractures measured in drill core versus the

depths measured by televiewer with the exception of core loss zones where an assumption had to be made by the geologist on the actual depth of core loss. Dip angles measured in drill core were

typically within 2 degrees of the angles in the digitized fracture. The digital data set of acoustic

borehole televiewer fractures was correlated to the Excel spreadsheets of depths, dip angles, and

fracture mineralogy recorded in drill core. This was done to assess if copper oxide mineralization as recorded as fracture mineralogy had a preferred dip orientation in 5-degree, 10-degree, and 20-

degree bins. Copper oxide mineralization was recorded on fractures dipping in all directions but the

mode was in a westerly direction – reflecting the importance of Basin and Range structures in remobilizing the copper. The digitized measurements were also correlated with the geologists’ log

to provide actual azimuth and dip orientations to significant fault and fracture zones.

SRK reviewed the output from the acoustic borehole data and compared the measurements to those recorded in the geology logs to identify the possible presence of clay-rich fault gouge zones that

could serve as a barrier to solution flow. Alternatively, broken rock contacts or fault breccia zones

could have acted as high-conductivity pathways. A compilation was made of the structural

orientations of significant fault breccia and clay-rich zones, which were brought into MineSight to see if these structures could be correlated between drillholes.

The large number and variability of the measured structures with actual dip azimuths and dip angles

made correlation difficult. In many cases, the extrapolation of a measured structure in one drillhole would coincide with the down-hole depth of a measured structure in another drillhole, but the strike

and dip of the two structures would not match within reasonable expectations.

Two structures (here named the Coachwhip fault and Tarantula fault) were identified that were

traceable between several holes in the leach test area. While televiewer logs were not available for 15 of the 19 holes, correlation was possible using the geologic logs where geologists noted the

presence of a fault zone based on chip logging. The magnitude and direction of the displacements

along these two faults are unknown. For illustrative purposes the Tarantula fault (N35°E, 75°NW) crosscuts the Coachwhip fault (N63°E, 75°SE) and appears to show 10 ft of dip-slip motion. The

SRK geology model does not incorporate any fault displacements because the amount of offset

cannot be determined.

2.3.2 Detailed Lithologic Model

Using the drillhole intercepts, SRK generated a detailed 3-D lithologic model. The lithology was

simplified into Tertiary basin-fill formation, undifferentiated Tertiary granodiorite porphyry (mineralizing intrusion), and Proterozoic quartz monzonite porphyry (host rock). Other

volumetrically minor units such as Proterozoic diabase were not modeled.

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For the purpose of the model, the corehole logs were assumed to be the most reliable. Where holes

with different drilling methods were in very close proximity, the logged geology would not typically agree. During the reaming of BHP-1, for example, several cave-ins occurred that generated sample

contamination in the RC chips – making the comparison to the same core interval meaningless. In

these cases, the hole drilled with the more detailed and reliable sampling method was used, and the other disregarded.

The model boundary was chosen to extend 100 ft beyond the field test on all four sides. Within this

model boundary, three rectilinear grid sets (N-S, E-W, and Plan) were constructed on 50’ intervals, for the construction of 2-D polygons representing the lithologic units. Previous work shows that the

porphyry dikes strike about N80°E and dip steeply to the south, so the N-S cross sections were

generated first (Figure 2-6). The plans were drawn next, followed by the E-W long sections (Error!

Reference source not found.). Once all three sets of polygons were completed, a solid representing the porphyry dikes was generated using the polygons (see perspective views in Figure 2-7). Solids

for quartz monzonite porphyry and basin-fill formation were generated by clipping the model

boundary solid against the top of bedrock and the granodiorite porphyry solid.

2.3.3 Summary of the Field Test Area Geology

Globally within the deposit area, quartz monzonite is the dominant rock type (70%). The BHP field

test area, located on the southern edge of the densest concentration of porphyry dikes in the deposit, consists of about 60 percent granodiorite porphyry and 40 percent quartz monzonite porphyry. The

porphyry dikes strike approximately east-west, but are curved and anastamosing bodies that merge at

depth. The dikes dip at about 80° to the south.

The structural geology in the field test area is quite complex. The limitations imposed by the lack of

outcrop and the vertical drillhole orientations make delineation and correlation of fault structures

very difficult. The sheer number and variable orientations of structures noted in the geologic and

borehole televiewer logs attests to the complexity. The rock is very thoroughly and intensely fractured, with innumerable small slips and minor faults. The mineralogy consists of mixed copper

and iron oxides, silicates, and hydroxides.

2.3.4 Mineral Resources of Field Test Area – 2010 Estimate

The geology and assay statistics for the 19 drillholes within the field test area are shown in Table

2-3. The average drillhole grades in the BHP field test area (0.428 to 0.446 %TCu) are relatively

higher than the average grade for the Florence deposit (0.331 %TCu). Additionally, the table presents the ratio of ASCu:TCu grades, and the calculated modes for rock type (drillhole database

code ROCK), metallurgical zone (METZO), fracture intensity (FRACI), copper minerals present on

fracture surfaces (CuOx1), and copper minerals present in altered feldspar sites (CuOx2).

To calculate the resources of the field test area, SRK created solids bounded by the top of bedrock,

the top of sulfide, and the vertical traces of the injection and recovery wells (Figure 2-8). An

additional solid was created for the top 40 ft of bedrock (Bedrock Exclusion Zone) where blank casing was used and little copper extraction was expected to occur. Average %TCu and %ASCu

grades were calculated for the oxide zone excluding the bedrock exclusion zone. The resources

contained in the field test area were calculated using the SRK 2010 resource model and are

summarized in Table 2-4.

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Table 2-3 Drillhole assay statistics for the field test area

Well 1

Top of

Bedrock 2

Top of

Sulfide 2

Interval Length

Avg.

TCu (%)

Avg.

ASCu (%)

ASCU

:TCu Ratio

Rock

Mode 3

METZO Mode

4

FRACI

Mode 5

CuOx

1 Mode 6

CuOx

2 Mode 6

BHP-1 363 808.1 445.1 0.471 0.337 0.715 29 2 5 1 2

BHP-2 368.3 848.6 480.3 0.623 0.363 0.583 21 2 3 2 1

BHP-3 363 800.25 437.25 0.440 0.314 0.714 21 2 2 1 1

BHP-4 362.5 796.4 433.9 0.434 0.291 0.671 21 2 2 0 1

BHP-6 370 820 7 450 0.474 0.364 0.768 29 2 N/A

8 2 2

BHP-7 370 793.9 423.9 0.270 0.191 0.707 31 2 N/A 8 0 0

BHP-8 370 774.5 404.5 0.322 0.244 0.758 21 2 N/A 8 1 3

BHP-9 370 821 451 0.471 0.328 0.694 21 2 N/A 8 1 3

BHP-10 370 819.5 449.5 0.335 0.198 0.591 29 2 N/A 8 1 1

BHP-11 360 797 437 0.603 0.459 0.761 29 2 N/A 8 1 2

BHP-12 370 745.7 375.7 0.309 0.250 0.809 31 2 N/A 8 1 1

BHP-13 370 803.5 433.5 0.465 0.335 0.720 21 2 N/A 8 1 2

OWB-1 370 810.5 440.5 0.369 0.255 0.691 31 2 N/A 8 0 4

OWB-3 370 795.3 425.3 0.295 0.201 0.681 21 2 N/A 8 1 1

OWB-4 370 728 358 0.417 0.312 0.748 29 2 N/A 8 3 3

OWB-5 370 765 7 395 0.208 0.132 0.635 21 2 N/A

8 1 1

CH-1 370 789 7 419 0.341 0.243 0.713 21 2 N/A

8 3 0

CH-2 370 775 7 405 0.533 0.418 0.784 21 2 N/A

8 2 2

MCC427 360 761.25 401.25 0.543 0.424 0.781 21 2 3 2 1

1 – Wells BHP-5, OWB-2, and MCC534 are within the field test area, but no assay data are available

2 – Downhole depths

3 – Rock type 21 = quartz monzonite porphyry (Yqm); 29 = mixed Yqm and Tertiary granodiorite porphyry (Tgdp); 31 = Tgdp

4 – 2 = mixed iron and copper oxides

5 – FRACI code 2 = 5-10 fractures per foot; 3 = 10-15 fractures per foot

6 – 0 = minerals not noted; 1 = <1%; 2 = 1-2%; 3 = 2-5%; 4 = 5-10%

7 – Sulfide zone not intersected; depth given is TD

8 – Rotary/RC holes; no fracture data collected

Table 2-4 Mineral resources in BHP field test area

All Measured Oxide in Bedrock at 0.05% TCu cutoff

Area Tons TCu (%) ASCu (%) lbs TCu lbs ASCu

Within 8 Recovery Wells

1 636,812 0.431 0.310 5,490,000 3,950,000

Within 4 Injection Wells

2 154,063 0.448 0.319 1,380,000 983,000

1 – Recovery wells are BHP-2, 3, 4, 5, 10, 11, 12, and 13

2 – Injection wells are BHP-6, 7, 8, and 9

Source: SRK, February 2010 resource estimation.

Tonnage factor = 12.5 cubic feet per ton

Includes all Oxide material below the top of bedrock excluding the bedrock exclusion zone (top 40’ of bedrock). All mineral resources

within these two areas are classified as “Measured”

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SRK, 2010. Tgdp dike mass (blue) intrudes Yqm (buff) and is crosscut by a number of faults. Cross section lines A-A’ and B-B’ are

shown for reference.

Figure 2-5 Geology plan map through field test area; 700ft amsl

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Figure 2-6 N-S geology section 649370E through field test area looking east (L) and E-W section 744925N through field test area looking north (R)

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3-D depiction from top of bedrock of the three E-W-trending Tgdp dikes (blue) and drillholes in the BHP field test area. Quartz monzonite

(not shown) is the host rock.

Figure 2-7 Perspective views of the Tgdp dikes looking due W, -60 degrees (left) and S45°E, -75 degrees (right)

Source: SRK, 2010. Model blocks are 50’ x 50’ x 50’. Block grade cutoff colors: Blue = >0.2%TCu, Green = >0.3%TCu, Yellow =

>0.4%TCu, Orange = >0.5%TCu, Red = >0.6%TCu. Volume excludes the 40’ bedrock exclusion zone.

Figure 2-8 Plan view of volume of rock within field test designated for resource calculation

SWVP-026379



2.4 Conclusions and Lessons Learned

The general geology of the Florence deposits is well understood through drilling data, downhole

geophysical surveys, and the previous physical inspection by Conoco of the geology in the underground pilot mine. The existing geology deposit model is a good conceptual framework to

predict the approximate contacts and types of rocks and mineral zones to be encountered in any

specific area of the deposit and to enable the development of a life-of-mine plan for copper extraction. The fact that the bedrock is overlain by more than 370 ft of basin-fill formations and is

not available for additional physical inspection, in the usual sense, will always provide a measure of

difficulty and uncertainty in formulating detailed hydrogeological and structural models – especially

in predicting the detailed geology and rock properties at the 100-ft 5-spot production scale.

Vertical exploration drillholes spaced on a 250-ft, E -W oriented grid provide adequate definition for

resource estimation purposes, but have a reduced probability of intercepting steeply dipping

structures such as the E-NE striking 70 degree structures found at Florence. These structures were utilized by the Tertiary-Laramide granodiorite dikes to intrude and fracture the Precambrian quartz

monzonite host rock, and deposit quartz-chalcopyrite-pyrite-molybdenite veinlets, disseminated

grains, and fracture coatings. The historic structural fabric and Tgdp dikes are responsible for the

principal direction of E-NE anisotropy noted in the spatial distribution of mineralization and the responses seen in various aquifer tests. The geology model incorporates both E-NE and N-NW

features including the orientation of the porphyry dike swarm and the post-mineralization Basin-and-

Range faults. The model, however, is biased towards the identification of these later N-NW striking, moderately dipping faults, because they have a greater chance to be correlated from one drillhole to

the next. The Tertiary extensional period and Basin-and-Range faulting are responsible for the

intense fracturing, oxidation, and remobilization of former copper sulfide minerals to form a 40- to 1,035-ft thick copper oxide/silicate-bearing Oxide zone.

On the scale of the BHP field test, the intricacy and finely divided nature of the Tgdp dikes was

surprising even though the presence of thin dikes was previously known. Three major E-W striking,

south-dipping dikes crosscut the test area and coalesced at depth to form two main porphyry bodies. These dikes pinch and swell, and have variably-sized protuberances at irregular intervals. While the

overall trend of the dikes is approximately E-W, on a more detailed level the contacts commonly

deviate from this trend. The Tgdp dikes may also locally contain large xenoliths or intrusion breccia lenses of Yqm.

2.5 Recommendations for New Field Test

Presented below are comments and recommendations related to the Curis Production Field Test

(PTF) planned to begin in 2011. A work plan to coordinate all geology, hydrology, metallurgical

and operations activities has not yet been developed for the PTF.

2.5.1 Proposed Location of PTF and Associated Surface Disturbance

Two phases of drilling related to the development of the PTF are planned – the timing of the phases will likely overlap in the project schedule. Phase I entails using a rotary drill rig to abandon 10

exploration drillholes and wells as shown on Figure 2-9. Abandonment of historic holes and wells is

designed to close potential pathways to the overlying formations once raffinate injection begins.

Phase II entails using a combination of diamond drill and rotary methods to drill 18 to 24 new wells in a 1.8-acre area south of the BHP field test area. The project site contains areas that are eligible for

listing on the National Register of Historic Places (NRHP). It is Curis’ intent to minimize surface

and subsurface disturbance during any drilling related activities. Surface disturbance is defined as the disturbance occurring in the top 4-6 inches primarily owing to driving-related ground

compaction. Subsurface disturbance is defined to occur in excavated or drilled areas 0 to 10 feet

below the surface.

SWVP-026380



During Phase I, new temporary, unimproved roads will be created in the farm field to access the 5

wells and 5 exploration drillholes to be abandoned. Well and drillhole locations O39-O, P39-O, 433MF, and 482MF are within an area eligible for NRHP listing (Site 292). The total estimated

surface disturbance within the NRHP site is 0.48 acres, as shown blue hatching in Figure 2-10. An

access road width of 12 ft was assumed, which was determined by using a drill rig width of 8.5 ft, length of 26 ft, and turning radius of 50 ft. The working disturbance area is estimated to be

approximately 50-ft by 100-ft at each site. The drill will be limited to linear maneuvers (i.e. forward

and backward) within the NRHP site.

The locations of the buried exploration hole casings were surveyed using information in the drill

logs. The top of casing for a typical Conoco exploration hole is buried approximately 3 feet below

ground surface. To date, four of the target casings have been definitively located through the use of

a metal detector. The location of 433MF is known and has been surveyed, but the casing has not yet been identified through use of a metal detector so is likely deeper than three feet. A backhoe with a

2-foot wide bucket will be used to expose the top of casing on all holes. A trench approximately 5-ft

long, 3-ft deep, and 2-ft wide will be excavated, and excavation will stop when the top of casing is exposed. A distinct change in soil color typically appears immediately above and adjacent to the

casing up to 18 in below ground surface; this color change occurs where fill dirt was used to backfill

the top of the cut casing. This change in soil color will be used to assist during the excavation of

433MF. The backhoe will scoop the top 18 inches of soil over the approximate hole location to identify the fill dirt and covered 433MF casing.

Once the top of the casing has been exposed, a piece of 4-in PVC pipe will be inserted over the outer

rim of the casing to keep the boreholes free of dirt, and the trench will be backfilled with the dirt that was temporarily stockpiled. The rig will pull up over the top of the open casing, remove the PVC

pipe, and proceed to enter the hole and abandon it with Type V acid- and sulfate-resistant cement to

within 5 feet below ground surface. Following abandonment, any surface depression remaining above the closed drillhole would be backfilled and the surface regraded by shovel and rake. No

other surface excavations are required.

No subsurface excavations are required to close the five monitor wells. Abandonment of the wells

will involve filling the well casing with Type V cement and removing 19 feet of 12.75-in diameter surface conductor casing. The existing 4 in x 3 ft concrete pad supporting the wellhead vault will

also be removed. The ground immediately above the closed well will be regraded by shovel and

rake.

Phase II drilling is within an 1.8-acre area south of the BHP field test that has been identified to

contain no cultural resources eligible for listing on the NRHP. The estimated extent of surface and

subsurface disturbance related to well abandonment, drilling, and operation of the PTF including a

new pipeline corridor is shown on Figure 2-9. An elevated gravel-topped access spur road will pivot off the previously existing farm and field test roads. A pipeline corridor with a 2-foot deep ditch

lined with high density polyethylene liner will pivot off the existing pipeline corridor as shown in

yellow hatching on Figure 2-9. The approximate locations of the new road spurs, drill site disturbance area, and proposed pipeline corridor are shown in red hatching.

Subsurface disturbance in the top 20 feet includes drilling and installing 12.75-in diameter surface

conductor casing. An aboveground mud tank will be used to support the drill rig during rotary drilling of the top 390 feet. A mud tank is not needed for drilling below this depth. No other

subsurface excavation is needed to complete the drilling activities.

2.5.2 Drilling Methods

SRK recommends that mud rotary methods be used in the basin-fill formations; this drill technique

provides stable drilling conditions and boreholes in unconsolidated basin-fill formations with

virtually no deviation from vertical. Rotary methods may also be appropriate for holes designated as

SWVP-026381



observation wells unless the intent is to convert the observations wells to injection or production

wells in the future.

SRK recommends that only core and reverse-circulation drilling methods are used in the bedrock

within the PTF for holes to be assayed. Use of conventional mud rotary methods will preclude the

collection of meaningful assay data, which is essential for detailed determination of the head grade within the PTF. Without assay data, the accuracy of the recovery calculations will diminish. Lastly,

use of mud rotary methods in the bedrock will require extensive swabbing and well development of

rock that is already highly broken, friable, and prone to caving if agitated too greatly. Removing the residual mud is a time-consuming hourly driller’s charge that cannot guarantee all mud will be

removed. The formation porosity needs to be kept intact as long as possible during the test and in

operations, so it is a risk to use a method that can plug the fracture apertures before injection begins.

The reverse circulation method provides better delineation of geology contacts than does mud rotary drilling, but neither methods provides the level of detail achieved in a diamond drill hole. It is

recommended that a minimum of five of the PTF holes are drilled using diamond core methods, and

that the borehole televiewer is used in those holes. Diamond drill core will allow detailed review of rock contacts, fracture mineralogy, and the distribution of copper mineralization. Use of the

borehole televiewer will allow the geologists to correlate logged faults between holes, as was done

previously. As with the BHP holes, a downhole gamma probe should be used to determine the clay

layer and bedrock contacts. The caliper log and cement bond log are required to assess the success of cementing.

For consistency, all holes should be logged and sampled according to the geology SOPs developed

previously (detailed in Section 3.2.3 above).

2.5.3 Geology of Curis PTF

Based on evaluation of available drillhole data and the deposit geology model built in the 1990s by

BHP, the geology of the proposed Curis PTF will likely be less complicated than that seen in the BHP field test area. The Curis PTF area appears to contain approximately 75 to 80 percent Yqm, a

typical representation of the Florence deposit. The bedrock is overlain by approximately 375 feet of

basin-fill units, similar to that measured elsewhere on the property.

There appears to be four E-W striking Tgdp dikes in the proposed PTF area as shown in Figure 2-10.

Three sub-parallel, south-dipping dikes are 10-20 feet thick and one north-dipping dike is

approximately 30 feet thick; the latter dike splits off from the southern-most dike in the BHP field test area. In addition to the Tgdp dikes, there are several Tertiary andesite dikes that are

approximately parallel to the E-W striking, south-dipping Tgdp dikes. These andesite dikes appear

to be less than 20 feet in thickness. The BHP model also includes several north-striking dikes of

Precambrian diabase. SRK was unable to identify the drill intercepts from which these interpretations were made and believes they were “modeled in” based on interpretation from

drillholes outside the immediate vicinity of the PTF.

The oxide zone is estimated to be 350 to 450 feet thick in the PTF area. The oxide zone in this area contains mixed copper/iron oxide and silicate minerals and has a representative average grade of

0.45 %TCu and 0.37 %ASCu. Some preferred pathways may be expected to develop parallel to the

dominant E-NE striking sub-vertical Tgdp dikes. Based on nearby drillholes, however, the overall

rock fabric is highly fractured with an estimated fracture intensity of 10-15 fractures/ft.

SWVP-026382



Figure 2-9 Proposed location of Curis PTF and associated disturbance

SWVP-026383



Figure 2-10 Geology plan map of PTF, 900 ft amsl (upper); E-W geology profile 744600N looking north (left) and N-S geology profile 649250E looking east; (Tgdp is blue, Yqm is buff)

SWVP-026384



2.5.4 Logging, Sampling, and Assaying Protocols

The protocols for logging, sampling, and assaying should be reviewed to ensure best current

practices are followed. Protocols are in place and can be transmitted to the field staff to ensure

geological, structural, fracture mineralogy, and geotechnical logging techniques are consistent with previous work. For the PTF activities, logging will likely occur on a combination of hard copy logs

and digital data entry. During operations, logging and data entry activities should consider using

primarily digital logging methods via hand-held computer, bar-coding, and other standardized

formats for instant manipulation and use.

Sampling and assaying protocols were previously in place to ensure high confidence in the integrity

of the analytical results and should be continued during PTF activities. Sample integrity and a good

quality “Head assays” for the injection zone cannot be guaranteed with use of mud rotary drilling. As mentioned previously, the use of mud rotary drilling should be avoided in the injection zone with

the exception that limited mud rotary drilling may be required if hole stability difficulties are

encountered.

Samples collected from mud rotary intervals would be logged but not be sent for assaying owing to potential contamination through co-mingling with the overlying formation. Samples taken with RC

drilling are recommended to adhere to a 10-ft assay interval. Samples taken by diamond drill

methods will generally adhere to a 10-ft assay interval but should honor rock contacts to provide the best statistical correlation of rock type versus grade.

No changes to the methods for analysis of %TCu or %ASCu are recommended without a well-

thought out correlation study using both former and new methods. The only addition would be the analysis of a more complete list of constituents by inductively coupled plasma mass spectrometer

(ICP-MS) methods. Addition of ICP-MS analyses may assist to determine the concentrations of

trace elements that can be environmentally or otherwise significant. The additional analyses could

be performed on each interval or on selected intervals to reduce the cost (every other interval, every 5th or 10th interval, or on a 50-ft composite).

The QA/QC program including duplicate splits and standards was well-developed and robust in

execution. SRK recommends including occasional blanks in the stream to assess the laboratory’s sample preparation techniques and to send a select number to another laboratory for secondary

comparison of results.

Samples of fracture and feldspar-site mineralogy should be collected every 100 ft and analyzed by XRD, to confirm the mineralogy of the copper minerals and associated gangue minerals. Chip and

core samples are also planned to be used for additional bottle roll or column tests to assess copper

recovery and rate of recovery based on laboratory conditions, acid consumption. The samples may

also be used to assess the effectiveness of various pre-treatments for improving extraction and rinsing amendments to assess reclamation timing, cost, and effectiveness.

SWVP-026385



3 Design of Test Facilities The following sections summarize the design of the BHP test facilities. The facilities include the

wellfield, well construction and well head infrastructure, and the general facilities (tank farm, control

room, pipeline, and evaporation pond).

The field test as previously mentioned was designed with three objectives. First, the test was

conducted to demonstrate that the wellfield could be operated in a manner that met the

environmental regulations. Second, the test was required to understand the ISR process, primarily the copper recovery curve as a function of time – this was required to develop operating and capital

costs and to declare reserves. The test was also performed to prove the capability of reclamation.

Twenty-one wells were drilled with a spacing of 50 feet (Figure 3-1, OWB-6 is not shown). The original design was to inject in BHP-1 and recover in wells BHP-2 through BHP-5. Hole stability

problems with certain intervals in BHP-1 made it undesirable to use BHP-1 as a long-duration

injection well. The layout was revised to inject raffinate in BHP-6 through BHP-9, with a fence of

outer recovery wells. The spacing of the wells was determined after a review and simulation of multiple alternatives such as 7-spot, 9-spot, line-drive, staggered line drive, and other configurations.

Figure 3-1 Field test layout

SWVP-026386



3.1 Well Construction Design

There were three types of well designs for the pilot field test as shown on Figure 3-1. A description

of the injection and recovery wells (BHP-1 through BHP-13), the chemical monitoring wells (CH-1 and CH-2), and six observation wells (OWB-1 through OWB-6) is presented in Sections 3.1.1

through 3.1.3. Descriptions of the cementing process for the borehole annulus and the mechanical

integrity tests are presented in Section 3.1.4 and 3.1.5, respectively. The wellhead design for the BHP injection and pumping wells is presented in Section 3.1.6.

3.1.1 Injection and Recovery Wells

The 13 BHP wells have an identical design to allow them to be used as either recovery or injection wells. The uniwell construction design for the injection and recovery wells is shown on Figure 3-2.

The holes were drilled using mud rotary methods to the overburden bedrock contact between 340

and 370 feet below ground surface (bgs). In wells BHP-1 through BHP-4, the remainder of the hole in excess of 800 ft was drilled with 3-inch inner diameter (ID) HX core (6-inch core for BHP-2)

down through the lower basin-fill, oxide zone, and into the sulfide zone. The holes were reamed out

with reverse circulation methods. BHP-5 through BHP-13 were drilled to approximately 20 ft into

the sulfide zone by reverse circulation methods to approximately 800 ft (Table 3-1).

BHP staff developed a general well construction plan, but some field changes were made as needed

when difficulties were encountered in the individual holes. The well construction followed EPA

specifications including the general pattern listed below.

Steel surface casing (12 ¼” dia.) was installed in the top 20 ft and cemented with Type V acid-

resistant and sulfate-resistant cement in a 16-in diameter borehole.

A 12 ¼-inch diameter hole was drilled to 40 ft below the top of bedrock. Schedule 80 PVC

casing (8” dia.) was installed in the hole and the annulus between the casing and borehole was

filled with Type V cement. A double plug method was used to cement the annulus; the grout set for a minimum of 72 hrs.

A 6-in diameter steel casing was set in the hole to protect the 8-in PVC during subsequent drilling.

A 5 7/8-in diameter hole was drilled by a dual-wall reverse circulation method to a depth of approximately 50 ft below the oxide-sulfide contact. The exception was in BHP-2, where a 9

7/8-inch hole was drilled through the zone of six-inch diameter core. The 6-inch steel casing

was then removed from the upper portion of the hole.

Schedule 80, slotted PVC casing (4” dia., 0.04” slots) was installed in the entire length of the

open hole. Approximately 10 ft of bentonite, silica sand, and gravel were packed into the bottom of the 12 ¼- inch diameter hole between the 8-in and 4-in PVC casing. The top portion of the 4-

in PVC was then removed so that the 4-in PVC extended 25 to 118 ft up into the lower portion

of the 8-incasing.

A well head was installed and the well was developed by the drilling company.

Ground or hole conditions forced several changes in the general plan especially in BHP-1 where excessive well development in highly fractured bedrock resulted in washout zones of 2-3 feet in

diameter. Only 120 feet of 6-inch steel casing was retrieved in BHP-1; the remaining 280 ft slipped

50 feet down into the RC portion of the hole (between 170-453 ft bgs) and proved impossible to extract. A smaller diameter of screened PVC (1 ½”) was installed in BHP-1 and BHP-3; no gravel

pack was placed in these holes.

3.1.2 Chemical Monitoring Wells

The chemical monitoring wells CH1 and CH2 are located in representative locations along the pilot

test flow path (one-third and two-thirds along the length of the flow path and half way along width of

SWVP-026387



flow path. The wells have three manually operated, water quality samplers installed in the screened

sections of the oxide formation at a depth of 420 (top one-third of the injection zone), 610 ft bgs, and 720 ft bgs (Figure 3-1). The well coordinates and construction details are listed in Table 3-1, and the

construction design is shown on Figure 3-3.

CH1 and CH2 have discrete sampling devices located at each of the three well screens per well, but the sampling devises are not physically separated through use of a packer or rubber boot so some

vertical mixing likely occurred. A detail of a sampler is shown on Figure 3-4. The samplers were

custom-made by the BHP Copper Miami maintenance shop with a 1½ inch diameter stainless steel pipe with stainless steel caps welded at each end. Two swage fittings are installed at the top and one

swage check valve at the bottom of the sampler (Figure 3-4). The bottom swage fitting is a check

valve fitted with a ball seat. When the sampler is not pressurized, the fluid in the well forces the

check valve ball to float and the sampler is filled with water from the well.

One of the swage fittings on top of the sampler is connected to high pressure polyethylene tubing

that extends to the surface and is connected to a high pressure cylinder of nitrogen (Figure 3-4). The

other swage fitting is for sampling. The polyethylene tubing extends into the sampler to about one inch from the bottom of the sampler and extends to the surface. Three samplers hang in the well

with 316 stainless steel aircraft cable. The polyethylene tubing was rated at 1,000 pounds per square

inch (psi).

To operate, the sampler is allowed to fill with water, and is then pressurized. The compressed nitrogen enters the sampler and forces water up the poly tubing (that extends into the sampler)

(Figure 3-4). The fluid is forced up the tube to the surface until nitrogen gas exhausts. This process

is done until three sampler volumes were removed and the third was kept as a sample. Nitrogen gas was used initially, but was eventually replaced with cylinders of breathable air (P. Kelm, oral

commun., 2010).

3.1.3 Observation Wells

Six groundwater level monitor wells were drilled by rotary methods with blank casing in the top 40

ft of bedrock and screened in the oxide. The wells were installed surrounding the test area to

monitor the inward hydraulic gradient. All were installed in the oxide zone with the exception of OWB-2, which was drilled within the Upper Basin Fill Unit. The wells sampled when the wells

were first drilled and periodically sampled during the rinsing phase. The samples were taken with a

standard bailer in the blank casing immediately above bedrock, and the borehole was not pumped or purged until remediation activities began. Elevated sulfate was detected in OWB-1 and OWB-4

during the pond water injection phase. The sulfate quickly fell to background levels when injection

wells BHP-6 through BHP-9 were reconfigured to become recovery wells and WW-4 water was

injected in BHP-1. These two observation wells are located in the northeast and southwest portions of the wellfield adjacent to BHP-10 and BHP-5, which had the highest sulfate concentrations

measured during the test.

3.1.4 Cementing Practices

B & C provided the cementing plan in the application for the Aquifer Protection Permit (1996b).

The cementing program includes procedures for drilling and casing new wells (B & C, 1996b,

Section 2.1.3), and for abandoning exploration diamond-drill holes and retired wells (B & C, 1996b, Appendix E). The purpose of the cementing program for newly drilled wells is to support the casing,

to restrict fluid movement between formations in the casing-borehole annulus, and to prevent

excursion of leach fluids from the casing into the formation.

Following the recommendations of B & C and Layne Christensen, the primary cement job on BHP-1

through BHP-5 was performed by pumping cement slurry down the casing and up the borehole

annulus. The drilling contractor used specialized equipment to control the Type V, acid-resistant and

SWVP-026388



sulfate-resistant cement. Significant factors contributing to successful cementing include: pipe

centralization, good circulation and mud conditioning (low viscosity and low yield point), high displacement rate, and adequate contact time of the cement with the borehole wall. Barite mud was

used to achieve a high displacement rate and to prevent back flush of the cement slurry.

The borehole cement was allowed to set prior to drilling the screened portion of the well, and the well construction was not approved until the compressive strength samples passed the requirements.

A downhole cement bond log survey was also performed, which gave immediate feedback on the

presence of voids in the cement.

During the cementing of BHP-1 through BHP-5, Layne took four slurry samples for 7-day, 14-day,

21-day, and 28-day compressive strength tests. The cement samples were analyzed by Western

Technologies, Inc. of Phoenix; the cement samples met the specifications (500 psi compressive

strength) required by the Arizona Department of Water Resources (ADWR). The majority of the samples met the 500 psi specification within 21 days.

On the remaining 15 wells (BHP-6 through BHP-13, CH-1, CH-2, OWB-1 through OWB-6), 13 of

the wells passed the cement test (>500 psi) at 7 days. BHP-9 and OWB-2 passed at 14 days.

3.1.5 Mechanical Integrity Tests

In compliance with federal regulations, BHP had to design, install, operate, maintain, and close wells

in a manner that prevents contamination of the surrounding aquifer (B & C, 1996a). A program to test for the mechanical integrity of the wells was an integral part of upholding the EPA Underground

Injection Control (UIC) permit. Cement bond logs, heat logs, or other techniques can be used to test

the integrity of the cement casing but the cement bond log was the preferred downhole log used. Prior to operation, each well was pressure-tested for leaks for 30 minutes. Wells that fail the test are

deemed to be inoperable until the well casing is repaired and the pressure test is successful. The

pressure test can be accompanied by other activities including: (1) an inspection of the casing by a

downhole video camera, (2) a static head test of the solid casing with the bottom shut-in, (3) a density logging of the entire cased interval to verify lack of voids in the annulus between the casing

and the borehole wall, and (4) an acoustic logging of the casing interval above and possibly below

the perforated section while injecting clean water to detect flow behind the casing (B & C, 1996a, section 4.5.2.5).

Based on the UIC permit, BHP was required to submit the results of mechanical integrity tests to

EPA on a quarterly basis. The injection and recovery wells were tested prior to operation and were supposed to be tested every five years following installation. To date, a double-packer system has

been used in the mechanical integrity tests at Florence. A lower packer was installed immediately

above the proposed injection interval; the upper packer was installed near the top of the casing. The

well bore was filled with water and a hydraulic pressure of 60 psi (maximum allowable wellhead pressure) was applied. The test was conducted for a minimum of 30 minutes. The wells passed the

integrity test if there was less than five percent decrease or increase in pressure over a sustained 30-

minute period.

All of the Florence wells that have been tested passed the test at about 60 psi. Using seal lube on the

threads of the casing ensured extra protection against leaking. Without seal lube, the casing threads

were observed to leak as shown by casing tests on the surface. Some of the wells lacked the seal

lube, but still passed the mechanical integrity tests because there was a good bond between the casing and the Type V cement in the borehole annulus. Records on the results of the mechanical

integrity tests were recorded in the project Access database and on hard copy forms filed on site.

3.1.6 Wellhead Design

The wellhead includes equipment that holds the downhole-tubing string in place and provides

pressure sealing. Additionally, wellhead equipment includes the various pressure gauges,

SWVP-026389



instruments, valves, fittings, and pipes associated with controlling flow into or out of the well. These

various parts measure the fluid pressure and flow rate, and are used for sampling fluids.

BHP staff developed a general plan for the wellhead design for the injection and pumping wells as

shown on Figure 3-5. The instruments used on injection well BHP 1 included:

One flow meter and controller, 60 gpm,

One pressure transducer, 100 psi,

Conductivity probe and pressure gauge, and

One pump, 7.5 hp, 60 gpm.

The instruments used on the each pump well included:

One flow meter and controller, 15 gpm,

One pressure transducer, 100 psi,

Conductivity probe, and

One pump, 2.5 hp, 20 gpm.

SWVP-026390



Figure 3-2 Well construction design – Injection and recovery wells

SWVP-026391



Figure 3-3 Well construction design – Chemical monitor wells

SWVP-026392



Figure 3-4 Discrete sampler for chemical monitoring wells

SWVP-026393



Table 3-1 Summary of well construction details

Well ID Northing (ft)

Easting (ft)

Ground

Elev. (ft amsl)

Meas.

Point Elev. (ft amsl)

Top of

Sulfide Zone (ft bgs)

Total

Depth (ft bgs)

Bottom

Outer Blank

Casing (ft bgs)

Top

Screen1

(ft bgs)

Bottom

Screen (ft bgs)

Pump

Depth (ft bgs)

BHP-1 744923 649371.6 1463.73 1463.51 764 800 403 380 3 740 360

BHP-2 744870.8 649422 1463.61 1463.24 864 894 408 290 2 770 300

BHP-3 744975.8 649419.5 1464.02 1463.24 854 872.5 403 341 3 860 300

BHP-4 744975.9 649320.3 1464.21 1463.74 784 834 403 341 2 742 300

BHP-5 744877.1 649321.9 1463.9 1463.54 770 798 403 375 2 776 300

BHP-6 744923 649420.2 1463.74 1463.7 7507 820 410 385

3 805 300

BHP-7 744974 649371.9 1464.13 1463.1 800 810 410 400 3 760 300

BHP-8 744923.6 649320.8 1463.59 1463.6 780 790 410 400 3 780 300

BHP-9 744874.3 649371.1 1463.86 1463.9 7607 850 410 400

3 840 300

BHP-10 744923 649371.6 1463.73 1463.65 8207 837 400 400

3 820 300

BHP-11 744923 649371.6 1463.73 1464.4 8007 805 400 380

2 800 300

BHP-12 744923 649371.6 1463.73 1464.2 6 770 400 390

2 770 360

BHP-13 744923 649371.6 1463.73 1463.3 7607

840 420 386 2 826

8

OWB-1 744975.9 649470.8 1463.87 1463.7 8207 830 420 395

3 795 240

OWB-2 745026.2 649321.1 1464.27 1464.3 6 225 200 200

2 220 200

OWB-3 744976.4 649270.6 1464.51 1464.5 7507 820 420 396

3 796 240

OWB-4 744873.6 649270.3 1463.72 1463.7 6 755 410 405

3 745 240

OWB-5 744873.9 649470.9 1463.24 1463.2 7607 765 420 405

3 765 240

OWB-6 745134.0 649160.0 146.00 9

6 925 420 380

3 920 240

CH-1 744935.0 649381.9 1463.90 1464.92 4

7607 789 N/A 420

2 789

420,

610, 720

5

CH-2 744934.3 649407.9 1463.72 1464.61 4

6 775 N/A 420

2 775

420,

610, 720

5

Notes: Compiled by SRK 1 = top of screened PVC may be within outer blank casing

2 = 4” screen

3 = 1.5” screen

4 = Casing elevation

5 = Discrete sampling points; no pumps installed

6 = Top of sulfide zone was not encountered before total depth of well was reached

7 = Top of transition zone; sulfide was not encountered before total depth of well was reached

8 = Records do not indicate pump depth

9 = No record of surveyed measuring point

There is no sand pack in BHP-1 or BHP-3 in the screened intervals.

SWVP-026394



Photo date 1999

Figure 3-5 Wellhead infrastructure design

3.2 Test Facilities Design

As mentioned previously, the field test included four injection wells that were surrounded by a set of recovery wells to prevent outward migration of process solutions as shown in Figure 3-1. All of the

pump-out flows were captured and conveyed using high density polyethylene (HDPE) pipes to a

series of tanks at the tank farm and ultimately into the 7-acre evaporation pond.

The injectate consisted of well water from site well WW-4 mixed with raffinate obtained from the

BHP San Manuel SX/EW Plant in San Manuel. For limited periods (first day and during 1-week

maintenance period at end of December 1997), the WW-4 water was mixed with sulfuric acid only.

The injectate was filtered first through a set of carbon filters and then through a set of 3-micron bag filters. There was no attempt to extract the copper produced as metal from the process solution

recovered from the wellfield. BHP’s operational experience led them to conclude that solvent

extraction technology was developed sufficiently that no test was required on the processing of the copper solution or production of copper cathode. All of the recovered copper solution was deposited

in the evaporation pond.

SWVP-026395



3.2.1 Tank Farm

The tank farm layout was designed by the Winters Group of Tucson. It consisted of:

A new 5,000 gal stainless steel sulfuric acid tank capable of holding 93 percent sulfuric acid,

An insulated 3,000 gal sodium hydroxide tank fitted with heat traces to prevent the normal freezing of the 40 percent caustic at 57o F,

Two parallel activated-charcoal filters to remove any entrained organic from the wellfield injectate,

Three parallel bag filters fitted with 3-micron bags and differential pressure gages, and

A concrete truck off-loading pad for receiving shipments of sulfuric acid, caustic, and raffinate from the BHP San Manual Plant. For safety purposes all of the truck off-loading receiving pipes were

fitted with different sized Cam lock disconnects. The trucks were required to have their own off-

loading air compressors and the appropriate fitting to matchup with the site Cam lock fittings.

The following tanks are all 5,000 gallon capacity and made of HDPE. These tanks included:

Two raffinate tanks,

One pregnant leach solution (PLS) tank,

One water tank, and an

Injectate tank.

An 80-mil HDPE liner was laid under the concrete truck off loading and tank farm areas and graded downward toward the pond and welded to the keyed liners.

Below the tank farm is a ground mat that is also tied into the pond fence. The ground cable was

installed to meet Federal electrical safety standards. A set of Jersey barriers with seep holes was installed parallel to the west pond wall; the area under the tank farm concrete tank and pump stands

was filled gravel to allow drainage to the pond. All tanks are fitted with level indicators.

All of the flows exiting the tanks along with tank elevations were monitored. Flows were measured via MagFlow meters calibrated against tank volume changes. The outputs of the level indicators and

Magflow meters were sent to the distributive control monitoring system.

Acid from the sulfuric acid tank went through the positive-displacement pump and acid was injected into the injectate line via a horizontal in-line mixer. Caustic was metered directly into the line into

the evaporation pond. Both were fitted with feed forward sensors so that flow stopped if there was

no flow in the process lines. Both acid and caustic systems were fitted with redundant check valves

back flow preventers.

3.2.2 Piping and Surface Layout

All of the piping in the plant and wellfield are constructed of welded 3-in diameter HDPE. The piping, valves, meters, well heads, pumps, tanks, truck off-loading areas, and pilot process facility

are constructed on lined HDPE pads to prevent contact with the native soil in compliance with the

1998 Arizona Department of Environmental Quality (ADEQ) Mining Guidance Manual - BADCT

(see Figure 3-5).

There are three HDPE pipelines to the wellfield from the tank farm. They are laid in a bermed

trench lined with 80-mil HDPE to prevent any exposure of the solutions to the native soils.

All of the pumps and fittings in the tank farm area except the water pump and acid pump are constructed of 316 stainless steel; the water and acid pumps are mild steel. All of the pumps are

horizontal centrifugal except for the acid and caustic pumps, which were positive displacement

pumps.

SWVP-026396



Evaporation Pond

The double-lined evaporation pond was designed by Fluor Daniel Wright of Vancouver to meet ADEQ BADCT requirements. It was sized based upon the expected inflows from the wellfield and

rainfall, and evaporation rates based on the site pan evaporation rate. A net evaporation rate was calculated and the pond surface area was established at 7.5 acres for the initial pond. This was to be

one of eight similar ponds for the ultimate full-scale production at Florence. The pond site was

moved northward slightly owing to the presence of archaeological sites.

The pond was excavated and cut material place on an unlined pad in the farm field to the northwest of the pond, as shown on Figure 3-6. The area was excavated to a depth of approximately 35 feet

with the sump at its low point at the middle of the north wall of the pond.

The bottom 80-mil HDPE liner was laid on compacted fill to a 95 percent compaction (ASTM 1557). All welds were vacuum soap tested, and selected test pieces were taken and pulled for

tension measurements. The liner was doubled lapped. An 8-in diameter schedule 80 PVC pipe was

placed at the sump and extended to the surface. The bottom of the pipe was perforated to allow

inflow of any potential leakage. A geonet was laid over the entire lower liner and then covered by an 80-mil HDPE upper liner; it was welded in the same manner at the bottom liner.

The liners were keyed into the berm surrounding the pond according to BADCT prescriptive

requirements. The liner was laid into a 2-foot deep trench and up the outer trench wall. The trench was filled with compacted earth to a 95 percent Procter.

The tank farm liner that was laid under the truck off loading and tank farm areas was graded toward

the pond and welded to the keyed liners as noted earlier.

One design-related problem occurred during operation. The 8-in diameter inter-liner leach fluid

collection pipe partially collapsed and pressed downwards in a slight bend owing to the weight of the

water. The leach fluid recovery pump became entrapped in the pressed pipe and could not be

removed until the water in the pond evaporated. It is highly recommended that this pipe be replaced with a stainless steel perforated pipe before initiating the PTF.

Photo date 1999

Figure 3-6 Excavated pond, earth pile to northwest, tank farm, and wellfield to west

SWVP-026397



Photo date 1999

Figure 3-7 Evaporation pond, floating dock, and boat for access to pond and sprayers

Photo date 1999

Figure 3-8 Evaporation pond embankment, liner keyed into berm, and 8-foot anchor fence

SWVP-026398



Photo date 1999

Figure 3-9 Senniger high-evaporation sprayers floating on 3-in welded HDPE piping. Yellow Jerry cans are for flotation support

Distributive Control System

An Allen Bradley distributed control system was installed in a rental trailer. The trailer (Mobile Mini) was installed on a pad on the south side of the pond fence. The controller was connected to a

computer with a monitor. The monitor displayed the following in real time and displayed the

following recorded information:

Tank levels,

Flows to the wellfield individual wells in the wellfield,

Flows from the wellfield individual wells,

Combined flows to the wellfield,

Combined flows from the wellfield,

Acid injection rates from the acid tank,

Caustic injection rates to the neutralization system,

Tanks level alarms for overflow prevention (high-high),

Transducer outputs from the levels in the wells, and

Conductivity and pH.

Wellfield net inward hydraulic control was maintained automatically by the control system. Whenever the gradient might be lost, the controllers adjusted flow to the individual wells to maintain

the hydraulic gradients.

SWVP-026399



3.2.3 Fluid Management and Filtration

The BHP principal hydrologist established the flow criteria to and from the wells. The plant

operators maintained the proper mix of raffinate, water, and pond recirculation solution to the

wellfield. The ratio of raffinate in the injectate, however, changed through time as can be seen in Figure 3-10. Through Day 46 (December 16, 1997), the percentage of raffinate in the injectate was

kept at 8.5% although short-duration operational spikes occurred that ranged from 6.1% to 10.6%.

The raffinate percentage in the injectate was reduced to an average of 5.8% through January 6, 1998

and 4.1% through the end of the test on February 9, 2008. The initial reduction was made as an experiment to assess impact on copper recovery. When the total dissolved solids concentrations

began to build in the pond, some pond water was pumped into the raffinate tanks in lieu of raffinate

and was used as make up; this produced the variable raffinate to injectate ratio seen between January 7, 1998 and February 6, 1998. During this time, the injectate included a mix of pond water,

groundwater from WW-4, and raffinate.

Free acid levels to the wellfield were maintained between 5 and 10 g/L. The caustic addition to the

feed fluid to the evaporation pond was maintained at a minimum pH 4.5.

All injectate was passed through parallel activated charcoal filters to remove and free or entrained

organic from the raffinate received from San Manuel SX Plant. The filters were operated one at a

time via by-pass valves. Whenever pressure began to build the units were switched and backwashed into the pond. The injection of raffinate ceased from December 24-29, 1997 during a period when a

leak in the carbon filter was identified and fixed. During this maintenance period, the injectate

consisted of sulfuric acid and WW-4.

The filtered solution was the passed through a set of two bag filters fitted with 3 micron bags.

Whenever the differential pressure began to build, one filter was switched out and the third switched

into the system to allow changing of the bags. The bags were rinsed with fresh water and disposed

in a landfill. No solution was allowed to be injected until it had passed through both the carbon filter and particulates filters.

Source: Originally prepared by M. Brewer, BHP; modified by SRK, 2010

Figure 3-10 Ratio of San Manuel raffinate to injectate during field tests

0%

2%

4%

6%

8%

10%

12%

10/31/97 11/14/97 11/28/97 12/12/97 12/26/97 1/9/98 1/23/98 2/6/98

Rati

o

Date

Ratio of San Manuel Raffinate to Total Injectate (gal/hr)

SWVP-026400



3.2.4 In-ground Environmental Monitoring Methods

Figure 3-2 illustrates the construction of the injection and recovery wells. In-ground environmental

monitoring was based on routine measurements of annular resistivity probes installed on the casing

centralizers. The conductivity monitoring probes were designed to detect any excursion of high-conductivity leachate into the UBFU through the concrete along the casing annulus. The well

centralizers were fitted with conductivity probes from just above the bottom of the grout seal through

20 foot above the clay zone. These were simple two strand wires cut at different lengths and tied to

the centralizers. Resistance was measured at surface with a volt-ohm meter at various voltages. Measurements were taken at regular interval over periods of time ranging from 2 to 10 minutes to

allow for stable readings and bleed off from the meter itself. Electrical resistivity values (ohms/cm2)

were then converted to conductivity values (µS/cm). Baseline measurements were taken prior to the injection of any acidic solution. Reading were taken manually on a weekly basis by the on-site

instrumentation technician and entered into an Excel spreadsheet that calculated the resistance

measurements for the cement and cable.

Figure 3-11 shows the annular resistivity of selected wells on a weekly basis from November 26, 1997 through May 1998 and then quarterly until July of 2001. As can be seen, slight increases in

resistivity were noted in all wells at initiation of the field test but the readings stabilized during the

field test and post-test rinsing phase with the exception of BHP-8. BHP-8 went from 10 Kohms to 29 Kohms. This was due to the materials used, large gauge copper wire (also used for the pump

wires) and steel bands. The end of the copper wire and steel bands were exposed to the concrete

grout. Oxidation occurred during the well use period which caused an increase in resistance at the copper-steel connection point.

Because the injection wells could not be accurately sounded while operating, BHP used calibrated

pressure transducers made by PWI of Tucson. These were calibrated using a two-point method 100

feet apart, and by verifying depth with a depth sounder. The pressure transducers were located just above the pumps or mid-level of the injection fluid levels. They were commercially available

transducers that could monitor solution level within 0.1 feet. These specially designed piezoelectric

transducers used were the first generation of transducers that could be used in a dynamic changing head situation.

Unfortunately, the transducers needed to be constantly recalibrated, and drifts as much as 2 m of

head occurred in a 48-hr period (M. Kline, personal communication, 2010). This was caused by the radical changes introduced in the system by the San Carlos Irrigation and Drainage District (SCIDD)

irrigation well BIA10B, which is adjacent to the 760 ft north-northwest of the field test area. The

operation of the well (~1500 gpm) could induce a change of 20 to 30 feet of head in a 48-hr period,

with no advance warning by SCIDD of when the well would be turned on or off. Most transducers at the time were only designed to operate in a narrow range and couldn't handle such an abrupt

change. Although the PWI transducers BHP used were the best available at the time and performed

better than BHP’s TROXLER data loggers, they were still prototypes, which didn't have the great sensitivity or ability to adjust to the extremes imposed by operation of the nearby irrigation well (M.

Kline, oral commun., 2010).

Environmental Data Processing

The field test cells used a computer-based SCADA (System Control and Data Acquisition) system to gather data from the remote telemetry systems in the well field. The remote units stored data locally

until the information was uploaded to the central computer. Three programs were used to convert the raw data into a usable format: Datatran.exe, Filter.exe, and a batch file named week.bat.

The telemetry system would occasionally receive false data due to static build-up in the

instrumentation lines. To limit extreme biasing of data, the Filter program was modified to remove

false readings. These programs allowed data import to Excel or other spreadsheet applications.

SWVP-026401



Figure 3-11 Annular resistivity in Kohms

Annular Resistivity in Kohms

0.0

5.0

10.0

15.0

20.0

25.0

30.0

11/2

5/97

1/24

/98

3/25

/98

5/24

/98

7/23

/98

9/21

/98

11/2

0/98

1/19

/99

3/20

/99

5/19

/99

7/18

/99

9/16

/99

11/1

5/99

1/14

/00

3/14

/00

5/13

/00

7/12

/00

9/10

/00

11/9

/00

1/8/

01

3/9/

01

5/8/

01

7/7/

01

9/5/

01

11/4

/01

Date

Ko

hm

s

BHP6

BHP7

BHP8

BHP9

BHP10

BHP11

BHP12

BHP13

OWB1

OWB4

OWB5

CH1

CH2

OWB3

OWB3 values

show n x5 scale

SWVP-026402




In general the installed system performed as designed; however a number of problems were

encountered during the test. These problems and the suggested remedies are shown Table 3-2.

Table 3-2 System problems and resolutions

Problem Resolution

Grundfos downhole pump and motor failures and clogging

The motors were replaced under warranty with more reliable units.

The pumps were modified and the pump check valves were drilled out to allow reversing of the flows through the pumps to clear precipitates and algae. This action resolved the issue.

Conductivity probes gave inconsistent readings. A Wheatstone bridge system was used that allowed dampening to be applied along with averaging. This action resolved the issue.

The well flow control system software developed by the University of Arizona did not work well. Flows bounced and were inconsistent.

The on-site staff recreated the software in C++, which allowed dampening, and signal averaging. This action resolved the issue.

The evaporation pond filled up more rapidly than originally anticipated due to additional hydrology tests, rainfall, operator control, and seasonal effects.

A set of Senniger evaporator sprayers were installed on the pond, but were not sufficiently effective to control pond water elevations. More robust evaporators were needed and evaporation should have started earlier in the test.

The pressure transducers in the wells were hung in the injection wells. The net result is the readings jumped as the fluids dropped into the wells.

The wells were already constructed and no thief tubes could be added to dampen the readings.

Birds landed on the evaporation pond frequently with one duck dying.

Manual hazing via use of employees chasing the ducks by boat, firing shot guns was largely ineffective.

The majority of significant safety incidents and near misses including one fatality were related to commuting accidents.

A fatigue management system was implemented as most employees traveled to and from the Phoenix and Tucson areas.

The well casings were made of schedule 80 PVC. Cementing the wells was completed carefully to avoid damaging the plastic casing.

One well was completed using Smith vinyl ester fiber cast pipe with casing strengths that exceed 1,000 psi. This avoided all of the special equipment need to protect the pipe.


Many of the technical operations challenges experienced in 1999 would be reduced now by use of

modern state-of-the art equipment and instrumentation. A few recommendations related to the

operation of the PTF are provided below.

Snow makers (at least three) should be installed prior to the start of the next field test to keep

ahead of water levels in the evaporation ponds. These should be installed on a barge in the

center of the pond to prevent overspray from landing on unprotected areas and to reduce the

noise level detected in nearby areas.

The three discrete samplers in the chemical monitoring wells worked well and provided valuable information on the breakthrough times and water chemistry. They were not physically isolated,

however, so some vertical mixing may have occurred; packers or rubber boots should be used to

isolate each discrete sampler. Additional samplers (3to 6 total) may be desirable to provide

SWVP-026403



more detail in the evolution of the water chemistry over various elevations. The increased

numbers of samplers, however, should be viewed from a practical eye with respect to the added complexity of the well installation, sample collection procedures, and increased analytical costs.

Listed below are recommendations to consider for injection/recovery well design.

More substantial conductivity probes should be evaluated and installed during construction of the new wells.

The field test wells had 8-inch upper casings with an inner, temporary sleeve that was used to prevent damage to the PVC during drilling of the 5 7/8-in borehole in the ore zone. A droppable

RC drill bit was used so that the RC rods could remain in place while the 1.9-in ID (1.5-in OD)

PVC casing could be installed in the injection zone. A review of current bit sizes, casing diameters, and diameters of the injection pipe materials should be made to evaluate the potential

for downsizing the well and casing diameters while still providing the diameters needed for all

stages of drilling and well installation. This has potential for a large savings in life-of-operations

capital costs if revised dimensions in one or more wells demonstrate that they can be installed and show reliable performance during the PTF activities.

In the UIC permit, PVC, fiberglass-reinforced plastic (FRP) or other corrosive resistant casing is

allowed. FRP if used is to be made from aromatic amine epoxy resin, which provides chemical

resistance for sulfuric acid process solutions. SRK recommends evaluating the cost-benefits of

replacing the PVC casing with Smith vinyl ester pipe or equivalent such as Certa-lokTM PVC. The additional cost is offset by greater strength and resistance to pressure. Certa-lok PVC is

extremely resistant to harsh environments, acids and other chemicals and is commonly used for

Class III injection well construction. Thief tubes should be installed on all wells that allow insertion of pressure transducers to read with wide fluctuation of head in the wells.

Positive displacement cementation allows the entire annular space to be cemented in one fluid process and provides a superior annular seal.

Generally an injection well passes mechanical integrity testing if cementing records, such as the

cement bond log, demonstrate complete filling of the annulus between the casing and the well

bore. Cement pressure testing of the production casing is not only a permit requirement, but is

also the industry standard secondary test; performing these tests provides continued value going forward as proof that the well was properly constructed.

Drilling out of the production interval using lower cost mud rotary methods as opposed to

reverse circulation may be economically beneficial if the mud cake can be thoroughly removed

during well development. The downside is that the sample collected will not be usable for

assaying purposes. The rotary drilling only option would be appropriate in the observations wells.

Current industry well completion practice is generally through the installation of a production screen and a separate telescoped liner into the production zone. The liner is sealed within the

production casing with a series of two rubber k-packers or m-packers (triple seal). For an acid-

injection application, these rubber packers would be constructed of silicon rubber to prevent chemical degradation of the rubber. By utilizing a rubber-sealed liner, the size can be increased

to bring the screen wall closer to the formation (i.e. 6-in production casing, 5 5/8-in drill out, 3-

in or 4-in screen.

A 3-in or 4-in screen dimension allows for more rigorous well development but may need to be

replaced by 1.5-in ID screen in boreholes with poor rock stability. Well development is faster and more successful the closer the source of energy is to the producing formation.

SWVP-026404



4 Hydrologic Site Characterization Extensive summaries and white-papers have been prepared by BHP and predecessor companies on

the hydrological characterization and numerical flow models for the Florence deposit (Conoco, 1976,

Magma, 1994; and BHP, 1997c, d; BHP, 1999). Project-scale aquifer tests, baseline water quality sampling and modeling were performed to support environmental permit activities and to assess the

representative properties of various aquifers (B&C, a, b). Aquifer tests and test-scale modeling were

performed in the field test area before and after the injection of raffinate. The sections below provide an overview of the local hydrology and the project-scale and field-test scale test work.

4.1 Hydrogeological Characterization of the Deposit

The major surface water feature in the area is the Gila River, located about 0.5 miles south of the

project area. Because of upstream diversions (Florence-Casa Grande Canal and North Side Canal),

the Gila River is generally dry with the exception of flow caused by brief, intense seasonal rainfall. Two watershed drainages (East Drainage and West Drainage) transect the mine and administration

areas but discharge only ephemeral flow to the Gila River. Consequently, infiltration of river water

into the upper basin-fill sediments is limited to periods of ephemeral flow.

The regional groundwater gradient is from the recharge zone along the Gila River flowing north-

northwest to the Salt River Basin. Historically, regional groundwater withdrawals have been

primarily been related to agricultural uses and utilize the upper and lower basin-fill aquifer.

Locally, the aquifers correlate well with the lithologic units identified in the project area; the

hydraulic properties, pump tests, and water quality data confirm that there is little vertical

communication between the aquifers. The approximately 370 ft of unconsolidated conglomerate and

alluvial material overlying the deposit was divided into five units (BHP, 1997a): (1) Quaternary Alluvium (Qal), (2) Upper Loose Conglomerate (ULcgl), (3) Upper Cemented Conglomerate

(UCcgl), (4) Clay, and (5) Lower Cemented Conglomerate (LCcgl). Flat-lying basalt flows and

dikes were encountered by drilling in the poorly indurated conglomeratic unit. The ULcgl is the principal source of groundwater in the area, primarily for irrigation purposes; the aquifer for this unit

is called the Upper Basin-Fill Unit (UBFU). The Clay layer is approximately 20 to 40 ft thick and is

50 to 70 ft above the top of bedrock over most of the deposit area; the aquifer in this unit is called the Middle Fine-Grained Unit (MFGU). The LCcgl varies in thickness from 50 to 800 ft and consists of

weakly to moderately cemented conglomerate; the aquifer in this unit is the Lower Basin-Fill Unit

(LBFU). Table 4-1 correlates the aquifer units associated with the lithologic units found in the

project and field test area.

SWVP-026405



Table 4-1 Correlation of geologic and hydrogeologic units in the basin fill formations

Lithologic Map Unit

Lithology Aquifer Unit

Aquifer Description

Comments

Qal Quaternary alluvium Qal Alluvium Recent, coarse-grained, highly permeable, unconsolidated sediments

ULcgl Upper Loose Conglomerate

UBFU Upper Basin-Fill Unit

Laterally uniform, coarse-grained, permeable, unconsolidated, sediment, and matrix-supported conglomerate.

Wells have a "GU" designation for Gila (Conglomerate)Upper

UCcgl Upper Cemented Conglomerate

UBFU

Clay Clay MFGU Middle Fine-Grained Unit

Laterally extensive, fine-grained, calcareous silt/clay unit with low permeability

LCcgl Lower Cemented Conglomerate

LBFU Lower Basin-Fill Unit

Laterally extensive, coarse- to fine-grained, unconsolidated conglomerate with increasing induration and decreasing permeability with depth.

Wells have a "GL" designation for Gila Lower

Source: Compiled by SRK, 2010

4.1.1 Pump Tests

A series of 49 pump tests in 17 locations were conducted around the site as part of the APP application process. This included 17 major pumping wells and 46 monitoring wells, screened

within different aquifers. Eight wells were completed within the UBFU, 17 within the LBFU, and

38 wells within the oxide aquifer. The pump test results are summarized in Table 4-2. The significantly lower hydraulic conductivity in the MFGU is a favorable feature for ISR operation to

limit the potential vertical migration of process solutions. The low conductivity of the sulfide zone

eliminates the sulfide zone from consideration for an ISR operation.

Table 4-2 Hydraulic parameters of hydrogeological units

Hydrogeological Unit Thickness (ft) Average Hydraulic Conductivity (ft/day)

Upper Basin-fill Unit (UBFU) 200-500 60

Middle Fine-Grained Unit (MFGU)

20-40 0.00014

Lower Basin-fill Unit (LBFU) 50-800 5

Oxide Zone About 440 0.5 (from 0.1 to 1)

Sulfide Bedrock - 0.003

Source: Brown and Caldwell, 1996a

SWVP-026406



4.1.2 Measurement of Anisotropy

Pump tests to assess the anisotropy in the oxide zone were conducted in several locations including

the P12 and P19 well clusters located in the northwest part of the project area (see Figure 4-1). The

measured anisotropy ratio at P13 is about 3 and the major principal axis direction is N61°E (Figure 4-2). The anisotropy ratio at P19 is about 1.7 and the major principal axis direction is N78°E (Figure

4-3). The horizontal anisotropy can have a significant effect on effective sweep and copper

recovery. In theory, a large sweep area is obtained when the injection and recovery wells are

installed in the direction of the minor principal direction. When the injection and recovery wells are in the direction of the major principal direction, the solution sweeps a narrow band of rock. BHP’s

evaluation of various well configurations showed that the 5-spot pattern, crossing both minor and

major principal axes, would provide sufficient sweep and was the most cost-effective pattern for the layout of the wellfield.

4.1.3 Well Capacity

The well capacity is the pumping rate per unit thickness of the oxide zone at the maximum allowable drawdown. The maximum allowable drawdown is the difference between the ambient groundwater

level and the top of the pump. For the calculation of well capacity, the assumptions were that the

allowable drawdown was 200 ft., the well has 57 percent efficiency (based on the pumping test results), and the mean hydraulic conductivity of the oxide zone of 0.5 ft/day. A mean pumping rate

of 0.25 gpm per ft was obtained, which did not take into account nonlinear head loss, and the

mechanical and biological clogging of the wells and formation. To be conservative a pumping

recovery rate of 0.1 gpm per foot was chosen (BHP, 1997c). For a 6-in well and a 4-in pump, the maximum flow rate was calculated to be less than 200 gpm.

4.1.4 Hydrophysical Logging

BHP retained Colog, Inc. of Golden, Colorado to conduct a series hydrophysical logging tests in sets

of pumping and observation wells situated across the deposit. One of the tested well pairs, P5, is

located E-SE of BHP-1 in oxide bedrock and is therefore expected to be reasonably representative of

the hydraulic conditions found in the field test area.

The hydrophysical tests were designed characterize the vertical hydraulic heterogeneities and their

correlation with geologic structures. The tests results were used to calculate the flow efficiencies in

the oxide zone. The vertical flow profiles showed that the inflow is not uniform. The percentage of no-flow zone along the wellbore represents the fraction of rock that will not be in contact by lixiviant

directly. The percentage of permeable zones as a function of threshold length is presented on Figure

4-4. The threshold length is defined as the minimum length of impermeable zones in the borehole. That is, any no-flow zone that is less than the threshold length is considered to be a permeable zone.

The rational for defining threshold length is that if a no-flow zone is smaller than the threshold

length, the rock can still be contacted via fluid diffusion and flowing through micro-fractures (Figure

4-4). The average percentage of permeable zone increases from 65 percent at a 5-ft threshold to 85 percent at a 20-ft threshold.

In the oxide bedrock in the P5 well located 265 ft E-NE of BHP-1, the average percentage of

permeable zones measured at both 40 and 70 gpm production rates was greater than 80 percent at a 5-ft threshold. The hydrophysical logs at P5 indicate there was nearly continuous inflow throughout

the wellbore. This favorable condition would be expected to be present at the nearby field test area.

SWVP-026407



Source: BHP, 1997c

Figure 4-1 Aquifer test locations in the deposit area

The major principal direction in the vicinity of the P13 well cluster is N61°E. Source: BHP, 1997c

Figure 4-2 Horizontal anisotropic test at the P13 well cluster

P13.1 P13.2

O13.1

K1=0.86 ft/d

K2=0.29 ft/d

29 degree

-0.4

-0.3

-0.2

-0.1

0

0.1

0.2

0.3

0.4

-0.4 -0.3 -0.2 -0.1 0 0.1 0.2 0.3 0.4

North

K1K2

SWVP-026408



The major principal direction in the vicinity of the P19 well cluster is N78°E. Source: BHP, 1997c.

Figure 4-3 Horizontal anisotropic test at the P19 well cluster

Source: BHP, 1997c

Figure 4-4 Percentage of permeable intervals as a function of threshold length

The hydraulic connection between wells was estimated by evaluating flow distributions in wells

during stable ambient conditions and during stressed conditions in cross-hole tests. Tests were

conducted in four observation/pumping well pairs. BHP hydrologists concluded that the cross-hole

test results indicated that selective pathways may exist through discrete fractures and occasional changes of well pattern and flow direction may be necessary during operations in order to achieve

high recovery.

4.1.5 Regional Flow and Transport Model

B & C (1996) performed several numerical simulations as part of the APP and Underground

Injection Control Permit (UIC) applications. The numerical models included:

-0.6

-0.4

-0.2

0

0.2

0.4

0.6

-0.6 -0.4 -0.2 0 0.2 0.4 0.6

K1=0.54 ft/d

K2=0.32 ft/d

12 degree

P19.1 P19.2

O19.1

K1

K2

0

20

40

60

80

100

120

0 5 10 15 20 25

perc

en

tag

e o

f p

erm

eab

le i

nte

rvals

Threshold, ft

PW1-1

PW2-1

PW2-2

PW3-1

PW7-1

P15-O

P13-2

P12-O

P8.1-O

P5-O

P19-1

P28.2

Average

SWVP-026409



A regional groundwater model, MODFLOW code,

Transport flow models, PATH3D, a particle tracking code, and MT3D, a contaminate transport

code.

The regional groundwater flow was simulated under expected in-situ operational conditions, including mine closure and post-closure. The grid covered a 10-square mile area, with eight

horizontal layers of varying dimensions. The vertical coverage included the UBFU, MFGU, LBFU,

the oxide zone, and the sulfide zone. The Party Line fault and the Sidewinder fault were assumed to have an order of magnitude higher hydraulic conductivity than was indicated by actual values

measured in the field, at the request of ADEQ and EPA.

A simulation of four years of operation was performed by B & C. Regional groundwater simulation was performed at Year One. The following two years were simulated with regional and mining

pumping (the base case). The fourth year simulated hydrologic variations, where either increased

recharge or withdrawal was investigated.

Simulation of mining under natural conditions included: ISR well operations and important regional stresses and conditions such as irrigation and municipal groundwater pumpage, and the contribution

of the Gila River. Particle tracking simulating the active leaching and hydraulic control showed that

all of the mining solution was contained within the hydraulic zone.

4.2 Hydrogeological Characterization of Field Test

Prior to the raffinate injection phase, hydrogeological characterization was performed with varying

numbers of wells in the field test location. These characterization tests included: differential pump

tests and a groundwater injection tracer test. BHP prepared a numerical flow and transport model

(MODFLOW/MT3D) to estimate the in-situ porosity and dispersivity, and the lateral and vertical excursion of solution. A sweep efficiency simulation was also performed. The tests and findings are

briefly described below and in greater detail in BHP reports and memoranda (1997c, d).

4.2.1 Field Measurements and Data Management

Operators were trained to measure water levels, use the pH and conductivity meters, collect and ship

water quality samples for analysis, download data transducers, and record the results of site

inspections and maintenance repairs. The field measurement entries were generally done by hand into log books with numbered pages that were kept at the control room trailer and on individual field

sheets – much of which were then entered into the project database.

Field measurements were performed using pH and electrical conductivity meters. The YSI meter used until November 17, 1998 was found to be unreliable for pH measurements; the YSI meter did

provide adequate reliability and reproducibility for electrical conductivity readings. The YSI pH

meter was replaced with a Corning meter that was used thereafter with good reliability. Training on both meters and measurement methods was reinforced at regular intervals especially when quality

control issues were noted between different technicians.

BHP used a Microsoft Access database and Excel spreadsheets to record much of the project data

that were collected during the field test. The database is still available for review and inspection. The data collected included well construction and abandonment information, the results of

mechanical integrity tests and field measurements (water levels, pH, EC), pump installation and

service records, laboratory analyses for a variety of constituents, flow rates, and other information. Staff members devised data entry forms for daily data entry activities, standardized reports, queries,

and water quality graphs that updated themselves as new analyses were added.

Water quality analyses including duplicates were performed by three laboratories. Hard copy lab

results were provided – no PDF copies were digitally provided by the laboratories. The water quality analyses were recorded in the Access database by sampling point, date, and laboratory with

SWVP-026410



all constituents arranged horizontally across the row. This method did not allow detailed

information to be recorded about each constituent, such as the method detection limit and laboratory qualifiers. Electronic data deliverables were not readily available at that time from all of the

laboratories used. Although queries and reports were developed, the database structure is not ideally

formulated to access unique data records.

Transducers were downloaded by the staff hydrologists and manipulated to track the performance of

the wellfield. The processed data was stored and shared on the hydrologist’s computers.

4.2.2 Pre-Leach Aquifer Pump Tests

BHP staff conducted four pumping test at the 5-spot wells BHP-1, BHP-2, BHP-4, and BHP-5. The

wells are screened approximately 400 ft in the oxide bedrock (Table 3-1). When one well was

pumped, the remaining four wells were used as observation wells. Each test lasted from one day to three days; the water levels were allowed to recover between the test intervals. The observation

wells showed drawdown responses that resemble the Theis curve for equivalent porous media. The

drawdown in all the wells shows a linear relationship between the period of 10 minutes and 1,000

minutes. Then the curves become flatter due to inflow (leaky) from the upper basin-fill aquifer. BHP concluded that based on the four pump tests there is heterogeneity and/or anisotropy within the

oxide zone in the location of the field test location.

The hydraulic conductivity and storativity values generated from these aquifer tests were calculated using AQTESOLV (Duffield, 1996) (software for the analysis of pumping tests and slug tests) are

summarized in Table 4-3. The Theis solution was used, which assumes that the rock is

homogeneous and isotropic. The mean hydraulic conductivity was about 0.6 ft/day and storativity was 0.0007. When the pumping well and observation well were switched, the hydraulic

conductivities obtained were very similar, which was interpreted to be an indication that the data

were very reliable (BHP, 1997d).

Table 4-3 Hydraulic conductivity and storativity from the oxide aquifer tests

Aquifer Test Observation Well K (ft/d) Storativity

BHP-1 BHP-2 0.6 0.001200

BHP-1 BHP-3 0.6 0.00042

BHP-1 BHP-4 0.4 0.00033

BHP-1 BHP-5 0.9 0.00069

BHP-2 BHP-1 0.6 0.00120

BHP-2 BHP-3 0.8 0.00140

BHP-2 BHP-4 0.5 0.00063

BHP-2 BHP-5 0.7 0.00024

BHP-4 BHP-1 0.3 0.00038

BHP-4 BHP-2 0.5 0.00059

BHP-4 BHP-3 0.5 0.00037

BHP-4 BHP-5 0.5 0.00090

BHP-5 BHP-1 0.9 0.00075

BHP-5 BHP-2 0.8 0.00020

BHP-5 BHP-3 1.0 0.00074

BHP-5 BHP-4 0.5 0.00096

Average 0.6 0.0007

Source: BHP, 1997d

SWVP-026411



4.2.3 Groundwater Injection Tracer Test

The groundwater injection test was designed and performed to estimate the effective porosity of the

oxide zone as well as the solution dispersion, travel times, and the flow paths that the injected

solution takes. Prior to obtaining the APP the introduction of salt, dyes, and artificial tracers into the oxide zone was not allowed. In lieu of this, an alternate solution of using the distinct chemical

composition of the upper or lower basin aquifer as a tracer was chosen.

Upper basin-fill water from well M10-GU was continuously injected into the central well, BHP-1, at

an average rate of 53 gpm for almost 2 months while wells BHP-2 through BHP-5 were extracting about 13 gpm. Sulfate was used as a tracer to detect the breakthrough curve and assess the reason

for differences in the sulfate mass extracted from each well. The electrical conductivity (EC) of

M10-GU water (1,900 µS/cm) is about twice that of the oxide groundwater (850 µS/cm). Sulfate concentration in the UBFU is about four times higher than that of the oxide water (260 mg/L vs. 60

mg/L).

The breakthrough curves for electrical conductivity and sulfate at extraction wells can be seen in

Figure 4-5 and Figure 4-6. During the first few days, the EC of BHP-3 was at a high level indicating effects of residual drill mud (Figure 4-5). The EC of BHP-3 started to decrease as the well was

pumped and purged of the remaining drilling mud. As the UBFU water reached BHP 3, the EC

curve stopped decreasing. It flattened and started rising as more M10-GU water swept through the oxide water around the BHP-3 area. This behavior was not observed in the sulfate breakthrough

curve of this well because the drilling mud was not high in sulfate content (Figure 4-6).

Almost all extraction wells showed increases in concentration after four days with the exception of BHP-2, whose breakthrough occurred after 18 days. BHP-4 had the greatest sulfate concentration

response of all four pumping wells; its sulfate concentration had increased by three fold by the end

of the test. The sulfate concentration at BHP-3 and BHP-5 had increased by 2.3 fold, while at BHP-

2 it slowly increased by 1.3-fold. BHP-2 was completed in a sliver of quartz monzonite sandwiched by parallel Tgdp dikes. It is apparently isolated from BHP-1 and the other BHP wells by two faults

identified in televiewer logs, as shown on the geologic section on Figure 4-7. These faults, if they

contain significant clay gouge, might cause the low hydraulic conductivity zone around BHP-2.

Source: BHP, 1997d

Figure 4-5 Electrical conductivity breakthrough curves during groundwater injection test

Electrical Conductivity during Water Injection Test

700

900

1100

1300

1500

3/10/97 3/20/97 3/30/97 4/9/97 4/19/97 4/29/97

Time

EC

(m

icro

mh

os/c

m)

BHP2

BHP3

BHP4

BHP5

BIA 10 on

SWVP-026412



Figure 4-6 Sulfate breakthrough curves during the groundwater injection test

Figure 4-7 Diagonal NW-SE section (looking southwest) showing screened intervals in undifferentiated bedrock and the faults between BHP-1 and BHP-2

Sulfate Concentration during Water Injection Test

40

60

80

100

120

140

160

180

3/10/97 3/20/97 3/30/97 4/9/97 4/19/97 4/29/97

Time

Su

lfate

(m

g/L

)

BHP2

BHP3

BHP4

BHP5

BIA 10

on

SWVP-026413



4.2.4 Numerical Modeling

BHP used numerical modeling as a preliminary assessment of transport and movement of solution in

the oxide aquifer at the field test location. The flow model was constructed using MODFLOW

(McDonald and Harbaugh, 1988). Subsequently, the computed heads and cell-to-cell fluxes were utilized in MT3D (Zheng, 1990) for the simulation of transport.

The computer model incorporated available data on hydrologic and geologic conditions, aquifer

properties, and water quality to simulate groundwater flow and advective-dispersive transport of a

conservative species within the aquifer. The porosity and longitudinal dispersivity in the oxide zone were calibrated against sulfate breakthrough data in four observation wells approximately 70 feet

from the sulfate source.

The hydraulic configuration that best matched the observed drawdown patterns in the four aquifer tests is shown in Figure 4-8. This figure shows the detailed two-dimensional K zones within the 5-

spot, the K values for the rest of the oxide area had values of 0.6 ft/d. It was necessary to use a low-

K (0.05 ft/d) trend cutting southwest to northeast between BHP-1 and BHP-2 and an almost no-flow

zone (K = 0.01 ft/d) northwest of BHP-4 to reproduce all four oxide aquifer tests.

Source: BHP, 1997d (Red dots indicate the 5-spot wells). Colors indicate K (ft/d) zones: brown = 0.01, orange = 0.05, yellow = 0.1, green

= 0.3, blue = 0.5 or 0.85, purple = 0.6

Figure 4-8 Hydraulic conductivity zones within the oxide bedrock in the 5-spot

4.2.5 Estimation of Porosity and Dispersivity

Effective porosity is the ratio of pore volume allowing movement of fluid to total volume of the

rock, be it porous or fractured. Hydrodynamic dispersion accounts for velocity variations that cause spreading of contaminants over greater and smaller distances than would be calculated by the

average seepage velocity of groundwater alone. This parameter lumps variations in velocities due to

“small” scale heterogeneities which are unknown. By using the numerical model of groundwater

flow coupled with the solute transport model, BHP hydrologists attempted to estimate porosity and dispersivity in the field test by adjusting them during calibration. These parameters were adjusted

until the distribution of the solute concentration approximates measured data. The solute transport

SWVP-026414



model, MT3D, was calibrated to the 5-spot water injection data. Using an effective porosity of 10

percent in the oxide aquifer, the numerical model reproduced a fairly good match with measured sulfate concentrations during the first three weeks of the 5-spot tracer test (Chong-Diaz, 1997).

The 10 percent porosity estimate was higher than the previous estimate of 2 percent (B & C, 1996b,

p. 2-12). If this higher porosity value is generally true, it substantially reduces the risk of pore clogging and decrease of fluid flow due to mineral precipitation during the in-situ leaching process.

Further, the lixiviant may be contacting more exposed ore area. However, a higher volume of

lixiviant than previously calculated will be needed to fill the oxide aquifer before copper starts to be extracted.

4.2.6 Evaluation of Hydraulic Control

For environmental and operational purposes, the injected solution must be contained horizontally and vertically) and recovered. The horizontal control prevents lateral excursion of injected solution

to the regional groundwater outside the mining block. The vertical control prevents the vertical

excursion to the aquifer in the LBFU. In the wellfield design, horizontal hydraulic control was

maintained by inducing and sustaining hydraulic gradients inward by pumping from perimeter wells BHP-10, BHP-11, BHP-12, and BHP-13. The vertical hydraulic control is achieved by the

combination of excess extraction and completing the wells 40 ft below the LBFU, leaving a buffer

zone below the LBFU contact with the top of oxide zone.

B & C simulated a specific mine block with flow and particle tracking using MODFLOW and

PATH3D as part of the APP demonstrations. The wells were in a 5-spot pattern, and all the

perimeter wells were recovery wells. The injection and recovery rates for all interior wells were 0.1 gpm per foot of well screen. Based on mass balance of injection and withdrawal, the recovery rates

of exterior wells were calculated. To establish hydraulic control of the mine block, the exterior wells

were pumped at elevated rates. In the simulation, exterior recovery wells were pumped at 25 percent

over the calculated base rates needed to achieve total injection equal to the total withdrawals.

Particle tracking was used to demonstrate the hydraulic control. Fifteen particles were introduced to

the injection solution at the injection wells and then traveled with the solution. Hydraulic control

was successful if all the particles were recovered in the recovery wells. Otherwise, the excess pumping at exterior wells would need to be increased to achieve the hydraulic control. The results of

the simulations by B & C (1996c) showed that hydraulic control could be achieved when perimeter

wells are pumped at 25 percent over the base rates.

An interior five-spot within the wellfield was used to demonstrate the vertical control. A simulation

was performed that injected solutions 40 ft below the contact of oxide zone and overburden.

Artificial particles were introduced to the solution to track the solution movement. A small wellfield

consisting of 13 wells was used to demonstrate the vertical control near the wellfield boundary (B & C, 1996c). The results showed particle tracking of solution movement from an injection well to a

recovery well. No solution was moved into the LBFU under simulated wellfield conditions (B & C

(1996c).

Following the groundwater injection test at the 5-spot, BHP performed a numerical simulation of

horizontal and vertical spreading that might occur after 10 and 365 days of raffinate injection into the

oxide zone using the field test configuration (BHP, 1999). Their simulation indicated a small portion

of the injectate would migrate horizontally to the observation wells located 50 ft beyond the outer recovery wells. In addition, the simulation forecast that the injectate would move 20 to 40 ft up into

the LBFU at the end of one year. The simulation assumed no change in hydraulic conductivity

during the one-year time frame. Laboratory tests on LBFU drill core indicated that the permeability of this material could be reduced by 50 percent in reaction with raffinate solutions owing to mineral

precipitation.

SWVP-026415



Profile looking north through field test with 20-ft simulation layers shown in red and black symbols. Recovery well BHP-12 (left), BHP-1

(center), and BHP-10 (right) are shown in black. Injection wells BHP-8 (left) and BHP-6 (right) are shown in red. Simulated sulfate

contours at various concentrations are shown flaring up a few feet above the top of bedrock into the LBFU. BHP, 1999.

Figure 4-9 Simulated vertical concentration profile between injection wells BHP-6 and BHP-8

4.2.7 Sweep Efficiency Estimation

Sweeping efficiency can be defined as the ratio of volume of medium contacted by injected fluid

(e.g., raffinate) to total volume of porous/fractured medium. The solution movement within a well could be different from a neighboring well. The area contacted by solution as a function of time is

called sweeping. Using the data provided by the hydrophysical tests, BHP hydrologists calculated

the estimated sweep efficiency.

Curves of concentration versus time or pore volumes from each discretized oxide layer were plotted.

A table with relationship between pore volume and percent of area contacted by the injected solution

was created. Using hydrophysical data and the table of pore volume and percent of contacted area;

the sweep efficiency for 11 wells were derived. The average sweep efficiency for these 11 representative wells at various locations around the deposit reached 75 percent within three pore

volumes in the path between the injection and extraction wells. A sweep efficiency of 80 percent

was ultimately selected as reasonable estimate for the average operations time period of 5 years.

4.2.8 Well Clogging Considerations

Injection wells typically develop resistance to flow over time owing to well clogging processes

(Pyne, 1990). At the San Manuel ISR operation, for example, gradual well clogging developed in the form of reduced injection capacity and development of no-flow zones through portions of the

screened intervals in the injection wells (as shown by spinner logs). The different clogging

mechanisms include:

Drilling mud residues and mud cake on the borehole wall,

Chemical precipitation in bore holes,

Suspended solids in the injectate solution,

0.050.100.200.300.400.50

0.700.80

0.95

UBFU

OXIDE

LBFU

MFGU

MODFLOW BC Symbols

Well

Point Source/Sink

MT3D BC Symbols

SWVP-026416



Microorganisms (particularly fungi), and

Entrapped air bubbles or air entrainment owing to cascading leach solution in the injection wells.

All of these clogging mechanisms result in a reduced permeability (“skin” effect) around the wells.

San Manuel raffinate was used during the Florence field test and was filtered on site as described in

Section 3.2. A combination of dual media filters and activated carbon filters were used for the

raffinate to filter out both solids and microorganisms. Three-micron filters were used for the added

sulfuric acid and make-up water. In order to minimize potential air entrainment, the injection pipes were extended below the water level. The use of acid-resistant grout to cement the well casings was

intended to eliminate one source of gypsum precipitation. Drilling and well installation techniques,

as well as solution handling, were tailored to reduce well clogging and to minimize damage to the bedrock. Clogging did occur, however, primarily as a growth of an amorphous aluminum silicate

and algae seen in selected wells during the injection of evaporation pond water during post-test

rinsing.

4.2.9 Well Bromide Tracer Test Post-Leaching

Following the 101 days of raffinate injection (10/31/1997 to 2/9/1998) of the field test area, the

reclamation phase began. During reclamation, a tracer test using bromide was conducted. Groundwater from well WW-4 (3,000 feet away) and sodium bromide solution were mixed together

with an inline mixer. The mixed solution, with bromide concentration of 54 ppm, was injected into

BHP-1 at 55 gallon per minute for 45 hours. The injected solution was recovered from BHP 2

through BHP-9. The average total pumping rate was 93 gpm. After this time, only groundwater was injected into BHP-1.

The relative concentrations vs. time curves are presented in Figure 4-10. Figure 4-11 shows a

diagrammatic representation of how much solution reached each pumping well. About 56 percent of the injected bromide had been recovered in a 30-day period; the average pumping rate is also shown.

Of note was the fact that the percentage of bromide solution recovered at the pumping wells was not

proportional to the pumping rate or distance from the injection well. For example, BHP-7 pumped at only 7 gpm and recovered 12 percent bromide; BHP-6 being at an equal distance of 50 ft from the

injection well, pumped at a higher rate of 11 gpm but received only 9 percent bromide. BHP-8 and

BHP-9 are of equal distance from the injection well and had a similar pumping rate of 12 gpm, but

they had different results. Fifteen percent of bromide reached BHP-8 and only 6 percent bromide reached BHP-9. BHP-2 and BHP-3 pumped at 7 gpm, but BHP-2 did not recover any bromide and

BHP-3 recovered only 2 percent. BHP hydrologists interpreted this to mean that differences in

heterogeneity and communication existed in the field test site.

The pre-leach groundwater (sulfate) injection tests also indicated the isolation of BHP-2 from BHP-1

and the other BHP wells. The heterogeneity noted in the tracer test response may be influenced by

local geologic conditions. BHP-2 is sitting within a sliver of quartz monzonite that is sandwiched between two E-W striking porphyry dikes and is isolated from BHP-1 and the other BHP wells by

two faults (Figure 4-7).

SWVP-026417



Figure 4-10 Relative Br concentration vs. time curves (BHP, 1999)

Br Field Test

Relative Concentration vs Time

Injected 50 ppm for 2 days into BHP1

-0.20

0.00

0.20

0.40

0.60

0.80

1.00

05/13/98 05/18/98 05/23/98 05/28/98 06/02/98 06/07/98 06/12/98

Day

Rel. C

on

c. (p

pm

)BHP2

BHP3

BHP4

BHP5

BHP6

BHP7

BHP8

BHP9

BHP10

CH1

CH2

Br Field Test

Relative Concentration vs Time

Injected 50 ppm for 2 days into BHP1

-0.05

0.00

0.05

0.10

0.15

0.20

0.25

0.30

05/13/98 05/18/98 05/23/98 05/28/98 06/02/98 06/07/98 06/12/98

Day

Rel. C

on

c. (p

pm

)

BHP2

BHP3

BHP4

BHP5

BHP6

BHP7

BHP8

BHP9

BHP10

CH1

CH2

SWVP-026418



Source: BHP, 1999

Figure 4-11 Diagram representation of Br percentage reaching pumping wells

4.2.10 Summary of Injection and Tracer Tests

The results of the pre-leach groundwater (sulfate) injection test, the raffinate injection phase, and the post-leach bromide tracer test are summarized and compared in this section. The three injection tests

were performed using different well configurations, groundwater compositions, and pumping rates.

Although the physical area tested and the wells involved are slightly different, a qualitative comparison can be made to summarize the local response seen in the wellfield during each test. The

duration of the tests and the tracked constituents are summarized in Table 4-4. The question to be

answered is whether the responses seen in any particular injection test can provide valuable ground-

truth information that would allow a qualitative or quantitative forecast on the potential behavior seen during raffinate injection.

North

6 % Br

50 ppm Br injected into BHP1 at 54gpm. A Total of 27 Kg Br after 45hours. RECOVERED 57% Br in 1 monthperiod.

BHP9

BHP6

BHP7

BHP8

BHP4

BHP2BHP5

BHP3

BHP10

(13 gpm) (12 gpm) (7 gpm)

(12 gpm) (7 gpm) (7 gpm)

(12 gpm) (11 gpm) (6 gpm)

BHP11

BHP12

BHP13

owb1

owb3

owb4owb5

12 % Br

15 % Br

10 % Br 2 % Br

0 % Br

9 % Br

0 % Br

3 % Br

SWVP-026419



Table 4-4 Duration of injection tests

Groundwater Injection Test

(sulfate)

Raffinate Injection

(sulfate)

Groundwater Injection Test

(bromide)

Begin inject 3/12/97 10/31/97 5/13/98

End inject 5/8/97 2/8/98 45 hours

Begin inject water NA 2/19/98 5/15/198

End inject water NA 5/12/98 7/17/98

Note: The pre-leach groundwater-injection test used M10-GU well water. WW-4 well water was used during the raffinate-injection period

and during the bromide tracer test.

As described previously in Section 4.2.3, M10-GU groundwater that was pumped from the UBFU

and contained an average of 260 mg/L sulfate was injected into BHP-1 (60 mg/L sulfate). BHP-2,

BHP-3, BHP-4, and BHP-5 were pumped during the injection test that lasted 77 days from 3/12/1997 to 5/27/1997. A contour map based on the relative percentage of the mass of sulfate

recovered in each of the corner wells from 3/12 to 5/8/97 is shown on Figure 4-12. As shown, sub-

equal amounts of sulfate (~25%) were recovered from BHP-3 and BHP-5 in a N45E trend; the

greatest percentage (31%) was recovered in BHP-4 in the northwest corner; BHP-2 recovered the least percentage (18%).

During the raffinate-injection phase, injectate containing 10,000 to 6,000 mg/L sulfate was injected

in BHP-6, BHP-7, BHP-8, and BHP-9 with inner recovery wells BHP-1 through BHP-5 and outer recovery wells BHP-10 through BHP-13. Figure 4-13 presents a contour map of the percentage of

sulfate mass recovered from each well through May 12, 1998. The majority of the sulfate mass

extracted during this period was recovered from BHP-1 (35%), which was pumped at a rate of approximately 40 gpm. BHP-5 extracted 19% of the sulfate extracted and was pumped at a rate of

approximately 19.3 gpm. The outer perimeter wells recovered 5 to 8% of the mass extracted with

pumping rates ranging from 10.4 to 13gpm. Once again the major principal axis of sulfate extraction

is along a NE-strike.

The post-leach bromide tracer test is described in Section 4.2.9. Bromide was injected into BHP-1 at

a concentration of 54 mg/L bromide for 45 hours. Recovery wells BHP-2 through BHP-9 were

pumped at a total rate of 93 gpm. Following the 45-hr bromide injection, groundwater was injected for about 2 months. Figure 4-14 presents a map that contours the percentage of total cumulative

sulfate pounds extracted in a one month period (45 days of bromide injection followed by

groundwater injection). During this time, 56 percent of the total bromide injected was recovered.

SWVP-026420



Prepared by SRK, 2010

Figure 4-12 Contoured percentage of sulfate mass recovered during pre-leach groundwater injection test (3/12/1997). BHP-1 is the injection well.

Figure 4-13 Contoured percentage of sulfate mass recovered during raffinate injection and rinsing phase (10/31/1998 to 5/12/1998). BHP-6 through BHP-9 are injection wells.

SWVP-026421



Figure 4-14 Contoured percentage of bromide recovered by well during bromide tracer test (5/13/1998 to 7/17/1998)

4.2.11 Flow and Transport Modeling

Numerical inverse modeling was used to calibrate hydraulic parameters in the oxide zone, based on

the field test results. The flow distribution was simulated using MODFLOW, a flow model

developed by the U.S. Geological Survey (McDonald and Harbaugh, 1988). The tracer movement

was simulated using MT3D, a transport model that considers advective and dispersive processes (Zheng, 1990). The inverse calculation was conducted using the Parametric Estimation software,

PEST.

To calibrate the parameters, an initial estimation of these parameters was put in the models. The results of the simulations were then compared with field data. If the match was not satisfied, the

hydraulic parameters were adjusted by PEST, and simulations were repeated until a satisfactory

comparison of field data and simulation results was achieved. The interference pumping test data

were used to calibrate the distribution of hydraulic conductivity. The water injection test data were used to calibrate the dispersivity, and effective porosity. Because of the heterogeneous nature of the

rocks, the calibration is usually non-unique. However, the major features within the area surrounded

by the wells will be captured.

The model grid covered an area of 7,000 feet by 7,000 feet within the test site and 640 ft of depth.

The grid design was characterized by non-uniform cell spacing of 10 feet (middle cells), 20 feet, 40

feet, 60 feet, 135 feet, and 140 feet, which encompassed the boundary of 7000 ft by 7000 ft. The wells were positioned in the inland block, separated (discretized) in 10 feet x 10 feet cells. The grid

perimeter cells were assigned constant head boundary conditions. The vertical dimension of the

model was discretized into 3 layers. The top layer covered the lower basin fill unit. The second

layer covered the top 40 feet of oxide. The bottom layer covered the rest of the oxide. All the layers were considered to be confined aquifers. The transmissivity values were allowed to vary and were

SWVP-026422



calculated from the saturated thickness and hydraulic conductivity. The storage coefficients were

considered to be uniform.

The test area was divided into 37 distinct zones. A high conductive zone and two low conductive

zones were introduced along BHP-5 and BHP-9, based on the examination of pumping data and

tracer data as well as the geological features. Some zones were combined as one zone during the calibration process to reduce the number of parameters, in order to reduce the computation time and

enhance the certainty of calibration.

Figure 4-15 shows the field drawdown curves and the calibrated curves. The hydraulic conductivity results show a zone connecting BHP-5 and BHP-9 that has significant differences with the

surrounding rocks. The value of the high conductive zone was 5 ft/day, sandwiched by the low

conductive zones of as low as 0.1 ft/day. This feature indicated that there was a short circuit

between BHP-5 and BHP-9. The wellfield was separated into two somehow isolated areas.

The SO4 concentration curves of the calibration and field water injection test data are shown in

Figure 4-16. The dispersivity value obtained was 70 ft and the effective porosity was 6 percent.

This was consistent with the previous studies (Orr, 1997). The match was surprisingly good, considering that the dispersivity value and the effective porosity were treated uniformly. It was

found that introducing more zones of dispersivity and effective porosity only slightly improved the

match.

The bromide test was not used to calibrate the model because the bromide test was conducted after three months of leaching. The conditions of rock had been changed since the pumping tests and pre-

leach water injection test were conducted. However, the test was used to validate the numerical

simulations, as shown in Figure 4-17. The match is qualitatively good. The slower arrival time in test data indicates the porosity increased due to the leaching of minerals.

In summary, the approach of equivalent porous medium embedded significant discrete features

matches the field data very well in such a highly fractured and heterogeneous rock, as was found by Neuman (1982).

SWVP-026423



Source: BHP, 1999, Comparison of observed (blue) and model simulated (pink) drawdown results, statistical data (yellow and cyan).

Figure 4-15 Field drawdown curves and the calibrated drawdown curves

BHP2

-2

3

8

13

18

1 10 100 1000 10000

minutes

BHP3

-2

3

8

13

1 10 100 1000 10000

minutes

BHP4

-2

3

8

13

1 10 100 1000 10000

minutes

BHP5

-2

3

8

13

18

23

1 10 100 1000 10000

minutes

BHP6

-2

3

8

13

1 10 100 1000 10000

minutes

BHP7

-2

3

8

13

1 10 100

minutes

BHP8

-2

3

8

13

18

1 10 100 1000 10000

minutes

BHP9

-2

8

18

28

38

1 10 100 1000 10000

minutes

BHP10

-2

3

8

13

1 10 100 1000 10000

minutes

BHP12

-2

3

8

13

18

1 10 100 1000 10000

minutes

BHP13

-2

3

8

13

18

1 10 100 1000 10000

minutes

OWB1

-2

3

8

13

1 10 100 1000 10000

minutes

OWB3

-2

0

2

4

6

8

1 10 100 1000 10000

minutes

OWB4

-2

3

8

13

18

1 10 100 1000 10000

minutes

OWB5

-2

3

8

13

1 10 100 1000 10000

minutes

SWVP-026424



Source: BHP, 1999

Figure 4-16 Relative concentrations seen in sulfate field data and calibration results

Source: BHP, 1999

Figure 4-17 Simulated (magenta) and measured (dark blue) bromide concentrations in BHP-6, BHP-7, BHP-8, and BHP-9

-0.10

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0 10 20 30 40 50 60 70

day

rela

tive

co

nce

ntr

ati

on

BHP2 meas

BHP2 calc

BHP3 meas

BHP3 calc

BHP4 meas

BHP4 calc

BHP5 meas

BHP5 calc

BHP6 Br Test

-0.2

-0.15

-0.1

-0.05

0

0.05

0.1

0.15

0.2

0.25

0.3

0 5 10 15 20 25 30 35

Day

Rela

tive C

on

cen

trati

on

0

0.2

0.4

0.6

0.8

1

1.2

Weig

ht

Measured

Calculated

Residual

Weight

BHP7 Br Test

-0.05

0

0.05

0.1

0.15

0.2

0.25

0.3

0 5 10 15 20 25 30 35

Day

Re

lati

ve

Con

cen

tra

tio

n

0

0.2

0.4

0.6

0.8

1

1.2

Weig

ht

Measured

Calculated

Residual

Weight

BHP8 Br Test

-0.05

0

0.05

0.1

0.15

0.2

0.25

0.3

0 5 10 15 20 25 30 35

Day

Re

lati

ve

Con

cen

tra

tio

n

0

0.2

0.4

0.6

0.8

1

1.2

Weig

ht

Measured

Calculated

Residual

Weight

BHP9 Br Test

-0.05

0

0.05

0.1

0.15

0.2

0.25

0.3

0 5 10 15 20 25 30 35

Day

Re

lati

ve

Con

cen

tra

tio

n

0

0.2

0.4

0.6

0.8

1

1.2

Weig

ht

Measured

Calculated

Residual

Weight

SWVP-026425



4.2.12 Hydraulic Containment Results

Injection of sulfuric acid solution started on October 31, 1997. The leaching solution was made of

groundwater from Florence, concentrated sulfuric acid from San Manuel, and San Manuel raffinate.

The injected solution had an average pH of 1.6.

The wellfield was operating at a total injection rate of 122 gpm and a total recovery rate of 150 gpm.

Table 4-5 presents the average injection and pumping rates for the wells. The rates declined with

time owing to the clogging of pumps. The pumping rate was kept low thereafter. The problem was

solved later by injecting raffinate around pumps to dissolve the precipitation on the pumps. Injection rates ranged between 21 to 35 gpm per well. Pumping rates in the inner recovery wells ranged

between 14 to 19 gpm per well. Pumping rates in the perimeter recovery wells ranged between 10 to

13 gpm. The total pumping rates have been kept larger than the total injection rates, based on permit requirements. The net pumping and injection rates are shown in Figure 4-18. BHP-1, which is

surrounded by the four injection wells, was the main recovery well and pumped at an average rate of

39 gpm.

The depth to water data for the BHP test wells and the six observation wells (OWB series) during the leach test on February 2, 1998 were used by SRK to create a groundwater elevation contour map.

The map shown on Figure 4-19 shows the hydraulic containment of the injection wells, BHP-6,

BHP-7, BHP-8, and BHP-9.

Table 4-5 Average injection and pumping well rates during leaching phase

Well ID Average Injection (gpm)

Well ID Average Pumping (gpm)

BHP6 32

BHP1 39

BHP7 35

BHP2 14

BHP8 21

BHP3 17

BHP9 33

BHP4 16

Sum 121

BHP5 19

BHP10 11

BHP11 11

BHP12 10

BHP13 13

Sum 150

Source: BHP, 1999

SWVP-026426



Figure 4-18 Net positive pumping rate in the wellfield (BHP, 1999)

Source: Prepared by SRK in Surfer using February 2, 1998 BHP water level records

Figure 4-19 Potentiometric map for February 2, 1998 (contours in ft amsl)

Inflow vs. Outflow Rates

0

20

40

60

80

100

120

140

160

180

200

10/31/97 12/30/97 02/28/98 04/29/98 06/28/98 08/27/98 10/26/98 12/25/98 02/23/99 04/24/99

Rate

(g

pm

)Injectate to f ield

Total Flow from Field

SWVP-026427




In general the hydrogeologic study of the mine site and of the pre-leaching 5-spot area addressed all

of the areas of concern.


Listed below are a few brief comments related to hydrological aspects of a future field test and full-

scale operations.

4.4.1 Data Management

Management of well construction data, water quality analyses, water levels, and equipment

installation and maintenance records will be an on-going concern in the future field test and during

full operations. Installation and development wells and their associated facilities will generate volumes of data that will be required for assessing the success of the ISR operation and to meet

ADEQ and UIC compliance requirements. A data collection plan and a Sampling and Analysis Plan

(SAP) must be developed to ensure all data are collected at the proper source, at the proper time, and

by the proper means. The plans need build on any available operations plans previously prepared to address normal operation and contingencies, such as device failures and power outages. The SAP

should address quality assurance methods water quality monitor wells including sampling, data

downloads, water level and other field measurements. Sampling personnel should be thoroughly trained in sampling protocols to ensure the quality of the program is maintained.

Data will be generated by hand entries into logs books, data capturing devices, and reports. The data

should be stored so that it can be easily accessed, can be uploaded simply, captures all required elements, is backed up, and secure.

Data Capture

Hand entry – Data that is hand entered is the likely to contain errors. Errors are potentially generated when the device is read, when the data are entered into the log, and when the logged data are entered

into an electronic file. Capturing and handling of data in this fashion should be minimized.

Handheld instruments used to capture data should have a data logger that can download to a computer.

Data capturing devices – Devices connected to equipment that automatically capture and record data

should have sufficient memory to store all data for the period of time between downloads plus a

reserve. The device also needs sufficient power to maintain full operations between battery replacements or external power outages. The devices must also be secured from the environment

(heat, wind, strong rain) and vandals.

Data reporting – Reports generated from laboratories should include an Electronic Data Deliverable file. These files should be received in a format that is easily uploaded to the sampling database and

has all information that may be needed including method detection limits, and potential issues with

interferences or varying dilutions that can occur when laboratories analyze process solutions.

Once data are received they should be verified for completeness, correctness, and conformance; then validated to determine its analytical quality. These two steps will ensure the data meets the

requirements of the data collection plan and the SAP.

A database provides the best means of storing, displaying, and reporting site data. Several commercial products are available that provide water quality database formats for analyses,

compliance exceedance alerts, graphs, mapping, scheduling, and reporting. These products are well

developed and tested. They can be installed, running, and operational in minimal time after some training. Another option is to use a commonly available database, such as Microsoft Access, which

would need to be tailored to the site requirements. Graphing routines, data entry forms, reports, and

SWVP-026428



queries would need to be developed, and tested. This process tends to be time consuming and

involves staff members very familiar with input characteristics and output requirements to develop the database structure. Staff training is required for data input and a data supervisor is needed.

Owing to the inability to foresee all requirements, additional development is typically required.

Additionally, such systems do not possess some features that the more sophisticated commercial products offer, e.g. mapping, alerts, and scheduling.

SWVP-026429



5 Geochemical Characterization The major source of information that can be used to interpret the progress of leaching reactions

within an in-situ wellfield is the composition of the effluent solution. These compositions must be

interpreted in conjunction with experimental and theoretical studies into the behavior of the various components during reactions with the various mineral associations present in the Florence deposit.

The test was terminated upon a successful demonstration of hydraulic control according to permit

requirements, but before economic copper leaching was successfully demonstrated. The copper recovery curve required for economic models must therefore be extrapolated from the results of this

test, through the use of a reactive transport model. This section provides the experimental and

theoretical background for the interpretation of the Florence field test geochemistry, the analytical data from the leaching and remediation portions of the test, and results of reactive transport model.

5.1 Summary of Metallurgical Test Work

Magma and BHP conducted numerous mineralogy, bottle roll, column leach tests, and chrysocolla

dissolution studies during their respective pre-feasibility studies (Appendix 3, Magma, 1995;

BHP1997d), which are briefly summarized below. Representative samples were selected for the test work by geologists familiar with the deposit rock types, mineralogy, alteration, and assay grade

populations. The metallurgical tests used NX/NQ-diameter drill core and 6-inch diameter drill core

and targeted the dominant rock types and grade ranges. Magma studies were designed to assess leach recovery and acid consumption under heap leach conditions; the tests were performed by

McClelland Laboratories, Inc. of Sparks, Nevada using small- and large-diameter drill core.

BHP’s pre-feasibility metallurgical program was initiated in 1996 to provide information for the

design and planning of the ISR operation. Representative samples selected for testing consisted of materials to be leached within the first 5 to 7 years of operation. The program was designed to

address technical issues that had been identified from previous work. These mainly consisted of

estimating the amount of copper-bearing minerals that could be contacted with acidic solutions and the geochemical behavior of fluid-rock interactions. The metallurgical program consisted of

mineralogical studies, cation-exchange experiments to evaluate the removal of copper from smectite

clays, bottle roll tests to determine copper mineral solubility and acid consumption in sulfuric acid lixiviant, and column leach tests to determine aspects of copper leaching, kinetics (time-recovery),

likely leach solution chemistry, and reclamation chemistry. Limitations in the column-test work

program and results were related to the inability to replicate completely the hydrologic conditions

and porosity existing in the saturated bedrock. Solution velocities, contact time, and fluid-to-rock ratios can be considerably different in unsaturated column tests or heap leach materials versus in-situ

conditions.

5.1.1 Summary of Previous Test Work

Development of the Florence copper resource was begun by Conoco in 1971, and various leaching

tests and mineralogical characterization studies were carried out by Hazen Research, Inc. from 1971

through 1974 (Conoco, 1976). Most of the Hazen work comprised bottle roll and mechanically agitated leaching tests. In about 1972, a decision was made to adopt vat leaching of finely crushed

copper oxide mineralization with a cut-off grade of 0.3% TCu. During 1972–74, the vat-leaching

concept was refined by tests that explored the influence of particle size, temperature, and free acid concentration on leaching kinetics. Recognizing the relatively brief duration of a commercial vat

leaching cycle (7 to12 days), the tests were focused on achieving 70–76 percent copper dissolution in

less than 10 days, and preferably 2–4 days, in the interest of minimum acid consumption. The Hazen

program concluded with a pilot-scale vat-leaching test in 1976.

In 1994, McClelland Laboratories, Inc. conducted 19 bottle roll tests and 4 column tests as part of a

study that was designed to compare the feasibility of an open pit, heap leach operation with in-situ

SWVP-026430



leaching and recovery (Magma, 1994). The tests were made on drill core samples obtained during

the Magma pre-feasibility assessment and were intended to complement the Conoco effort. The bottle roll leach tests dissolved 40–80 percent of the total copper in the samples and approximately

65–75 percent dissolved during column leaching.

In 1995, 19 column tests were performed under the direction of B & C (1996) as a part of the work needed to apply for an Aquifer Protection Permit (APP). Seventeen of the tests examined the acid

neutralization capacities of various rock types and basin-fill sedimentary units. Two other column

tests were run in order to determine pregnant leach solution (PLS) composition after leaching at pH 1.5 with recycled SX raffinate. Head assays were not obtained, but the columns produced maximum

PLS grades of 3.8 grams per liter (g/L) and 8.4 g/L Cu and the estimated leachable copper content of

the samples equated to 0.56% Cu and 0.84% Cu, respectively.

The laboratory tests conducted by Hazen, McClelland, and B & C followed procedures normally used to enable scale-up of metallurgical response to conventional vat, heap, or agitated leaching and

generally did not yield data of direct use in designing in-situ recovery. For example, solution

flowing between injection and recovery wells must pass through typically 50 to 100 feet of mineralized formation without pH adjustment, whereas the early tests incorporated periodic acid

addition to maintain a nearly constant free acid concentration. Nonetheless, those tests did provide

useful information about response variability and maximum likely copper solubilization.

BHP set out to design experiments that would more closely simulate in-situ conditions by saturating the column sample with leaching solution, by using lower solution flow rates, and by altering

solid/liquid contact and fluid retention. The last two techniques were to involve coating large-

diameter core samples with epoxy and filling the cavities in the column charges with inert silica sand.

Chrysocolla (hydrous copper aluminum silicate) at Florence has been known for decades to have

variable copper content ranging from the theoretical concentration of 36.2 weight percent copper to a low of approximately 18 weight percent. Examinations by Adrian Brown Consultants, Inc.

(Williamson, 1996) as well as by Davis (1997) and Brewer (1998) revealed a highly variable

composition with aluminum ions typically substituting for copper in a layer silicate lattice. Some

mineral grains can contain only a few percent copper and will be only faintly bluish in color. During leaching with raffinate, the copper silicates initially dissolve congruently with silica until the

leaching solution becomes silica-saturated and only copper dissolution is favored. A rough

quantification of this type of mineralization versus the percent of copper-bearing mineralization located dominantly on fractures is noted for each assay interval in the drill logs and in the project

database.

5.1.2 Bottle Roll Tests

Bottle roll tests are bench-scale leach procedures designed to evaluate, rapidly and inexpensively, the

solubility of copper mineralization in a sulfuric acid lixiviant. Mineralization from the Florence

deposit had been analyzed with bottle roll leach tests during preliminary project evaluation by Conoco, and again with slightly different bottle roll tests during the Magma pre-feasibility study.

Sample material in both cases consisted of assay rejects from drill core; other parameters for each

type of test are presented in Table 5-1. The listed test parameter differences generally result in only

slight variations in the final copper recovery; the exception being the length of time each test is conducted.

SWVP-026431



Table 5-1 Summary of test parameters for bottle roll tests

Variable Conoco Test Magma Test

Crush Size -6 mesh -10 mesh

Sample Mass 100g 500g

Solution Volume 1 liter 2 liter

Solution pH 1.0 1.5

Ending pH 1.1-1.5 1.5

Acid Content 10-12g/l 5-20g/l

Leaching Time 8 days 3 days

Source: BHP, 1999

The Conoco work demonstrated that copper mineralogy is a very important component to leach

recoveries of individual samples. This is reflected in the metallurgical zone (met zone) terminology that was an outgrowth of that early work. The metallurgical zones as described in Volume II,

Section 3 of BHP (1997a) consist of:

Zone 0: Overburden

Zone 1: Copper oxide-dominant mineralization

Zone 2: Mixed copper oxides and iron oxides

Zone 3: High iron, no visible copper oxides

Zone 4: Transition (copper oxides and sulfides)

Zone 5: Sulfide

A statistical summary of the Hazen and McClelland test results, grouped into metallurgical zones, is shown in Table 5-2. Both studies show that chrysocolla-dominated and mixed copper/iron oxide

mineralization (designated as Metzones 1 and 2, Table 5-1) exhibits relatively consistent copper

recoveries of around 65 to 70 percent of the total copper, with average copper grades of about 0.15 percent in the leached residue. However, the average acid soluble (ASCu) to total copper (TCu)

ratio of Magma samples is somewhat higher than the average ratio of the Conoco samples. This is

consistent with results discussed in Section 3.7.4, Volume II of BHP, 1997a, where it was found that the Magma/BHP Copper ASCu values are systematically higher than the Conoco ASCu values

obtained on the same pulp sample.

SWVP-026432



Table 5-2 Statistical summary of bottle roll tests

A. Conoco bottle test data

Met Zone 1 2 3

Number 15 52 9

Avg. Std. Dev. Avg. Std. Dev. Avg. Std. Dev.

%TCu 0.633 0.390 0.554 0.389 0.284 0.063

%ASCu/%TCu 68.7 12.4 66.2 12.6 44.4 16.0

Bottle Rec. 72.2 12.6 65.0 13.8 43.3 16.2

Resid. Cu 0.136 0.087 0.158 0.129 0.140 0.040

B. Magma Pre-feasibility data

Met Zone 1 2 3

Number 0 16 1

Avg. Std. Dev. Avg. Std. Dev. Avg. Std. Dev.

%TCu 0.454 0.152 0.094

%ASCu/%TCu 79.2 7.5 56.7

Bottle Rec. 68.6 11.4 40.5

Resid. Cu 0.136 0.048 0.050

Source: BHP, 1999. Metzone 1 = chrysocolla dominant; Metzone 2 = mixed copper/iron oxides; Metzone 3 = high iron

A similar conclusion can be reached for material designated as Metzone type 3. The average recovery of the tests conducted by Conoco is nearly identical to the recovery of the one met zone 3

sample tested by Magma. The ASCu/TCu ratio of that Magma sample, however, is higher than the

average ASCu/TCu ratio of the Conoco samples. Nonetheless, the conclusion can be reached that

both the ASCu/TCu ratios and bottle test recoveries are significantly lower for met zone 3 samples than for met zone 1 and 2 samples.

Bottle test recoveries of chrysocolla mineralization are relatively independent of head grade for the

higher grade samples, and show 65 to 85 percent recovery for samples containing greater than 0.65 percent TCu. Chrysocolla-bearing samples below 0.65 percent TCu, along with met zone type 3

samples, tend to exhibit a poorly-defined grade-recovery relationship that could be approximated as

a constant tail recovery.

5.1.3 Large-Scale Column Tests

Four 6-in diameter by 10-ft high column leach tests were performed by Magma on crushed 1-in drill

core using San Manuel raffinate and 135 to 150 g/L sulfuric acid curd. Recovery rates of 64 to 73 percent were obtained under these conditions. Six-in diameter drill core was also used in a large

column (3 ft by 20 ft) using the same conditions with a calculated TCu recovery of 67 percent (BHP,

1997c).

Fourteen column tests were performed by the BHP San Manuel Metallurgical Lab and METCON Research in Tucson, Arizona. The materials tested included Magma and BHP drill core representing

primarily quartz monzonite with small amounts of granodiorite porphyry, diabase, and andesite; two

SWVP-026433



columns tested primarily granodiorite porphyry. Column leach testing conducted since 1996 by

BHP was organized in three phases:

Scoping Phase: 60-day tests to determine raffinate-rock reactions and composition;

Phase I: determine leaching behavior of mineralization representative of the first mining area;

and

Phase II: evaluate alternative lixiviants.

The first four column tests, representing the Scoping Phase of the program, were conducted by METCON on minus 2-in sample. Columns 1, 2, and 3 began with de-ionized water that was acidified with sulfuric acid to concentrations of about 5, 10, and 20 g/L H2SO4, respectively,

whereas Column 4 was treated with raffinate from the San Manuel SX/EW plant. The head assays

of the quartz monzonite sample were 0.398% TCu, 0.058% S, and 1.51% Fe. The columns were

leached for approximately 60 days and copper was continuously removed by SX, but it should be noted that copper was still being dissolved at the end of the test period. It is also noteworthy that the

San Manuel raffinate with 80 g/L total sulfate had a leaching effectiveness (% copper dissolved)

mid-way between the results for 5 g/L and 10 g/L acid, despite containing only 2.9 g/L free H2SO4.

Of the four tests, as shown in Table 5-3, the 20 g/L H2SO4 leaching solutions used in Column 3

dissolved the most copper, but at the expense of higher acid consumption. The BHP metallurgists

concluded that the leaching solution containing about 10 g/L acid offered the best balance of copper

dissolution, acid consumption, and cation loading (summation of cation concentrations in the final raffinate). Therefore, the final PLS composition from Column 2 was used to synthesize raffinate for

the subsequent Phase I column tests. Table 5-3 summarizes the results obtained during the Scoping

Phase. Total solution applications averaged 16.5 pore volumes (PVs) or 4.08 liters/kg solids.

Table 5-3 Summary of results from scoping phase columns, METCON

Column #

Rock Type

Head Grade

Acid conc.,

g/L

Days % TCu Dissolved

lb acid per ton

lb acid per lb

Cu

1 QM 0.398 4.8 63 45.8 11.0 3.1

2 QM 0.398 9.7 63 54.5 17.2 4.1

3 QM 0.398 19.7 63 66.2 30.4 6.0

4 QM 0.398 2.9 63 48.7 7.6 3.3

Source: Compiled by SRK from BHP 1997d

The Scoping Phase tests were followed by Phase I column tests designed to examine copper leachability from samples representing major resource types. Columns A and B were run by the

BHP San Manuel Lab, and column tests 5-10 were performed by METCON. The sample origins

included 6-inch core from diamond drill holes MCC-534 and BHP-2, which were within the first

planned mining block. Synthetic raffinate was made according to the final PLS compositions of previous tests, but without copper. In Table 5-4, the origin of the synthetic raffinate is shown as

follows: that for Columns A and B resembled the composition of the final solution from column 2;

the final column A solution was synthesized to start columns 8 and 9. Usually, the initial raffinate was made by dissolving reagent-grade chemicals in de-ionized water. However, column 10 was

initiated with the solutions produced by columns 8 and 9. Column tests 5, 6, and 7 evaluated the

response of very low-grade mineralization with head assays, respectively, of 0.155% TCu, 0.164%

TCu, and 0.126% TCu.

SWVP-026434



Table 5-4 Summary of results from Phase I column tests

Column Rock Type

Head Grade

%TCu

Raff

Source pH Days Pore Vols Liters/kg

% TCu

dissolved

lb acid

per ton

lb acid

per lb Cu

A QM 0.301 (calc)

2 1.4 84 13.0 4.40 35 2.5 7.6

B QM 0.141 (calc)

2 1.5 84 12.9 4.23 34 10.5 15.2

5 QM 0.155 2 1.5 59 12.9 3.49 46 16.6 26.0

6 QM 0.164 2 1.5 26 6.4 1.36 7 36.0 7.8

7 Tgdp 0.126 2 1.5 39 9.3 2.98 28 23.5 18.4

8 QM 0.216 A 1.7 158 35.2 8.00 54 1.6 43.7

9 QM 0.243 A 1.7 203 24.7 5.80 60 2.9 17.1

10 QM .305

(calc)

8+9 1.5 119 11.7 4.09 56 9.1 31.2


Columns 8, 9, and 10 were tested by METCON Research using average-grade, chrysocolla-bearing,

quartz monzonite (approximately 0.32 %TCu) from 6-inch diameter drill core; the voids were filled with inert sand (Col 8, 9) and tap was used prior to raffinate application to simulate saturated

conditions. The columns were 12-inch diameter by 5-foot tall (Col 8) and 12-inch by 10-foot tall

(Col 9 and Col 10); the material was subjected to simulated locked cycle in-situ leaching regime to assess the rate of copper dissolution and acid consumption. Leaching ranged from 158 days (Col 8)

to 203 days (Col 9); rinsing with tap water and a wash of sodium bicarbonate or sodium hydroxide

was performed following leaching. Copper extraction ranged from 54 to 56 percent with an acid

consumption ranging between 2.83 and 15.6 kg/metric ton of material (BHP, 1997c).

Although the tests were terminated when PLS copper grades were near or below 0.1 g/L, copper

recovery rates were still significant at the end of each test. This was because the relatively large

volume of leach solution that filled the column void spaces contains a relatively large mass of copper even at low copper concentrations. The copper recoveries attained during these column tests are

therefore not necessarily the maximum recoverable copper available for in-situ leaching and

recovery.

The Phase II column tests were designed to determine the efficiency of aluminum sulfate to pre-treat

typical chrysocolla mineralization for removal of exchangeable cations, specifically calcium and

copper. Copper recovery curves were similar to those illustrated in Figure 5-1, with relatively high

rates of recovery still present at the termination of the tests.

The columns were operated sequentially to simulate solution “stacking”, where low-grade PLS is

reconstituted with acid and returned to the formation in an effort to increase the PLS grade. The two

column tests were carried out at the BHP San Manuel Metallurgical Lab. The results are summarized in Table 5-5.

SWVP-026435



Table 5-5 Summary of results from Phase II column tests, BHP San Manuel

Column Rock Type

Head Grade %TCu

Raff

Source

pH Days PVs Liters/kg % TCu

dissolved

lb acid

per ton

lb acid

per lb Cu

C QM 0.386 (calc)

A 1.5 133 31.8 7.25 52 1.77 7.08

D Mixed QM + Tgdp

0.296

(calc)

C 1.7 126 28.1 6.22 35 - -

Combined 3.30 10.13


The copper recovery values were compared to the total copper content that was estimated from

residue analyses and copper mass recovered in solution. Copper was still being extracted at the

termination of each column test, albeit at low copper values in solution. The copper recoveries resulting from column tests should not be considered the ultimate copper recovery, only those that

are measured under specific test conditions.

Recoverable copper estimates for the Florence ISR project are based on previous observations and

experiments conducted by a cohesive multi-disciplinary staff. Conceptually, copper recovery of in-situ leaching is very easy to estimate. When acidic solutions are placed in contact with chrysocolla

and are subsequently pumped from the ground, 100 percent recovery is attained. Estimating the

proportion of copper contained in a given volume of rock that meets those conditions is more complex and requires estimations the proportion of copper contained in fracture-controlled

chrysocolla, the proportion of those fractures contacted with acidic solutions and/or available to be

contacted, and the proportion of extracted copper that is contained in PLS of an economic grade.

Additionally acid generation potential, column leach, and attenuation studies were performed by B & C to assess environmental effects and to support the APP application process. The Magma/BHP

studies evaluated interactions among the various rock units present in the Florence deposit to assess

copper extraction, sulfuric acid consumption and raffinate chemical characteristics over time. Two types of column leach studies were undertaken: (1) to monitor reactions between acidic raffinate and

bulk rock samples and (2) to monitor reactions that simulated leach field remediation.

Geochemical simulations were performed by B & C (1996b) and BHP consultants (BHP, 1997d) to assess solution control, chemical reactions, mass balance, and water balance issues during

operations, simulate block closure, and assess the post-closure solute transport. The numerical

simulations will be briefly reviewed below.

The wellfield copper extraction and remediation simulations were performed for a 100-foot spaced 5-spot system, and at a flushing flow rate of 40 gpm, the background sulfate levels and neutral pH

were estimated to be achieved within 60 and 133-150 days respectively. Chemical and kinetic

transport simulations were undertaken using the same inputs, and the predictions were that it would take 15 years to achieve extraction of all copper available for recovery. It should be noted that the

kinetic model indicated that 50 percent of the recoverable copper could be achieved within the first

two years and that would include the fractured chrysocolla being consumed within the first year. The model was sensitive to porosity decrease which it predicted would approximate 50 percent in

two years and also to clay rate constants that with this basic system would increase the period for the

initial fifty percent recovery of available copper to five years.

SWVP-026436



Source: BHP, 1997c

Figure 5-1 Copper recovery curves for column tests

5.1.4 Summary of Fracture Mineralogy Studies

A number of mineralogy studies were completed by to identify the principal minerals that would

interact with process solutions and to assess the potential for cation-exchange reactions. Mineralogy

examinations using X-ray diffraction (XRD) methods, scanning electron microscope (SEM),

reflected light microscopy, and semi-quantitative microchemical analyses were performed by J. Davis (1997) and C. Eastoe (1996) on exploration drill core and column test residues, respectively.

XRD-SEM Fracture Mineralogy

BHP geologist J. Davis (1997; BHP, 1997a) conducted a detailed study of the fracture mineralogy of the Florence deposit using samples collected from three drillholes located to the east of the field

test area. Using XRD and SEM techniques, they identified the minerals and assemblages present on

fractures as well as the distribution of different minerals vertically and horizontally.

The most common fracture minerals in the oxide zone are goethite (commonly copper-bearing), clay

minerals of various types (montmorillonite being most common, with lesser kaolinite, halloysite,

illite, and sepiolite), hematite, neotocite, jarosite, and chrysocolla. No horizontal variability was noted, and the vertical distribution appeared to be controlled by supergene processes.

The most common copper minerals observed were copper bearing-clays, but most of the copper in

the Florence deposit is present as chrysocolla of variable copper content. Copper-bearing clays

0 50 100 150 200Days Leaching

0

10

20

30

40

50

60

Co

pp

er

Re

co

ve

ry (

% o

f T

Cu

)

Col A

Col B

Col 8

Col 9

Col 10

SWVP-026437



(mainly montmorillonite and kaolinite) were observed to have copper present in the octahedral site,

substituting for aluminum or magnesium; no intergrowths of clays and chrysocolla were observed.

Cation-Exchange Bottle Roll Tests

A series of bottle roll tests were conducted by BHP to determine the cation-exchange capacity of the copper-bearing clays present at Florence (Patel, 1996). Samples were taken from three drillholes

(MCC-543, MCC-551, and MCC-552) and run for 72 hours. Eleven different lixiviants were used;

these consisted of hydrochloric or sulfuric acid, combined with one of several ion-supplying agents

(chlorides and sulfates of barium, calcium, magnesium, copper, aluminum, and ammonium).

The tests showed that copper recovery was highest when aluminum sulfate was added to the sulfuric

acid lixiviant and that calcium ions in the calcium-montmorillonite clay exchanged readily. Copper

extraction during the 72-hour test was <1 percent for nearly all lixiviants except for the sulfuric acid plus alum. Copper extraction in screened, uncrushed samples treated with sulfuric acid plus

aluminum sulfate was 9.3% for the MCC-543 sample, 6.56% for the MCC-551 sample, and 5.93%

for the MCC-552 sample. Copper extraction in the crushed samples was greater, reaching 11.81%

for MCC-543, 8.6% for MCC-551, and 8.66% for MCC-552.

5.2 Geochemical Modeling

Several laboratory tests and numerical simulations were performed prior to and following the BHP

field test to assess mineral reactions and copper extraction rates during operations as well as the

water quality expected to be measured in the wellfield after rinsing was completed. The early simulations used the results of Column test 2 and theoretical chrysocolla dissolution values from

academic literature. The later simulations used the water quality data collected during the field test,

and an attempt was made to prepare a reactive transport model calibrated to the laboratory and field

measurements. A complete summary of the simulation results and interpretations was prepared by R. Preece and is incorporated as Section 5 in the draft Field Test Report dated October 15, 1999

(BHP, 1999). A brief summary is provided below of these simulations.

5.2.1 Summary of Pre-test Geochemical Modeling

Magma Copper recognized that copper recovery curves derived from laboratory-scale test work

could not be used to estimate field-scale production with simple scaling functions. Magma

contracted with Dr. Tianfu Xu, University of La Coruña, Spain and Dr. Peter Lichtner and co-workers at the Southwest Research Institute (SWRI), San Antonio for geochemical modeling. Both

Xu and Lichtner studies used the results from Column 2 to calibrate the models and to estimate

necessary mineralogical parameters to predict copper recovery curves. Work therefore began in mid-1995 by Magma to develop tools suitable for predicting and monitoring in-situ leach processes.

The reactive transport computer model was identified as being the most promising tool to allow for

scaling laboratory studies to production estimates. These models combine geochemical reaction equations with hydrogeologic flow and transport equations to calculate the movement of fluids and

their chemical components as they flow through reactive rocks.

5.2.2 Summary of Post-Leach Geochemical Modeling

Geochemical models of static reaction experiments demonstrated that the Florence field test data

could not be simply interpreted from any single mechanism. Furthermore, comparisons among the

models suggest that flow and transport are important considerations to any geochemical model for this particular field test. Finally, because the leaching portion of the field test was terminated before

full PLS breakthrough, the time-copper curve in the BHP-1 production well cannot be extrapolated

to predict the copper recovery and time-copper grade curves. These require the use of a reactive

transport model that incorporate fundamental hydrogeological and geochemical parameters obtained from the test data to extrapolate the results using a first principles approach.

SWVP-026438



The problem was divided into two parts:

Dr. Denis L. Norton, a consulting geologist-geochemist, defined and estimated critical mineralogical and geochemical parameters from the behavior of injected solutions sampled at

monitor and production wells. This was largely conducted by examining the CH-2 data,

formulated as a one-dimension reactive transport problem.

Dr. Peter C. Lichtner, a consulting reactive transport modeler, used the parameters to first

calibrate the model against field data, and then extrapolate the test data to obtain a multi-year copper recovery curve. This was conducted as both a 2-D and 3-D problem, although a copper

recovery curve could only be obtained from the 2-D model.

Although good fits were obtained to the CH-2 geochemical data, the BHP-1 data were not successfully reproduced by the transport models. Because of project deadlines and inefficiencies

with working at long distances among the principals in this portion of the project, only a few

iterations were made to calibrate the model (BHP, 1999). Dr. Norton’s review suggested that

calibration may never be achieved under a conceptual framework of flow and transport through equivalent porous media, instead a hierarchical fracture network approach may be required.

The flow, transport, and geochemical parameters obtained from batch and column tests and one-

dimensional treatment of the field test were used by Lichtner (1999) to develop a production model for Florence. The work by Lichtner was divided into two phases: model calibration, in which 2-D

and 3-D models were constructed and compared with the field data; and production forecast, where

the best fit to the calibration phase was used to estimate a five-year copper recovery curve. Details of the problem setup and results are presented in Lichtner (1999), provided in BHP 1997d Appendix

IV-13.

The calibration effort was only partially successful. Only a limited number of models were run, and

fine-tuning of model parameters could not be accomplished. The profiles for monitor well CH-2 were reasonably well modeled, although transport parameters obtained from pumping and tracer

tests required modification to achieve this. Significantly, however, the geochemical behavior

observed in CH-1 and BHP-1 could not be reproduced. Use of a three-dimensional model that incorporated vertical variability in transport parameters did provide a possible explanation of the low

sulfate and magnesium values observed in these wells. Higher permeability and porosity in the

upper portions of the oxide zone caused a limited amount self-dilution as injected solutions migrated though the upper layer. Because of the higher porosity, these solutions were delayed in arriving at

BHP-1. Even so, Lichtner (1999) concluded that the present formulation of the flow and transport

was not suitable for satisfactory calibration of the model. Although Lichtner (1999) did not argue

for an alternative conceptual approach in the manner of Norton (1999c), he did recognize that a multiple continuum model was minimally necessary, coupled with a more complete understanding of

the flow characteristics.

It can be argued that the heterogeneity associated with fracture flow may be accentuated at the scale of a single five-spot. As a wellfield grows in size, use of a volume-averaged flow and transport

model may become more appropriate to simulate the overall behavior of multiple five spots. Using

this reasoning, a long-term forecast model was developed to estimate a copper recovery curve for the

Florence model. The two mineralogical cases discussed in the previous section were used to examine sensitivity of chrysocolla accessibility. In a similar manner as Lichtner, et al. (1996),

Lichtner (1999) distinguished the two types of chrysocolla by decreasing the kinetic rate for the

chrysocolla associated with copper-bearing clay minerals. Because of the difficulty with integrating the copper production over the vertical extent of the pumping well in the 3-D model, the forecast

model was conducted only for the 2-D case.

The copper recovery curves are presented in Figure 5-2 for the two cases. The difference in the ultimate recovery for the two cases is due simply to round off error in assigning chrysocolla

SWVP-026439



concentrations in the initial boundary conditions. The five-year recovery is estimated to be

approximately 50 percent of the total copper for Case A, and 45 percent for Case B.

The PLS copper grade and pH curves for the two cases are shown in Figure 5-3. The values

predicted by the reactive transport model are consistent with values obtained in column and batch

test work, as well those observed in the CH-2 well. Because both cases obtain similar copper recoveries with the same flow rate, average PLS grades are similar to each other.

Source: BHP, 1999

Figure 5-2 Copper recovery curves of the long-term forecast model

The copper grade curve exhibited in this model would suggest that economic PLS grades could be obtained for 6 to 7 years of leaching. An economic cut-off grade of 200 to 400 mg/l is likely for an

intermediate leach solution suggesting that the Case A scenario could be leached for 6 to 7 years,

while the Case B would continue for 7 to 8 years (Figure 5-2). This extra leaching time would result in a copper recovery of 60 to 65 percent for both cases (Figure 5-2).

0 5 10 15

Time of Leaching (years)

0

20

40

60

80

Cop

pe

r R

eco

ve

ry (

% o

f T

Cu

)

67% Ultimate Recovery

CASE B

CASE A

SWVP-026440



Source: BHP, 1999

Figure 5-3 Copper and pH curves from long-term forecast model. Case A production shown as solid lines, Case B shown as dashed.

5.3 Conclusions

The Florence field test was highly successful in achieving many of the engineering and hydrogeological goals that was set for the project. One very important accomplishment was the

successful demonstration of the ability to attain remediation of the wellfield. The project, however,

appears to have been constructed at an awkward scale to fulfill one of the basic goals of the project: demonstrate economic copper production at a field scale. Under production scale in-situ copper

extraction, such as the San Manuel in-situ facility (BHP property located approximately 50 miles

southeast f Florence) , several inter-connected production cells could be averaged to cancel the effect

of heterogeneity in the transport and chemical characteristics of the rock. With only one production cell, however, heterogeneity can dominate transport of reactive fluids in an unpredictable manner.

Even with this issue in the forefront, the test suggests that in-situ production is manageable by a

skilled team of geologists, hydrogeologists, and geochemists. The production planning team would adjust the wellfield layout to take advantage of or mitigate the effects of localized, site-specific

conditions based on experience gained in adjacent portions of the wellfield.

BHP’s geochemists felt that the geochemistry of the solutions recovered in production wells could not be explained solely on the basis of water-rock reactions. Only the solutions sampled in CH-2

followed expected geochemical behaviors, which were dominated by dissolution/precipitation and

cation exchange mechanisms. The geochemical evidence they believed pointed to a significant

amount of dilute solutions being mixed with raffinate in the remaining wells, even within the BHP-1 production well. No combination of known cation exchange, surface complexation, and

0

400

800

1,200

1,600

Co

pp

er

(mg

/l)

0 5 10 15

Time of Leaching (years)

0

2

4

6

8

pH

Copper Curves

pH Curves

SWVP-026441



dissolution/precipitation mechanism was discovered that could explain the chemistry of production

wells without mixing with diluted waters.

The leaching portion of the test was not of sufficient length to demonstrate proof of concept for in-

situ copper extraction on a commercial scale. While copper leaching reactions were observed in

nearly all of the production wells, economic concentrations of copper in solution were not attained during the short duration of the field test. Of considerable concern were the apparently low recovery

rates that were calculated for the reaction path between BHP-6 and CH-2. This may be due to the

passive samplers in CH-2 intercepting a single flow channel rather than an integrated volume that would be sampled by a pumping well. The extent of water-rock reactions and dilution will be

important to assess in the new PTF.

Remediation of the wellfield is achievable, and appears to be strictly a function of using groundwater

injectate to flush raffinate from the groundwater system. Minor amounts of gypsum and silica appeared to have re-dissolved by the remediation fluids, but most components, including pH

appeared to behave conservatively. This conclusion was also reached on the basis of column

washing experiment by Preece (1997). This would suggest that the strategy of monitoring sulfate as a proxy for regulated components derived by B & C (1996d) continues to be a viable strategy. This

also suggests that adding a neutralizer to the injectate may not decrease the time necessary to meet

regulatory standards for pH.

5.4 Basis of Design

A copper recovery curve for the Florence project has not yet been demonstrated. Production model forecasts have been derived using curves calculated with reactive transport models that are largely

based on column and batch tests. Although leaching characteristics similar to these tests have been

observed in monitor well CH-2, this is an insufficient demonstration of project feasibility. Additional, longer term field-scale leach tests are required to provide a basis for copper recovery

curves.

The ultimate copper recovery for oxide zone mineralization by in-situ leaching technology was

estimated from geological observations and extrapolation of column leach tests. It was estimated, for the oxide mineral zones, that an average of 67% percent of the total copper is contained in

fracture-controlled chrysocolla (designated as CuOx1 in the drillhole codes) or copper-bearing clay

minerals (designated as CuOx2) within close distance of a fracture. The residual copper has been found in relatively insoluble copper-bearing iron hydroxides and in pervasive chrysocolla, copper-

bearing clays, and copper sulfides located in away from a fracture or in other zones or portions of the

deposit that are inaccessible to raffinate solutions. Like all ISR operations, this estimate will not be validated until a field-scale field test is run to completion. However, the time scale to completion for

an ISR operation is a matter of years, rather than months observed in oxide heap leach operations.

This estimate may not be completely validated by a feasibility-stage leach test, although the

proportion of copper contained in fractures and primary flow features (CuOx1) may be determined by a sufficiently long test.

Net acid consumption was estimated from column leach tests to be 3 lb. acid per lb. copper. While

free acid breakthrough (pH < ~3.5) was not achieved in any of the production wells, the Cu-pH relationships observed in the CH-2 monitor well are nearly identical to those observed in the column

tests. Because of the uncertainties in the interpretation of the leach test transport and reaction

processes, the acid consumption estimates from column tests could not be verified. It is also

uncertain whether the field-scale test provides an accurate indication of acid requirements for free acid breakthrough.

One cautionary note, however, was provided by leaching experiments with LBFU sediments. The

calcareous sediments overlying oxide zone mineralization were found to be calcareous, with acid

SWVP-026442



consumption on the order of 150 lb acid per ton. Unintentional flow of raffinate into the LBFU will

increase acid costs if it is not effectively controlled by the well construction design and operation.

The ability to remediation an ISR site has been demonstrated in the BHP field test. The data

collected during the remediation portion of the field test indicates that sulfate levels in process water

are a good indicator of the concentrations of ADWR-regulated constituents. Dissolved sulfate of approximately 750 mg/l denotes that most constituents are near or below regulatory limits. The one

exception is pH, where rinsing of more 99 percent of the PLS is required before regulatory

compliance. The current data suggest that this is strictly flow driven, so that non-reactive transport models may be sufficient to use for estimates of water balance and remediation time and costs in the

process flow sheet.

5.5 Recommendations

The Florence ISR test must be re-done. The field test program completed to date is not sufficient to

state mineral reserves based on known total copper recovery or rates of copper recovery. However, it is not recommended that the test be conducted under the same conditions, however, as it is likely

that the same results will be obtained. In particular, it is recommended that additional wells be

drilled to provide multiple leaching cells.

The amount of dilution required by geochemical models has not been successively simulated by flow and transport models constructed to date. Conversely, the chemical reaction paths that are implicit in

the transport models are incompatible with static and transport reaction models discussed in this

study. This duality between the geochemical and hydrogeological view of the test data must be at least conceptually reconciled before attempting a second leach test. The concepts advanced by

Norton (Appendix VI-13) provide a good starting point to a working toward a new paradigm.

Additional simulations of field-scale extraction and remediation should be conducted. In particular, the effect of variable copper content of the wellfield on PLS copper grade and total leach time should

be investigated. The remediation of the wellfield provided a useful, longer term data set that may be

used for inverse modeling of the transport characteristics of this wellfield. It also provides for

forwarding modeling efforts to better understand the dynamics of fluid dilution and back-reaction of precipitates during remediation. These may help to better design the next test field and remediation

strategies.

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6 Operations Activities through Reclamation Phase Section 6 provides information on the field test operation with respect to changes in water quality

through time.

6.1 Field Test Duration

The leaching and reclamation schedule for the BHP field test is shown in Table 6-4. An injectate consisting of sulfuric acid and WW-4 groundwater only was injected on Day 1; injection of San

Manuel raffinate and groundwater began on November 1, 1997 and continued through February 6,

1998. Injection of pond water only followed by groundwater only was performed BHP-6 through BHP-9 through May 12, 1998 with simultaneous recovery of increasingly dilute solutions in the

remaining recovery wells. Groundwater injection was performed in BHP-1 through December 16,

1998 with water recovery in the former injection wells. Pumping of BHP-6 through BHP-9

continued through March 31, 1999.

6.2 Field Test Operation Procedures

During the field test, well data was collected manually and electronically from individual injection,

recovery, and monitoring wells, tanks, and pond levels. This information included: water levels,

electrical conductivity and pH, flow rates, and the chemistry of injected and recovered solutions and groundwater.

6.3 Manpower Requirements and Duties

The original staffing plan was to have six full-time employees in the wellfield during the field test

including two technical supervisors with four additional full-time shift workers working as operators.

One new hire quit just before operational start-up, and one technical supervisor died in a car accident the week after start up, so the field test was operated by Michael Kline and three other operators,

with maintenance by Peter Kelm and Richard Sichling (safety officer). The staff worked two 12-

hour shifts each day on a 28-day rotating shift schedule; the shift changes occurred at 6:30 a.m. and 6:30 p.m. No regular time for lunch period or break period was set up, allowing the technicians to

decide on their own when to take lunch and rest breaks.

Full-time coverage, however, was needed for two important reasons. The first reason was to have

enough staff to watch the delivery truckers when offloading the raffinate, and sulfuric acid, and caustic soda to ensure safe procedures were used. Second was to watch for power outages and do

the manual switch-over to back-up power during seasonal storms, this was required at least six times

during the 101 days (M. Kline, written commun., 2010). Sampling, sounding, and performing pH and conductivity measurements only took about 6 hours of the operator’s duties. If major

maintenance work in the wellfield or evaporation pond had to be done, however, it could not be done

by a single operator. Maintenance problems were also caused by seasonal monsoon events during strong wind, rain, and lightening.

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Table 6-1 Field test shift schedules

Shift Mon Tue Wed Thu Fri Sat Sun

Week 1

Day 4 4 4 3 3 3 3

Night 1 1 1 1 4 4 4

Week 2

Day 1 1 1 4 4 4 4

Night 2 2 2 2 1 1 1

Week 3

Day 2 2 2 1 1 1 1

Night 3 3 3 3 2 2 2

Week 4

Day 3 3 3 2 2 2 2

Night 4 4 4 4 3 3 3

Source: M. Kline, personal commun., 2010

6.4 Evolution of the Water Quality in the Field Test through Rinsing Phase

Water quality samples related to the BHP field test consisted of groundwater monitored before and

after the field test and the make-up water pumped from well WW-4. Water quality samples related to process solution included injectate (the mix of groundwater and sulfuric acid injected into the

injection wells), pregnant leach solution collected from the recovery wells, and the evaporation pond

water. Process solution samples were taken daily and weekly by field technicians trained in water quality sampling procedures. Water quality analyses were performed by the BHP Copper San

Manuel Metallurgical Laboratory, ACTLABS-Skyline of Tucson (now Skyline Assayers &

Laboratories), and ACTLABS-Enzyme (now ACTLABS) of Ancaster, Ontario, Canada. Field data

(water level, electrical conductance, and pH) were recorded and entered by BHP field technicians on a daily basis.

The groundwater and process solution analyses related to the field test and subsequent rinsing phase

are available in a Microsoft Access database (FlorenceDB.mdb-revised 6/28/2010) for the period from November 1, 1997 through October 1999. Although the number of sampling points decreases

after March 1998, sampling data are also available from 2000 through 2007. The database contains

records of water quality sampling, well construction and well history details, flow data, the results of mechanical integrity tests, and other information. Data entry forms, queries, and reports that

generate graphical views of the concentrations of constituents for various sets of wells are also

available in the database. The data were originally entered by BHP employees to record the results

of drilling (well construction details, costs, integrity tests) and the results of solution analyses related to an in-situ leach, recovery, and rinsing field test.

The water quality database lacks standard laboratory quality assurance/quality control (QA/QC)

information such as minimum detection limits, date of analysis, dilution factors, QA/QC codes/comments, etc. SRK found some apparent data entry errors and outlier results in the Access

database but did not cross-checked the database entries against the original laboratory sheets or field

record sheets to estimate overall accuracy or completeness of the database. An effort was made

through the sampling program to collect duplicate samples and to record the meter calibration results.

Graphical interpretation and presentations of the water quality data were prepared by BHP and have

also been prepared by SRK in an attempt to understand the interactions and recoveries in each well and in groups of wells. Wellfield extraction graphs are shown in Appendix A and water quality

SWVP-026445



graphs for each well are shown in Appendix B. The graphs quickly become too busy to interpret

easily and the horizontal and vertical water quality changes occurring through time in the injection and recovery wells is not easy to understand using standard Excel graphs.

To provide a more spatial and temporal interpretation of the solution chemistry and understand the

reactions that occurred, the data were exported from the Access database into Voxler2 by Golden Software, a 3-D gridding/contouring software program. The concentrations between known points

were kriged to estimate water quality concentrations within and adjacent to the field test area. An

animation was created on the kriged concentration results to show the evolution of water quality through the duration of the field test. A full explanation of the methods was provided to Curis is a

separate memo (SRK, 2010a)

6.4.1 Sulfate

The wellfield layout and well traces are shown in perspective view in Figure 6-1. Sulfate

concentrations were interpolated by day on a weekly basis, displayed with cutoff grade colors, and

captured as jpg images for display. Examples are shown in Figure 6-2 at two dates—November 7,

1997 and February 1, 1998. The injectate, a mix of raffinate and local groundwater, had a concentration of approximately 10,120 mg/L SO4 when it was injected via BHP-6, BHP-7, BHP-8,

and BHP-9 beginning October 31, 1997. The injectate concentration varied and was approximately

6,387 mg/L in early February.

Note the early detection of elevated sulfate in perimeter recovery well BHP-5 one week into the test

while other perimeter recovery wells were still measured below 1,000 mg/L (concentrations less than

1,000 mg/L are shown in white). Near the end of the test, elevated sulfate was uniformly measured throughout the field test with the exception of upgradient, perimeter recovery well BHP-13 where

continual inflow of fresh groundwater prevented concentration of the sulfate. Upgradient well BHP-

2 showed markedly lower concentrations and mass of copper extracted than upgradient well BHP-5

suggesting that some structure or other feature preferentially directed flow from BHP 9 to BHP-5.

Figure 6-3 shows the rinsing progress that was achieved during the following two months based on

sulfate concentrations and pH. The intermediate pH, residual process water in the evaporation pond

was injected back into the test area via the same four injection wells from mid-February to March 21, 1998. Groundwater from WW-4 was injected into the test area until May 14, 1998. The upgradient

portion of the field was rinsed to below 1,000 mg/L in less than two months.

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The injection wells are shown with yellow drillhole collars, recovery wells have green collars, and chemical monitor wells have white

collars. The white drillhole traces are shown in perspective view using downhole surveys.

Figure 6-1 Planar view showing field test layout and location of the wells in mine coordinates (ft)

Note: Sulfate concentrations vary from background values of less than 1,000 mg/L (shown in white) measured on the perimeter of the test

area to high sulfate values of over 6,000 mg/L measured in injection wells BHP6, BHP7, BHP8, and BHP9 (shown in red).

Figure 6-2 Planar view showing SO4 (mg/L) concentration near the start of raffinate injection on November 7, 1997 (left) and end on February 1, 1998 (right)

SWVP-026447



Figure 6-3 Planar view showing SO4 (mg/L) concentration at the end of pond water injection on March 21, 1998 (left) and the end of groundwater injection on May 14, 1998

6.4.2 pH

The pH visualization begins with a perspective view looking down from immediately above the field test area and transitions to an east-west profile looking north. Background groundwater quality

ranges from pH7 to over pH8 as shown in the plan view in Figure 6-4. During the raffinate injection

phase, pH values ranged from approximately 1.5 to 1.7 in the injectate. Although pH values have a lognormal relationship, the values were treated as integers in this simplified approach and were

interpolated using IDW2 method with 50’ projection distances. Images were created for weekly

results using cutoff grade colors for values ranging from pH1 to pH9. Injectate is visible as red color

in the visualization and in Figure 6-4 and Figure 6-5.

In the animation, you will note the steady decrease in pH spreading outward from injection wells

BHP-6 and BHP-8 first at the upper elevations, then middle, and lower one-third of the profile.

Starting in the last week of January, the central recovery well has finally reached the pH3.5 to pH3 level where copper dissolution can begin. It took more than 3 months for the injectate to migrate

across a 50-foot distance through rock of variable fracturing and hydraulic conductivity, partially

consume the carbonate gangue minerals present on the fractures, and start to reach a state of acid

equilibrium in the central test area that could overwhelm the inflow of fresh (pH 7-8) groundwater. This visualization, in conjunction with one on copper concentrations measured through the test,

emphasizes the time component needed to move enough volume of injectate across the flow path

between injection and recovery wells and through the volume of rock in order for the rock and pore solutions to start to become acid-equilibrated. Without acid-equilibration, copper cannot be

effectively dissolved and recovered.

The location of the injection wells in are clearly identified by the trace of low pH (1.5) solutions contoured in red color on left with near-neutral water in the vicinity of BHP-1 and neutral, pH7

water inflowing into the perimeter recovery wells. At the end of the test, the injectate has reacted

with materials in the top one-third of the rock profile and is decreasing to pH4 (yellow) in the bottom

portions of CH1 and CH2. Near-neutral water is measured in perimeter well BHP12.

SWVP-026448



Note the background water quality has a pH between 7 and 8. On November 3, injection of pH1.5 injectate is visible in BHP-6, BHP-7,

BHP-8, and BHP-9.

Figure 6-4 Planar view showing pH (su) on October 31, 1997 (left) and November 3, 1997 (right)

SWVP-026449



The well traces are faintly visible and begin at the top of bedrock.

Figure 6-5 Vertical E-W profile from BHP12 though BHP10 looking north showing pH on November 7, 1997 (left) and at the end of the raffinate injection phase (February 8, 1998)

During the rinsing phase, intermediate (4.8 to 6.05) pH pond water was reinjected back to the wellfield and the water quality recovered in the central and perimeter showed a similar range of pH

values (Figure 6-6). On March 14, the visualization shows a sudden decrease in pH measured in

BHP-10; this occurred when acidic injectate was used to kill and remove organic growths on the well

screen. Continued injection through May 14 with fresh groundwater had increased the pH from pH4.95 to over pH7 in the perimeter wells. Low pH concentrations ranging from 4.5 to 5.5 are noted

in the animation in the CH wells at the end of the three-month rinsing phase.

SWVP-026450



At the end of the March, the injectate has reacted with materials in the top one-third of the rock profile and is increasing to pH4 (yellow) in

the top portions of CH1 and CH2. Water with a pH of 5-6 is measured in perimeter well BHP12. By the mid-May, pH values had

increased to the range of 5-8 for much of the wellfield with background values measured in injection well BHP-8. CH1 and CH2 still

show lower pH values between 4 and 5.

Figure 6-6 Vertical E-W profile from BHP-12 though BHP-10 looking north showing pH on March 21, 1998 (left) at the end of pond water injection and at the end of the groundwater injection phase (May 14, 1998).

6.5 Copper Recovery and Mass Balance

As previously discussed, the injectate was raffinate from the BHP San Manuel SX-EW Plant that

was mixed with site groundwater from well WW-4 to create an injectate solution. The concentration

of various trace inorganic metals and common ions varied in each batch of raffinate shipped to the

site. The average pH of local groundwater was 7.6-7.8 s.u; the average pH of the blended injectate was 1.65 s.u. The copper content in groundwater was approximately 0.1-0.2 mg/L; copper

concentration in the blended injectate ranged from 1 to 32 mg/L with an average 11 mg/L.

During rinsing activities, pond water with an average pH of 5.70 s.u. and copper content of 20 mg/L was injected back into the wellfield. Groundwater from WW4 was injected for the period from April

7 to May 12, 1998 as the final reclamation of the 5-spot leach area. The pH of the injectate during

this phase was approximately 7.41 s.u. with an average copper content of 0.2 mg/L.

A daily average for the flow rates (gpm) in and out of each well was matched with water quality

analyses for each well to calculate how much mass of copper was extracted from the wellfield.

SWVP-026451



Interpolated values were used to fill the gaps later in the test when daily flows were available but

water quality analyses were performed only on a weekly basis.

Table 6-2 tabulates the copper (lbs) added to the wellfield by well through May 1999 via the

injection wells and extracted from the recovery wells. The majority of copper was added through the

introduction of the residual copper during the raffinate injection phase and through reinjection of pond water beginning in February 1998. The copper mass injected and extracted in units of

pounds/day through May 1998 and May 1999 is shown on Figure 6-7 and Figure 6-8, respectively.

The figures show the daily and cumulative lbs/day of copper injected into the four injection wells and pumped from the recovery wells during the leaching and reclamation periods. The slope of the

Net Daily Cu lbs/Day data line for the raffinate injection period between October 17, 1997 and

February 8, 1998 continued to increase until the premature cessation of the field test. A change in

slope is also seen in the daily and daily net recovery between January and February 1998 as seen in Figure 6-7; this may be attributed to the introduction of copper-bearing, intermediate pH pond water

in the make-up water and the decreased ratio of raffinate to injectate.

The total cumulative copper mass extracted from the wellfield was 41,966 lbs through May 1999 (14 months after the cessation of the raffinate injection phase). The net cumulative copper recovered

after the subtraction of copper contained in the injectate was approximately 39,743 lbs through May

1999. Approximately 2,223 lbs of copper (5.2%) was injected into the wellfield and not recovered –

probably through precipitation in fractures or in the montmorillonite minerals during the injection of copper-bearing pond water. The net copper recovery represents a small fraction (3%) of the 1.34

million lbs copper estimated to be contained in the volume of rock within the inner recovery cell

shown in Figure 2-8.

Table 6-2 Mass of copper injected and recovered during leaching and rinsing phases

Well Cu Injection (lbs)

Cu Extraction (lbs)

Net Cu

Extraction (lbs)

BHP-1 9 5,874 5,865

BHP-2 0 234 234

BHP-3 0 1,004 1,004

BHP-4 0 916 916

BHP-5 0 6,738 6,738

BHP-6 617 5,383 4,766

BHP-7 687 6,562 5,875

BHP-8 353 4,812 4,458

BHP-9 557 7,282 6,725

BHP-10 0 2,007 2,007

BHP-11 0 833 833

BHP-12 0 301 301

BHP-13 0 22 22

Total 2,223 41,966 39,743

Compiled by SRK, 2010 from BHP flow and water quality data for period of 31 October 1997 through 11 May 1999. Negligible copper

was added during groundwater injection phases.

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Figure 6-7 Daily and cumulative injection and extraction – Net copper (lbs) recovery vs. time through May 11, 1998

-10

1990

3990

5990

7990

9990

11990

13990

15990

17990

-10

10

30

50

70

90

110

130

150

170

190

10/31/97 11/21/97 12/12/97 1/2/98 1/23/98 2/13/98 3/6/98 3/27/98 4/17/98 5/8/98

Cu

mu

lati

ve C

op

pe

r Ex

trac

tio

n l

bs/

Day

Dai

ly C

op

pe

r Ex

trac

tio

n l

bs/

Day

Date

Total Wellfield Cu Extraction Per Day vs TimeField Test 1997-1998

Total Well Field lbs/Day lbs/Day Injected Net lbs/Day Cu Total Well Field Cumulative lbs/Day Cumulative lbs/Day Injected Cumulative Net lbs/Day Cu

SWVP-026453



Compiled by SRK, 2010 from BHP flow and water quality data

Figure 6-8 Daily and cumulative injection and extraction – Net copper (lbs) recovery vs. time through May 12, 1999

6.6 Sulfate Recovery and Mass Balance

As was done with copper extraction, the flow rates (gpm) in and out of each well were matched with analyses in mg/L for the well. Interpolated values were used to fill the gaps later in the test when

daily flows were available but water quality analyses were performed only on a weekly basis.

During operation of the leaching phase of the test, sulfate content in the injectate ranged from 1,650 mg/L to 12,540 mg/L. The average sulfate content was 7,758 mg/L although the average decreased

during the test as the ratio of raffinate in the injectate decreased. During the pond water injection

phase, sulfate concentration in injectate ranged from 19 mg/l to 3,054 mg/L with an average of 1,783 mg/L. During the rinsing phase when WW-4 groundwater was injected, the sulfate content in the

injectate ranged from 10 mg/l to 452 mg/L with an average concentration of 85 mg/L.

The mass of sulfate injected and extracted is tabulated in Table 6-3 shown on Figure 6-9. As shown,

daily injection exceeds daily extraction through the leaching phase, but continues to be extracted after the leaching phase has ended. Cumulatively, approximately 1,168,496 lbs of sulfate was

injected into the field with a net recovery of 1,044,046 (89.3%) through May 11, 1999 when matched

sets of flow and assay records cease. Records compiled by BHP through June 2001 (Kline, 2001) show that 1,146,401 lbs of sulfate had been recovered with a net accountability of 98.6 percent.

Add more of John Kline’s info here

2/8/1998 5/12/1998 11/25/1998 5/11/1999

-10

4990

9990

14990

19990

24990

29990

34990

39990

44990

-10

40

90

140

190

240

Cu

mu

lati

ve C

op

pe

r Ex

trac

tio

n l

bs

Dai

ly C

op

pe

r Ex

trac

tio

n l

bs/

Day

Date

Total Wellfield

Cu Extraction Per Day vs TimeField Test 1997-1998

lbs/Day Extracted lbs/Day Injected Net lbs/Day Extracted Cumulative lbs/Day Extracted Cumulative lbs/Day Injected Net Cumulative lbs/Day Extracted

Raffinate Injection InjectionBHP1-5 & 10-13 Recovery

BHP1 GW Injection Phase Variable Recovery Wells

BHP6-9 Recovery

End of Injection

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Table 6-3 Mass of sulfate injected and recovered during leaching and rinsing phases

Well SO4

Injection (lbs)

SO4 Extraction (lbs)

Net SO4 Extraction

(lbs)

BHP-1 5,454 205,273 199,819

BHP-2 0 31,989 31,989

BHP-3 0 62,677 62,677

BHP-4 0 68,165 68,165

BHP-5 0 131,489 131,489

BHP-6 318,750 100,090 -218,660

BHP-7 349,828 110,556 -239,272

BHP-8 206,751 80,539 -126,212

BHP-9 287,712 124,977 -162,736

BHP-10 0 53,164 53,164

BHP-11 0 29,435 29,435

BHP-12 0 29,946 29,946

BHP-13 0 15,746 15,746

Totals 1,168,496 1,044,046 -124,449

Compiled by SRK, 2010 from BHP flow and water quality data for period of 31 October 1997 through 11 May 1999

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Compiled by SRK using BHP flow and water quality data

Figure 6-9 Mass injection and extraction - Net sulfate recovery vs. time through May 12, 1999


To Do

6.8 Recommendations for the New Field Test

Text

2/8/1998 5/12/1998 11/25/1998 5/11/1999

-1000000

-500000

0

500000

1000000

1500000

-25000

-20000

-15000

-10000

-5000

0

5000

10000

15000

20000

25000

Cu

mu

lati

ve S

ulf

ate

Ext

ract

ion

lb

s

Dai

ly S

ulf

ate

Ext

ract

ion

lb

s/D

ay

Date

Total Wellfield

SO4 Extraction Per Day vs TimeField Test 1997-1998

lbs/Day Extracted lbs/Day Injected Net lbs/Day Extracted Cumulative lbs/Day Extracted Cumulative lbs/Day Injected Net Cumulative lbs/Day Extracted

Raffinate Injection

InjectionBHP1-5 & 10-13 Recovery BHP1 GW Injection Phase

Variable Recovery WellsBHP6-9 Recovery

End of Injection

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Table 6-4 Timeline for leaching and reclamation activities

From To BHP-1 BHP-2 BHP-3 BHP-4 BHP-5 BHP-6 BHP-7 BHP-8 BHP-9 BHP-10 BHP-11 BHP-12 BHP-13

10/31/97 2/8/98 Prod Leach

Prod Leach

Prod Leach

Prod Leach

Prod Leach

Injection Raff

Injection Raff

Injection Raff

Injection Raff

Prod Leach

Prod Leach

Prod Leach

Prod Leach

2/9/98 2/17/98 Inactive Prod Recl

Prod Recl

Prod Recl

Prod Recl Inactive Inactive Inactive Inactive

Prod Recl Prod Recl Prod Recl

Prod Recl

2/18/98 3/26/98 Prod Recl

Injection Pond

Injection Pond

Injection Pond

Injection Pond

3/27/98 4/6/98 Inactive Inactive Inactive Inactive

4/7/98 5/12/98 Injection GW

Injection GW

Injection GW

Injection GW

5/13/98 7/17/98 Injection GW

Prod Recl Prod Recl Prod Recl

Prod Recl Inactive Inactive Inactive

7/18/98 8/5/98 Inactive Inactive Inactive

8/5/98 11/5/98 Inactive Inactive

11/6/98 11/12/98 Inactive

11/13/98 12/16/98 Injection GW

12/17/98 1/7/99 Inactive

1/8/99 2/7/99 Inctive Inctive

2/8/99 2/25/99 Prod Recl Inctive

2/26/99 3/5/99 Inctive Prod Recl

3/6/99 3/31/99 Prod Recl

4/1/99 5/12/99 Prod Recl

Notes: Inactive = Well not in operation

Injection Raff = Injection well during leach test, injectate is blend of raffinate and WW4 groundwater, low pH

Injection Pond = Injection well post-leach test, injectate is residual process solution in Evaporation Pond, intermediate pH

Injection GW = Injection well post-leach test during reclamation phase, injectate is WW4 water, neutral pH

Prod Leach = Production/recovery well during leach test

Prod Recl = Production/recovery well post-leach test during reclamation period

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7 Environmental and Safety Findings Section 7 addresses environmental and safety related issues during the field test and environmental

risk factors for post-closure water quality.

7.1 Environmental Issues during Operation of Field Test

Text

7.2 Environmental Issues following the Test - Post-Rinsing Water Quality

Routine water quality samples were collected during the field test and with decreasing frequency

through May 12, 1999 – one year after the conclusion of the pond water injection phase. Thereafter,

the pumping operation ceased. A set of water quality analyses was taken by B & C on behalf of

BHP in 2000 and 2001 and sent to Nevada Environmental Lab, Aerotech Laboratory, and Radiation Safety for analysis (see Table 7-1 and Table 7-2). B & C sampled the wells again in 2003 and 2007

as shown in Table 7-3 through Table 7-5.

Modeling performed by B & C (1996b) and previously submitted to ADEQ in the Magma APP application indicated that the regulated constituents sampled from within the aquifer exemption zone

would be below the Arizona Aquifer Water Quality Standards (AWQS) once the sulfate

concentration was rinsed to below 750 mg/L. In the fourth quarter of 2000, sulfate ranged from background values of 64 to 160 mg/L in the outer perimeter wells to slightly elevated values of 450

to 540 mg/L measured in the former injection wells BHP-6 through BHP-9. Neutral water quality

was measured in all wells except the former injection wells – pH values ranged from 3.83 in BHP-6

to 4.68 in BHP-8. By mid-2007, sulfate concentrations in the wells had all decreased to background concentrations with approximately 75 mg/L in the perimeter wells and 145 mg/L in the former

injection wells; pH in the former injection wells, however, had increased only slightly to 4.35 in

BHP-6 and to 5.11 in BHP-8. None of the trace metal results exceed the relevant AWQS at these sulfate and pH concentrations.

Radiochemicals were also sampled during leaching and rinsing phases, but with much less frequency

or consistency in constituents analyzed. Elevated adjusted gross alpha particle activity was

identified in five wells in 2001 including BHP-2, BHP-6, BHP-11, BHP-12, and BHP-13. A significant component of these analyses is contributed by total uranium, which was measured in

elevated concentrations ranging from 18.1 mg/L in BHP-8 to 10.9 p in BHP-12. Fewer analyses are

available in 2003 and 2007; three samples in 2003 (one in 2007) showed slightly elevated results ranging from 10.3 to 14.8 pCi/L but none of the analyses exceed the AWQS for adjusted gross alpha.

As seen before, the major constituent contributing to the elevated gross alpha is the total uranium

concentration. Total uranium is a constituent commonly noted in groundwater associated with the 1.4 billion year old granite and quartz monzonite basement rock in southern Arizona.

7.3 Safety Issues

BHP required that BHP employees and contractor personnel be MSHA certified. All personnel

received site safety, environmental, and cultural resources training prior to performing site activities

and mobile radios were used for communications in the field and to personnel in the Admin building. Regular safety training and tailgate sessions were performed primarily by Project Manager J. Kline,

Safety Supervisor R. Sichling, Sr. Technician J. McBroom, and Technician M. Kline. Fire safety

training exercises were prepared by R. Sichling, a volunteer Florence fireman. A program was instituted to report and respond to near-miss incidences, and adjustments made to avoid repeat

incidences.

SWVP-026458



Safety issues changed over time from a focus on safe work practices related to drill rigs, splitting

core and lifting heavy core boxes during the drilling and well installation period, to working around large earth-moving equipment during the construction of a lined pond and tank farm, and finally to

daily operation of the wellfield and tank farm. Maintenance of floating misting systems on the

evaporation pond was a two-person operation and life-vests were required for all personnel working inside the pond fence. The safety issues of consistent concern included:

Heat exhaustion,

Driving safety and potential exhaustion during long employee commutes,

Lightning and strong storm activity during the summer monsoon season,

Rattlesnakes and insects in the field, core shed, and other support buildings, and

Safe work practices by truck delivery drivers while unloading chemical shipments.


Fate transport modeling predicted that the regulated constituents within the wellfield would fall below the relevant AWQS once rinsing achieved sulfate concentrations below 750 mg/L. This was

achieved during the post-leach rinsing phase; the concentrations of trace inorganic metals met the

water quality requirements within two years without use of rinsing amendments such as caustic soda.

The base case timeframe for leaching operations, however, is 5 years with rinsing to be completed during a 2-year period. The BHP field test operated for a total of 101 days of raffinate injection and

an additional 30 days during the injection of intermediate pH, copper-bearing pond water;

reclamation continued with a reduced number of recovery wells an additional year to May 11, 1999.


Text

A bird fatality occurred during operation, which drew the attention of the agencies. In addition, the

pond was visited by geese, ducks, and pelicans. A bird harassing system should be installed prior to

stating the next test.

SWVP-026459



Table 7-1 Post-rinsing water quality results – All wells, 4th Quarter 2000

Parameter

(mg/L unless noted) AWQS

BHP1 BHP2 BHP3 BHP4 BHP5 BHP6 BHP7 BHP8 BHP9 BHP10 BHP11 BHP12 BHP13

4th Qtr 2000

4th Qtr 2000

4th Qtr 2000

4th Qtr 2000

4th Qtr 2000

4th Qtr 2000

4th Qtr 2000

4th Qtr 2000

4th Qtr 2000

4th Qtr 2000

4th Qtr 2000

4th Qtr 2000

4th Qtr 2000

Field EC (umhos/cm) - 1338 838 981 918 873 1517 1326 1448 1398 854 877 974 845

Field pH (units) - 6.51 7.23 6.58 7.12 5.81 4.06 4.06 4.61 3.8 6.78 6.78 6.7 6.68

Aluminum - < 0.025 < 0.025 0.035 0.043 0.4 4.4 4.1 3.5 4.9 0.034 < 0.025 0.085 < 0.025

Antimony 0.006 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001

Arsenic 0.05 0.001 0.001 0.002 < 0.001 0.004 0.008 0.005 0.004 0.009 0.003 0.001 0.003 0.002

Barium 2 0.053 0.056 0.042 0.022 0.0098 0.017 0.02 0.016 0.021 0.01 0.022 0.05 0.031

Beryllium 0.004 < 0.0025

< 0.0025

< 0.0025

< 0.0025 < 0.0025 0.0034 0.0034 0.0034 0.0046

< 0.0025

< 0.0025

< 0.0025

< 0.0025

Cadmium 0.005 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002

Calcium - 140 68 87 85 65 170 130 150 140 65 73 96 67

Chloride - 140 130 130 150 130 140 130 130 140 140 140 150 140

Chromium 0.1 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005

Cobalt - < 0.005 < 0.005 0.013 < 0.005 0.033 0.11 0.11 0.12 0.11 < 0.005 < 0.005 0.023 < 0.005

Copper - 0.8 0.074 1.1 0.43 7.6 24 24 28 26 0.27 0.2 1.7 0.031

Fluoride 4 0.68 0.62 0.94 1.2 1.3 1.7 1.7 1.6 2 1.3 0.5 1.3 0.54

Iron - < 0.05 < 0.05 < 0.05 0.11 < 0.05 0.15 < 0.05 0.17 0.055 0.063 < 0.05 0.14 < 0.05

Lead 0.05 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 0.002 0.003 0.001 0.002 < 0.001 0.002 0.002 < 0.001

Magnesium - 34 14 18 19 16 39 34 39 36 17 15 24 14

Manganese - 0.170 < 0.003 0.200 0.053 0.510 1.700 1.500 1.600 1.700 0.021 < 0.003 0.330 < 0.003

Mercury 0.002 < 0.0002

< 0.0002

< 0.0002

< 0.0002 < 0.0002

< 0.0002

< 0.0002

< 0.0002

< 0.0002

< 0.0002

< 0.0002

< 0.0002

< 0.0002

Nickel 0.1 0.025 < 0.02 0.022 < 0.02 0.040 0.130 0.140 0.140 0.150 < 0.02 < 0.02 0.031 < 0.02

Nitrate 10 < 1 < 1 0.39 < 0.1 0.38 0.48 0.43 0.47 0.45 0.48 0.38 < 0.1 0.4

Potassium - 6.3 5.6 6 6.1 5.3 6.7 7.3 7.3 7.6 4.8 7.3 5.1 4.8

Selenium 0.05 0.002 0.001 0.001 0.001 0.003 0.002 0.003 0.004 0.003 < 0.001 0.001 0.002 0.001

Sodium - 120 85 84 87 77 81 84 91 75 85 86 75 84

Sulfate - 390 64 130 110 160 570 450 540 490 66 66 160 62

Total Alkalinity - 93 130 100 120 34 < 25 < 25 < 25 < 25 110 130 110 130

Thallium 0.002 - - - - - - - - - - - - -

Zinc - 0.1 < 0.05 < 0.05 < 0.05 0.062 0.22 0.21 0.23 0.24 < 0.05 < 0.05 < 0.05 < 0.05

TDS - 904 493 549 493 524 1140 959 1100 1030 436 446 558 428

TPH - < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5

Adjusted Gross

Alpha (pCi/L) 15 - - - - - - - - - - - - -

Ra-226,228 (pCi/L) 5 - - - - - - - - - - - - -

Uranium - - - - - - - - - - - - -

Source: Brown and Caldwell, 2010. Samples were taken on several dates in the 4th quarter of 2000. Analyses were performed by Nevada Environmental Labs (NEL).

SWVP-026460



Table 7-2 Post-rinsing water quality results – All wells, 2nd Quarter 2001

Parameter



2nd Qtr 2001

2nd Qtr 2001

2nd Qtr 2001

2nd Qtr 2001

2nd Qtr 2001

2nd Qtr 2001

2nd Qtr 2001

2nd Qtr 2001

2nd Qtr 2001

2nd Qtr 2001

2nd Qtr 2001

2nd Qtr 2001

2nd Qtr 2001

Field EC (umhos/cm) - 1124 815 854 874 762 1171 1008 1150 1066 797 840 900 810

Field pH (units) - 6.34 7.32 7.17 7.14 5.81 3.83 4.14 4.68 3.78 6.86 7.4 6.74 7.55

Aluminum - 0.053 < 0.025 < 0.025 < 0.025 < 0.025 2.5 2.3 2 2.8 < 0.025 < 0.025 < 0.025 < 0.025

Antimony 0.006 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 0.002

Arsenic 0.05 0.002 < 0.001 < 0.001 < 0.001 0.004 0.009 < 0.001 0.004 0.009 0.003 0.001 0.003 < 0.001

Barium 2 0.043 0.05 0.053 0.017 < 0.0025 0.014 0.02 0.015 0.021 0.009 0.02 0.049 0.03

Beryllium 0.004 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 0.0028 < 0.002 < 0.002 < 0.002 < 0.002

Cadmium 0.005 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002 < 0.002

Calcium - 110 63 68 71 51 110 80 100 90 57 66 78 62

Chloride - 140 130 150 140 130 130 140 130 130 130 120 140 140

Chromium 0.1 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005 < 0.005

Cobalt - 0.007 < 0.005 < 0.005 < 0.005 0.026 0.073 0.071 0.082 0.076 < 0.005 < 0.005 0.016 < 0.005

Copper - 1 0.066 0.14 0.29 5.4 17 14 19 19 0.18 0.11 1 0.021

Fluoride 4 0.78 0.61 0.78 1.1 1.2 1.3 1.3 1.3 1.5 1.2 0.42 1.2 0.44

Iron - < 0.05 < 0.05 < 0.05 < 0.05 < 0.05 0.064 < 0.05 0.09 < 0.05 < 0.05 < 0.05 < 0.05 < 0.05

Lead 0.05 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 0.002 < 0.001 0.002 < 0.001 < 0.001 < 0.001 < 0.001

Magnesium - 30 13 14 16 14 26 21 27 25 15 14 18 13

Manganese - 0.180 < 0.003 0.011 0.025 0.370 1.100 0.860 1.000 1.100 0.010 < 0.003 0.190 < 0.003

Mercury 0.002 < 0.0002

< 0.0002

< 0.0002

< 0.0002 < 0.0002

< 0.0002

< 0.0002 < 0.0002

< 0.0002

< 0.0002

< 0.0002

< 0.0002

Nickel 0.1 0.027 < 0.02 < 0.02 < 0.02 0.029 0.081 0.084 0.093 0.093 < 0.02 < 0.02 < 0.02 < 0.02

Nitrate 10 0.54 0.35 0.36 < 0.5 0.34 < 0.5 < 0.5 < 0.5 < 0.5 0.44 0.36 < 0.5 < 0.5

Potassium - 5.9 5.3 4.4 5.1 5 6.5 6 6 6.2 4 4.1 4.9 4.4

Selenium 0.05 0.003 0.001 0.001 0.002 0.002 0.002 0.002 0.004 0.002 < 0.001 < 0.001 0.001 < 0.001

Sodium - 100 76 74 76 70 66 62 74 62 74 73 71 79

Sulfate - 240 60 73 93 110 420 280 410 360 59 64 120 52

Total Alkalinity - 80 130 130 120 44 < 25 < 25 < 25 < 25 120 140 120 130

Thallium 0.002 - - - - - - - - - - - - -

Zinc - < 0.05 < 0.05 < 0.05 < 0.05 < 0.05 0.12 0.096 0.14 0.12 < 0.05 < 0.05 < 0.05 < 0.05

TDS - 763 476 488 517 477 892 725 871 785 451 489 523 466

TPH - < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5 < 0.5

Adjusted Gross Alpha (pCi/L) 15 - 57 12.4 12.1 25.7 35.1 14 7.2 10.5 - 19.2 31.7 25.2

Ra-226,228 (pCi/L) 5 0.9 10.5 3 5.1 3.6 5.1 3.8 4 4.8 1.2 2.4 7.6 5.1

Uranium - 7 6 7.2 4.7 1.8 5.4 18.1 5 - 4.4 10.9 3.1

Source: Brown and Caldwell, 2010

SWVP-026461




Parameter



4th Qtr 2003

4th Qtr 2003

4th Qtr 2003

4th Qtr 2003

4th Qtr 2003

4th Qtr 2003

4th Qtr 2003

4th Qtr 2003

4th Qtr 2003

4th Qtr 2003

4th Qtr 2003

4th Qtr 2003

4th Qtr 2003

Field EC (umhos/cm) - 808 822 798 853 687 728 636 756 701 727 838 786 761

Field pH (units) - 6.12 7.74 7.37 6.96 6.46 3.96 5.14 4.48 4.34 6.96 7.57 7.3 7.51

Aluminum - < 0.1 < 0.1 < 0.1 < 0.1 < 0.1 0.96 0.49 0.91 1.1 < 0.1 < 0.1 < 0.1 < 0.1

Antimony 0.006 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001

Arsenic 0.05 0.002 0.002 0.002 0.002 0.005 0.010 0.009 0.004 0.006 0.004 0.002 0.002 0.002

Barium 2 0.029 0.039 0.05 0.017 0.0081 0.011 0.023 0.013 0.014 0.011 0.017 0.052 0.025

Beryllium 0.004 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 0.0011 < 0.001 0.0011 0.0011 < 0.001 < 0.001 < 0.001 < 0.001

Cadmium 0.005 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001

Calcium - 64 61 62 72 44 51 34 48 46 53 67 69 62

Chloride - 150 140 140 140 140 140 140 140 140 130 150 150 140

Chromium 0.1 < 0.001 0.002 0.001 0.001 0.001 < 0.001 < 0.001 < 0.001 < 0.001 0.001 0.001 0.001 0.001

Cobalt - 0.007 0.005 < 0.001 < 0.001 0.012 0.031 0.021 0.037 0.032 < 0.001 < 0.001 0.002 < 0.001

Copper - 1.4 0.04 0.081 0.22 2 8.5 3.4 9.6 8.9 0.14 0.048 0.2 0.017

Fluoride 4 0.91 0.69 0.55 0.88 1.7 0.86 0.94 0.92 0.96 1 < 0.4 0.84 < 0.4

Iron - < 0.05 < 0.05 < 0.05 < 0.05 < 0.05 < 0.05 < 0.05 < 0.05 < 0.05 < 0.05 < 0.05 < 0.05 < 0.05

Lead 0.05 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 0.004 0.001 0.004 0.004 < 0.001 < 0.001 < 0.001 < 0.001

Magnesium - 18 13 13 16 12 12 9 13 12 14 13 16 13

Manganese - 0.170 0.007 0.004 0.014 0.180 0.450 0.260 0.460 0.470 0.007 < 0.003 0.029 < 0.003

Mercury 0.002 < 0.0002

< 0.0002

< 0.0002

< 0.0002 < 0.0002

< 0.0002

< 0.0002

< 0.0002

< 0.0002

< 0.0002

< 0.0002

< 0.0002

< 0.0002

Nickel 0.1 0.025 0.004 0.003 0.006 0.016 0.036 0.026 0.042 0.041 0.006 0.002 0.008 0.003

Nitrate 10 0.94 0.65 0.47 0.45 0.49 0.53 0.49 0.52 0.5 0.41 0.37 0.45 0.48

Potassium - 6.4 7.4 7.1 7.6 6.2 5.8 5.5 6.2 5.7 6 6.5 5.8 6.3

Selenium 0.05 < 0.001 < 0.001 < 0.001 0.001 < 0.001 0.002 0.002 0.003 0.001 < 0.001 < 0.001 < 0.001 < 0.001

Sodium - 81 92 89 94 85 75 82 82 78 89 93 91 90

Sulfate - 130 67 69 130 67 150 97 160 130 60 97 76 57

Total Alkalinity - 64 140 150 130 84 < 6 10 < 6 < 6 130 130 130 150

Thallium 0.002 - - - - - - - - - - - - -

Zinc - < 0.05 < 0.05 < 0.05 < 0.05 < 0.05 0.052 < 0.05 0.067 0.073 < 0.05 < 0.05 < 0.05 < 0.05

TDS - 500 470 470 550 420 550 440 530 490 440 520 500 480

TPH - < 0.25 < 0.25 < 0.25 < 0.25 < 0.25 < 0.25 < 0.25 < 0.25 < 0.25 < 0.25 < 0.25 < 0.25 < 0.25

Adjusted Gross Alpha (pCi/L) 15 - - - 8.5 - - - - - - 10.3 14.8 11.5

Ra-226,228 (pCi/L) 5 1.2 - 0.4 2.4 2.2 2.6 1 2.3 2.4 0.6 4.8 6.4 4.4

Uranium - - - - 7.5 - - - - - - 5.7 14.2 6

Source: Brown and Caldwell, 2010. Samples were taken on several dates in the 4th quarter of 2003. Analyses were performed by Aerotech Environmental Labs and Radiation Safety Lab.

SWVP-026462




Parameter



4th Qtr 2004

4th Qtr 2004

4th Qtr 2004

4th Qtr 2004

4th Qtr 2004

4th Qtr 2004

4th Qtr 2004

4th Qtr 2004

4th Qtr 2004

4th Qtr 2004

4th Qtr 2004

4th Qtr 2004

4th Qtr 2004

Field EC (umhos/cm) - 813 786 810 982 714 757 663 769 709 736 849 805 782

Field pH (units) - 6.08 7.91 7.65 7.1 6.46 3.92 5.43 4.8 4.45 7.11 7.88 7.51 8.14

Aluminum - - - - < 0.2 - - - - - - - - -

Antimony 0.006 - - - < 0.001 - - - - - - - - -

Arsenic 0.05 - - - 0.002 - - - - - - - - -

Barium 2 - - - 0.019 - - - - - - - - -

Beryllium 0.004 - - - < 0.001 - - - - - - - - -

Cadmium 0.005 - - - < 0.001 - - - - - - - - -

Calcium - - - - 89 - - - - - - - - -

Chloride - - - - 120 - - - - - - - - -

Chromium 0.1 - - - < 0.001 - - - - - - - - -

Cobalt - - - - 0.004 - - - - - - - - -

Copper - - - - 0.22 - - - - - - - - -

Fluoride 4 - - - 1.1 - - - - - - - - -

Iron - - - - < 0.05 - - - - - - - - -

Lead 0.05 - - - < 0.001 - - - - - - - - -

Magnesium - - - - 20 - - - - - - - - -

Manganese - - - - 0.014 - - - - - - - - -

Mercury 0.002 - - - < 0.0002 - - - - - - - - -

Nickel 0.1 - - - 0.007 - - - - - - - - -

Nitrate 10 - - - 0.66 - - - - - - - - -

Potassium - - - - 8.6 - - - - - - - - -

Selenium 0.05 - - - < 0.001 - - - - - - - - -

Sodium - - - - 110 - - - - - - - - -

Sulfate - 110 58 66 180 68 130 85 150 110 55 95 70 51

Total Alkalinity - - - - 110 - - - - - - - - -

Thallium 0.002 - - - - - - - - - - - - -

Zinc - - - - < 0.05 - - - - - - - - -

TDS - - - - 710 - - - - - - - - -

TPH - - - - - - - - - - - - - -

Adjusted Gross Alpha (pCi/L) 15 - 28 - - - - - - - - - - -

Ra-226,228 (pCi/L) 5 - 8.5 - 3.6 - - - - - - - - -

Uranium - - 8.6 - - - - - - - - - - -

Source: Brown and Caldwell, 2010. Samples were taken on several dates in the 4th quarter of 2004. Analyses were performed by Aerotech Environmental Labs and Radiation Safety Lab.

SWVP-026463



Table 7-5 Post-rinsing water quality data – All wells, 2nd Quarter 2007

Parameter



2nd Qtr 2007

2nd Qtr 2007

2nd Qtr 2007

2nd Qtr 2007

2nd Qtr 2007

2nd Qtr 2007

2nd Qtr 2007

2nd Qtr 2007

2nd Qtr 2007

2nd Qtr 2007

2nd Qtr 2007

2nd Qtr 2007

2nd Qtr 2007

Field EC

(umhos/cm) - 916 809 805 1117 783 836 677 859 737 765 890 864 806

Field pH (units) - 6.02 7.34 7.33 6.58 6.05 4.35 5.11 4.65 4.58 6.72 7.12 6.79 7.46

Aluminum - < 0.2 < 0.2 0.2 < 0.2 < 0.2 1 0.47 1.2 1 < 0.2 < 0.2 < 0.2 < 0.2

Antimony 0.006 0.003 < 0.003 0.003 < 0.003 < 0.003 < 0.003 < 0.003 < 0.003 < 0.003 < 0.003 < 0.003 < 0.003 < 0.003

Arsenic 0.05 0.002 0.002 0.002 0.002 0.005 0.011 0.013 0.007 0.011 0.004 0.002 0.002 0.002

Barium 2 0.034 0.043 0.055 0.027 0.0071 0.015 0.026 0.017 0.015 0.0079 0.019 0.048 0.029

Beryllium 0.004 < 0.001 < 0.001 0.001 < 0.001 < 0.001 0.001 < 0.001 0.0011 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001

Cadmium 0.005 < 0.001 < 0.001 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001

Calcium - 76 63 66 110 53 54 35 54 41 55 75 75 66

Chloride - 90 130 150 130 140 130 140 130 140 140 140 140 140

Chromium 0.1 < 0.001 0.002 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 0.001 0.001 0.002 0.002

Cobalt - 0.007 < 0.001 0.001 0.002 0.014 0.035 0.024 0.043 0.028 0.001 0.002 0.002 0.001

Copper - 1.4 0.074 0.087 0.67 2.7 10 3.5 12 8.7 0.15 0.066 0.33 0.017

Fluoride 4 0.98 0.68 0.88 0.95 1.2 0.97 0.86 1.2 1.1 1.2 0.61 0.86 0.53

Iron - 0.056 < 0.05 0.05 < 0.05 < 0.05 0.32 < 0.05 0.27 < 0.05 < 0.05 < 0.05 < 0.05 < 0.05

Lead 0.05 < 0.001 < 0.001 0.001 < 0.001 < 0.001 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001

Magnesium - 21 14 15 24 15 13 10 15 12 15 15 18 14

Manganese - 0.230 < 0.003 0.020 0.043 0.240 0.480 0.270 0.530 0.420 0.006 0.003 0.025 < 0.003

Mercury 0.002 < 0.0002 < 0.0002 0.0002

< 0.0002 < 0.0002

< 0.0002

< 0.0002 < 0.0002

< 0.0002 < 0.0002

< 0.0002 < 0.0002

< 0.0002

Nickel 0.1 0.032 0.003 0.003 0.015 0.020 0.039 0.026 0.050 0.038 0.008 0.004 0.013 0.003

Nitrate 10 0.93 0.63 0.68 0.68 0.72 0.72 0.77 0.76 0.69 0.66 0.61 0.79 0.7

Potassium - 5.2 5.4 6.9 6.9 5.7 5.2 4.7 5.4 5.3 4.8 5.6 5.2 5.2

Selenium 0.05 0.002 < 0.002 0.002 0.002 0.003 0.002 0.002 0.005 0.003 < 0.002 < 0.002 0.002 < 0.002

Sodium - 88 94 100 110 93 86 88 95 86 92 100 93 95

Sulfate - 160 56 62 250 100 170 81 190 140 52 100 96 50

Total Alkalinity - 58 130 120 95 55 < 6 9 < 6 < 6 110 120 120 140

Thallium 0.002 - - - - - - - - - - - - -

Zinc - < 0.05 < 0.05 0.05 < 0.05 < 0.05 0.058 < 0.05 0.051 < 0.05 < 0.05 < 0.05 < 0.05 < 0.05

TDS - 600 500 490 770 500 600 470 640 530 450 550 540 480

TPH - - - - - - - - - - - - - -

Adjusted Gross

Alpha (pCi/L) 15 - 11.9 8.9 - - - - - - - - 5 3.8

Ra-226,228 (pCi/L) 5 < 0.4 8.9 5.6 3.3 1.4 3.6 < 0.3 2.2 1.6 < 0.4 3.6 6 3.9

Uranium - - 7.7 9.6 - - - - - - - - 14.6 6

Source: Brown and Caldwell, 2010. Samples were taken on several dates in the 2nd quarter of 2007. Analyses were performed by Aerotech Environmental Labs and Radiation Safety Lab.

SWVP-026464



8 References Arizona Department of Environmental Quality (ADEQ), 2004, Arizona mining guidance manual,

BADCT: State of Arizona Publication # TB 04-01, 293 p.

Beane, Richard, 1998, The blue precipitate in the well bore: unpublished memorandum from R. Beane to J. Kline and R. Preece, BHP, March 16, 1998, 6p.

BHP Copper Inc., 1997a, Florence Project – Final pre-feasibility report, v. II Geology: unpublished

document prepared by the BHP Copper Growth and Technology Group, 180 p.

_____, 1997b, Florence Project – Final pre-feasibility report, v. III Environmental permitting, legal

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SRK Consulting Summary of BHP Field Test and Updated Work Appendices


Appendices

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Appendix A: Wellfield Extraction Graphs

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Appendix B: Water Quality Graphs

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summary of the bhp field test and update work€¦ · 26/10/2011 · (bhp-10 to bhp-13) and 14 to...

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