SPE 134602

A Process to Evaluate Unconventional Resources Phillip Chan, SPE, Consultant; John R. Etherington, SPE, PRA International; Roberto Aguilera, SPE, University of Calgary Schulich School of Engineering

Copyright 2010, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in Florence, Italy, 19–22 September 2010. This paper was selected for presentation by an SPE program committee following review of information contai ned in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily refle ct any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Socie ty of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract It is the intention of the SPE/WPC/AAPG/SPEE Petroleum Resources Management System (PRMS) to provide a consistent

approach to estimating petroleum quantities, evaluating development projects, and presenting results within a comprehensive classification framework. The reserves and resources definitions and application guidelines are designed to be applicable to both

conventional and unconventional petroleum accumulations, regardless of their in-place characteristics, the extraction method

applied, or the degree of processing required to yield a marketable product.

The fact that unconventional resources are usually pervasive throughout a large area and are not significantly affected by

hydrodynamic influences may require different approaches in evaluation. Assessments may include an increased sampling density

to define uncertainty of in-place volumes, the variations in quality of reservoir, and hydrocarbons and their detailed spatial

distribution for the design of specialized extraction methods.

This paper summarizes the special problems in the estimation and evaluation of several resource types ranging from shale gas to

bitumen. The material is largely drawn from the soon to be published SPE Application Guidelines to the PRMS, supplemented with illustrations from actual field examples.

The rapidly advancing exploitation of unconventional resources has opened up many development opportunities, especially in

North America. Shale gas and bitumen have already caused major impact on energy supply. We anticipate these opportunities

will expand rapidly throughout the world. Achieving a better understanding of the special problems in unconventional resources

evaluation will help us build on PRMS to develop a more consistent approach to classification and categorization, accounting for

unique project risks and uncertainties.

Introduction In March 2007, the Society of Petroleum Engineers (“SPE”), the World Petroleum Council (“WPC”), the American Association of

Petroleum Geologists (“AAPG”) and the Society of Petroleum Evaluation Engineers (“SPEE”) jointly published the Petroleum

Resources Management System (“PRMS”) (SPE et al, 2007) to provide an international standard for classification of oil and gas reserves and resources. PRMS was subsequently endorsed by the Society of Exploration Geophysicists (“SEG”). PRMS was

designed to update, consolidate, and replace the 2000 SPE /WPC/AAPG publication “Petroleum Resources Classification and

Definitions” (SPE et al, 2000). A companion document “Guidelines for the Evaluation of Petroleum Reserves and Resources”

(SPE et al, 2001) was published 2001; this supplemental guidance has proved to be a valuable aid in consistently applying the

classification framework to enhance internal reporting. A PRMS Applications Document is currently under development to update

and expand the 2001 guidelines. One key area that was not previously discussed relates to the emerging focus on unconventional

(or non-traditional) resources. This paper provides a preview of a chapter on “Unconventional Resources Evaluation” to be

included in this document.

2 SPE 134602

Conventional and Unconventional Resources Two types of petroleum resources have been defined that may require different approaches for their evaluations:

a. Conventional resources exist in discrete petroleum accumulations related to a localized geological structural feature

and/or stratigraphic condition, typically with each accumulation bounded by a down dip contact with an aquifer, and

which is significantly affected by hydrodynamic influences based on buoyancy of petroleum in water. The petroleum is

recovered through wellbores and typically requires minimal processing prior to sale.

b. Unconventional resources exist in hydrocarbon accumulations that are pervasive throughout a large area and that are

generally not significantly affected by hydrodynamic influences (also called „continuous-type deposits‟). Such

accumulations require specialized extraction technology and, in the case of oil, the raw production may require significant processing prior to sale.

1

Conventional

Reservoirs

Tight Gas Sands

Coalbed Methane

Gas Hydrates

Heavy

Oil

Bitumen

Oil Shale

Incre

ased P

ricin

g

Imp

rove

d T

ech

no

logy

(modified from Holditch, JPT Nov. 2002)

Extra -Heavy

Oil

Shale Gas

Basin-centered Gas

Conventional

Unconventional

Figure 1: Petroleum -Resource Triangle

The relationship between conventional and unconventional resources is illustrated by a resource triangle (Figure 1). Heavy oil and tight gas formations straddle the boundary; nonetheless, both present challenges in applying assessment methods typically used for

conventional accumulations.

Very large volumes of petroleum exist in unconventional reservoirs but their commercial recovery often requires a combination of

improved technology and higher product prices. Industry analysts project that unconventional liquids reservoirs (excluding oil

shale) may contain 5.8 trillion barrels initially-in-place; oil shales may add over 2.8 trillion barrels (WEC, 2007). The in-place

estimates for unconventional gas accumulations range over 30,000 TCF (excluding gas hydrates) versus 2,800 TCF produced to

date (NPC, 2007). Estimates for gas hydrates volumes in-place vary widely between 35,000 and 61,000,000 TCF (EIA, 1998);

however, no commercial recovery methods have yet been developed to extract these volumes.

It is intended that the PRMS resources definitions, together with the classification system (Figure 2), will be appropriate for all

types of petroleum accumulations regardless of their in-place characteristics, extraction method applied, or degree of processing required. However, specialized techniques are often employed in assessing in-place quantities and evaluating development and

production programs.

Estimations of recoverable resource quantities must include an assessment of the associated uncertainty expressed by allocation to

PRMS categories using the same low/best/high methodology as for conventional resources. Typically the evaluation process

begins with estimates of original-in-place volumes. Thereafter, portions of the in-place quantities that may be potentially

recovered by identified development programs are defined.

As in conventional accumulations, undiscovered recoverable volumes are classed as Prospective Resources and are estimated

assuming their discovery and commercial development. PRMS recognizes that the hydrocarbon type and/or the reservoir quality

may not support a flowing well test but the accumulation may be classed as „discovered‟ based on other evidence (e.g. sampling and/or logging). It is not uncommon to recognize very large areas where prior drilling results have identified the presence of a

SPE 134602 3

„discovered‟ resource type that, based on analogs, has production potential. Where technically feasible recovery techniques are

identified but economic and/or other commercial criteria are not satisfied, even under very aggressive forecasts, estimates of

recoverable quantities are classified as Contingent Resources and sub-classified as Development Not Viable. If the recovery

processes have been confirmed as not technically feasible, the in-place volumes are classified as Discovered/Unrecoverable. As

the play and technologies mature and development projects are better defined, portions of estimated volumes may be assigned to

Contingent Resources sub-classes that recognize this progressive technical and commercial maturity. Reserves are only attributed

after pilot programs have confirmed the technical and economic producibility and capital is allocated for development.

On Production

Approved for

Development

Justified for

Development

Development Pending

Development

not Viable

Prospect

Lead

Play

Development On Hold

Development Unclarified

Figure 2: PRMS Reserves and Resources Classification with Project Maturity Sub-Classes

Note that under PRMS, the reserves and resource quantities reported are in the conditions as delivered at the custody transfer

(sales) point. In many cases, the raw production must be further processed to yield a marketable product. Integrated

development/processing projects include the cost of the processing and related facilities in the project economics; in other cases,

the raw production is sold to a 3rd party (at a reduced price) for further processing. In either case, development economics are

highly dependent on the capital and operating costs associated with complex processing facilities.

The recent emergence of unconventional plays as commercial ventures has brought the realization, that the publicly available

literature on standard assessment methods and illustrative examples for unconventional resources is limited. Since these accumulations are often pervasive throughout a very large area and are developed with high density drilling, well productivity is

often highly variable. Therefore probabilistic assessment techniques may be more applicable than in conventional plays.

The PRMS Application Document provides preliminary information on evaluation approaches utilized in the following resource

types generally referred to as „unconventional‟:

Extra-Heavy Oil

Bitumen

Tight Gas Formations

Coal Bed Methane

Shale Gas

Oil Shale

Gas Hydrates

4 SPE 134602

It is envisaged that these sections will be updated and expanded in future editions as the plays mature and evaluation methods are

better defined.

Process in Evaluating Unconventional Resources In the exploitation of unconventional resources there are typically four main stages in the assessment process: Exploration,

Evaluation, Delineation, and Development (Haskett and Brown, 2005). All resource evaluations begin with the identification of

hydrocarbons in sufficient quantity to potentially support commercial development. Thereafter the focus is on identifying the

development techniques that can overcome the technical or economic constraints limiting commercial development.

Before the reserves can be estimated and categorized according to the level of certainty, the unconventional resources will need to

be classified based on the development project‟s chance of commercialization. The logic flow based on PRMS classification principles discussed above, are clearly illustrated in Figure 3 and 4. After the Discovered Petroleum Initially in-Place (DPIIP) has

been established, the sub-classification of Contingent Resources will be carried out from which different categories will eventually

be estimated. Once an economically viable development program has been identified, the company has committed to its

implementation and there is a reasonable certainty that any contingencies preventing development will be satisfied, only then may

the marketable volumes be reclassified as Reserves. PRMS further requires that the development will be normally initiated within

a reasonable time frame (e.g. five years); any exceptions must be clearly documented.

Figure 3: Establishing PRMS Total Discovered Petroleum Initially–In-Place Resources (Adapted from Elliott, 2008)

SPE 134602 5

Figure 4: Establishing PRMS Contingent Resources and Reserves (Adapted from Elliott, 2008)

Assessment and Classification Issues Unconventional resources often necessitate different assessment approaches than applied to conventional projects. In most cases

the existence of in-place hydrocarbons over a large area has already been confirmed, thus „discovery risk‟ is minimal. The primary challenges in evaluating unconventional resources are in establishing sufficient scale and recovery rates to support commercial

projects.

A key component of commercial development is a land acquisition strategy which can provide a sustainable inventory of future

drilling locations. The extraction of unconventional resources such as extra heavy oil, bitumen and oil shale may involve

specialized processing facilities which requires minimum feedstock threshold and sustainable production rates to justify

development. The location of a heavy oil upgrader in the immediate vicinity of the heavy oil deposit is a typical example where

the quantity and rates of recovery of the unconventional resource is paramount to the economic justification of the facility.

There are invariably „sweet spots‟ in large unconventional plays because of the regional heterogeneity of the formation. The

reservoir quality in these areas is much superior to the rest due to higher permeability and porosity values, thicker pay, better net to gross ratios or higher pressure (overpressure). “In unconventional resource development, it is often the case that development

starts at the most advantageous parts of the field and then extends in time to the fringe areas as described in the modular

development concept” (Vassilellis, 2008).

Assessment is initiated by „detailed mapping‟ of the resource. This involves increased sampling density to define the potential of

the play, identify the sweet spots, and delineate the fringe areas. Next, pilot projects are initiated to demonstrate that the

specialized extraction techniques are technically and commercially viable. When moving away from the sweet spots, the

geological degradation and the possible increase in extraction costs must be considered in the classification and categorization of

the resource. PRMS guidance suggest that, similar to improved recovery projects applied to conventional reservoirs, successful

pilots or operating projects in the subject reservoir or successful projects in analogous reservoirs are required to establish required

recovery efficiencies for non-conventional accumulations.

For new plays, where there is not sufficient history of development, analogy with other similar reservoirs can be employed in the

initial assessment. “Analogs are defined by features and characteristics including, but not limited to approximate depth, pressure,

temperature, reservoir drive mechanism, original fluid content, reservoir fluid gravity, reservoir size, gross thickness, pay

6 SPE 134602

thickness, net to gross ratio, lithology, heterogeneity, porosity, permeability and development plan” (Hodgin and Harrell 2008).

Once results from the pilots have been obtained, future development in the same reservoir can be assessed based on comparisons

to the pilot areas. For conventional resources, the analogous parameters are mostly volumetric based such as fluid contacts; lowest

known hydrocarbons; structural position; and saturations. For unconventional resources geomechanical and geochemical factors

such as organic richness; thermal maturity; and sorption isotherms should be considered, in addition to the conventional

parameters of porosity, thickness and saturations.

The PRMS is project-based and commerciality has to be confirmed before classification of the recoverable resources as Reserves

can be undertaken. For a particular resource play different projects can be implemented sequentially to take advantage of the

better reservoir quality and lower operating costs areas, especially in the midst of low commodity prices. Most of the

unconventional resources are long life projects with a producing life of twenty to thirty years and above. A better understanding of the economics and probability of recovery can be obtained by phased development scenarios, especially to take advantage of the

sweet spots. As more information is obtained and the associated development risks are addressed, the program will be

continuously modified. PRMS is ideally suited to the evaluation and management of these different projects which can be

aggregated.

Once a viable development process has been established, one of the keys to economic projects is to take advantage of the scale of

operations. Vassilellis (2008) discussed the Factory Concept which is mainly an assembly line approach to field development

where similar operations become concurrent. “As long as operation intensity is maintained, the production level would be in a

plateau, which would be ideal for facility sizing and product marketing. In addition, the building of a materials inventory would

ensure the smooth execution of the plan without disruptive supply delays and by being able to negotiate procurement of services

and material at best terms. Quality assurance and surveillance would also apply as in a manufacturing process.”

This „Manufacturing Process‟ may be a development model for unconventional resources which can be transferrable from one play

to another. However, there are inherent risks associated with this concept. Even though the unconventional resource may exist in

large quantities over a wide area, there comes a time when lands cannot be obtained fast enough or in sufficient quantities to keep

up with the demand and maintain the production in a plateau. This can be due to various reasons such as competition or regulatory

and environmental factors as evidenced in some of the Appalachian shales projects. The building of a materials inventory such as

availability of fracturing sands and water for the massive stage fracs cannot be guaranteed. The heterogeneity of the play may

force different and unproven techniques to be developed and applied thus reverting to a sequential phased development in some

areas. The current cycle of low commodity prices and reinvestment risks may pose extra hurdles. All of these factors should be

considered in the establishment of the commerciality of the project.

Evaluation of Shale Gas Resources Shale gas plays have recently emerged as an abundant unconventional resource. This has resulted from improved technology

including directional drilling, multilateral horizontal wells, multi-stage fracturing, improved completion fluids and fracture

mapping using microseismic. The development of unconventional gas projects has created a major impact on the gas supply and

prices in North America. With limited production data; low commodity prices and other issues discussed above, it has been

difficult to clearly classify the resource and categorize the reserves. A process to evaluate shale gas plays based on the PRMS is

discussed below and may serve as a template in addressing these issues. While the following focuses on shale gas, similar

assessment methods may be applied to all unconventional resources.

Shales and tight gas have been increasing in importance as an energy source in North America in recent years (Wolff; Patel and

Hoffman, 2009). “This resource potential is rapidly being turned into reserves and production. In fact, U.S. natural gas Proved

Reserves rose 27% over the last five years to 238 TCF at year-end 2007. Shale gas production is now some 13% of total U.S.

production, up from 1% early in the decade.” The big-five U.S. shale plays include the Barnett, Marcellus, Haynesville, Fayetteville, and Woodford. Additional resource potential is now being uncovered in the Eagle-Ford and Cana (Western

Oklahoma) shales in the U.S.; and the Horn River Basin and Utica shales in Canada.

The estimation of Discovered Petroleum-in-Place takes into account all prior wells in the areas in question and all available

geological and flow information. Estimation of Contingent Resources will require input of working interest lands to be developed

and the well count to be drilled, including vertical and horizontal wells. Recovery factors are then assigned based on type decline

curves of analogous wells or results from pilot projects. Low, best and high estimates are derived by assigning incremental

recovery factors to free gas and adsorbed gas. Condensate and natural gas liquids yields are projected based on the gas analyses

SPE 134602 7

and facilities design. If a project meets economic hurdles and there are no additional contingencies, then the range of Reserves can

be estimated by deterministic methods and/or a probabilistic approach.

Probabilistic Approaches Probabilistic methods can be used in two general approaches to leverage incomplete data sets.

Volumetric Analysis: Similar to conventional resource evaluations, the key parameters can be modeled with mathematical

distributions and combined in Monte Carlo simulations to derive a results distribution. In the case of shale gas, the key inputs may

include total organic carbon (TOC), porosity, matrix and sorbed gas saturation. The range of recovery efficiencies applied to

estimate recoverable gas may be influenced by rock mechanics factors (brittleness/susceptibility to hydraulic fracturing, natural

fracture density). As in conventional reservoirs, the objective is to define the full range of potential outcomes rather than focus on selected deterministic scenarios.

EUR Distributions: Statistical analysis techniques may be more applicable to unconventional resources because of the sheer size

of the accumulations and the large number of wells involved; essentially it is an extension of the analog approach. The premise is

that the distributions of performance data from existing producing wells can be used to predict the performance of groups of

undrilled locations. The approach first requires identifying groups of wells within the play area not only in very similar geological

settings (pay thickness, saturations, fracturing, etc) but also using very similar completion methods (horizontal wells, multiple

hydraulic fracturing programs). Then, for each well, decline curve analysis (DCA) is used to define an Estimated Ultimate

Recovery to an economic limit. In the early stages of development sufficient data may not be available to establish a reliable DCA

but limited data and analogs (type curves) may establish a relationship between peak rate and EUR. By fitting a statistical

distribution to the suite of EUR data, one can derive P90/P50/P10 estimates of recoverable volumes. This same distribution can

then be applied to groups of wells in undrilled areas. Assuming the wells are in a contiguous area and total project commerciality has been established, the results would represent 1P/2P/3P Reserves.

Note that even adjacent wells in the play may have dramatically different initial rates and EURs but as a group there is a definable

distribution. The larger the group (more wells) the more reliable the estimates will be. Although the reservoirs may be

heterogeneous on a local scale, there is significant homogeneity in groups of wells in segments of the play.

Having established a drainage area for typical wells, the number of additional wells required to fully develop the property can be

projected and thus the overall potential reserves can be estimated. Note that this is a pure statistical approach and relies on several

assumptions:

1. The decline analysis is a reliable indicator of EUR. In many shale gas programs, the initial production may be in transient flow for extended periods. The inputs to harmonic decline cannot be validated. Typically initial high rates decline rapidly and the

„tail‟ may extend over 30 years until economic limit.

2. There is a reasonable correlation between peak rate and EUR.

3. The distribution of EURs is repeatable within analogous subgroups.

4. The reservoir within the study area is sufficiently homogeneous and the completion practices sufficiently similar to support

this analog approach.

An additional factor in assumption number 3 is the “aggregation effect” related to the very large number of wells. Using the shale

gas example, the recoverable volumes in a specific project area (subgroup) may be the summation of 100‟s of individual well EUR

analyses. The Central Limits Theorem tells us that as we independently aggregate individual well EUR distributions (even when

each distribution is lognormal) the resulting aggregate will tend towards a normal distribution and the P90 and P10 will converge

on the mean.

Figure 5 illustrates the concept whereby the arithmetic sum of the P90 volumes (150) of five identical entity level distributions is

compared to the P90 volume (330) resulting from an independent probabilistic aggregation of the same five distributions. Even if

we assume only partial dependency, the P90 of the probabilistic aggregate distribution will be much larger than the simple

arithmetic sum of the P90 volumes from the individual wells. The aggregation process reduces program uncertainly and increases

confidence in achieving project forecasts. PRMS, and most regulatory disclosure guidelines, accept probabilistic assessment

methods and probabilistic aggregation to the field, property, or project level; reported results for higher level aggregations use

simple arithmetic summation of individual reserves categories. Thus, assuming that we have established project commerciality,

8 SPE 134602

the P90 of the aggregate represents the Proved Reserves. The same aggregation effect reduces the 3P (P10) estimates and, at some

stage, the Proved approaches the 2P estimate for the total project.

While the application of this statistical analysis technique is currently being applied internally by operators in shale gas and other

unconventional plays, its acceptance by regulators for public disclosure has not yet been confirmed. Within this concept, it is

accepted that individual wells or clusters of wells within the play may not be economic on a standalone basis but the overall

project meets the commerciality criteria.

100

0

Arithmetic Sum Proved (dependent aggregate)

Estimated Ultimate Recoverable

P10

P90

Cum

ula

tive P

robabili

ty o

f “X

” or

gre

ate

r

5 Entity

Level

Distributions

150Monte Carlo (Independent) Aggregate

330

Project Level

Aggregates

P90 330 150 30

P50 560 435 87

P10 938 1250 250

Figure 5: Comparison of Deterministic Summation and Independent Probabilistic Aggregation

Deterministic Approaches The oil and gas industry has used deterministic approaches for several decades and the techniques need not be repeated here.

Suffice to say that they are generally based on volumetric calculations for determining the initial volumes of gas-in-place, and

decline type curve analysis for determination of EURs. In mature shale reservoirs, such as the Barnett, these curves provide good

levels of certainty and under favorable circumstances a correlation may be established between the peak rate and the ultimate

recovery. However, this correlation will need to be revised over time, as more data is obtained.

Uncertainties in Classifying Resources Using the PRMS System Shale gas examples are used herein to illustrate the resource assessment process. The Barnett Shale is a mature play and the Utica

Shale is an immature play, with the Fayetteville somewhere in between. All data utilized in this section for illustration purposes is

publically available in the literature and in websites of companies operating in shale gas reservoirs. While the assessments are

described using a deterministic approach, the same method can be extended to evaluations using probabilistic methods discussed in

a previous section.

Previous to popularization of the words „resource play concept‟ within the last decade approximately 100,000 acres of potentially

gas bearing shales were mapped from seismic data in the Saint Lawrence Lowlands of Quebec (Canada) in the 1970s. A key

objective of the mapping was to try to understand the distribution of the Ordovician Utica shales (Figure 6).

Results of one of the early attempts to quantify volumes of natural gas in the Utica shales and potential recoveries were published

in the SPE literature in 1978 (Aguilera, 1978). The assessment was based on estimates of fracture porosity and water saturation, and the volumes of Original Gas-In-Place (OGIP) were determined volumetrically. The work led to volumes of free gas in the

fractures ranging between 5.9 and 26.6 bscf per section (640 acres). The recovery was estimated on the basis of free gas in the

fractures, without considering any adsorbed gas, by assuming an abandoning pressure of 100 psi per 1,000 feet of reservoir depth.

SPE 134602 9

The result was estimated ultimate recoveries ranging between 4.7 and 21.4 bscf per section at an abandonment pressure of 625 psi.

The initial reservoir pressure used in the estimate was 3,000 psi.

Figure 6: Shale Gas Basins in Canada and the United States (adapted from Theriault, 2008)

A forecast per well was carried out by assuming continuous transient linear flow throughout 20 years without reaching any

boundary effects. The initial average rate for the first year of production was estimated at 0.5 MMscfd based on actual testing

results of vertical wells. Gas cumulative after 20 years of production was calculated to be 2.5 bscf. A preliminary analysis of a

partial development project drilling 90 wells were considered by the author to be potentially economic with only 46 successful wells required to break even. In spite of this economic evaluation the project was deemed to have a large degree of risk and a low

chance of commerciality and the project was put on hold. At the time when this work was completed, industry activity in the

development of unconventional resources was not prominent, and classifying of unconventional resources was not emphasized.

Operators were only interested in the booking of Reserves, the methodology of which may not correspond with today‟s thinking.

If we now review this project 30 years later we may classify the potentially recoverable volumes from the Utica Shale under

PRMS as Prospective Resources with a range of uncertainty between low and high estimates of 4.7 and 21.4 bscf per section,

respectively. The project will be in the assessment and evaluation phase until sufficient wells have been drilled that would allow

portions to be reclassified as „Discovered Petroleum Initially in Place‟ and then Contingent Resources. As the Utica shales extend

over 150 square miles, the potential recoverable resources of the total play may be between a low of 711 bscf and a high of

approximately 3,200 bscf. This initial volumetric estimation is very approximate only and will be refined as the project matures.

There have been significant advances during the last few years particularly on issues related to drilling and completion of

horizontal wells in shale gas formations. These technologies have been used successfully in several shale reservoirs including, for

example, the Barnett in Texas. Based on results to date, the industry has developed a useful “rule of thumb” that a hydraulic

fracture stage in a horizontal well is approximately the equivalent, from a gas production point of view, to a vertical well.

These recent innovative technologies are being applied in the shales. Figure 7 attempts to show learning curves comparing gas

production from the Fayetteville shale in the United States and the Utica shales. It also points out some of the uncertainties

evaluators may encounter when they evaluate shale plays. At first glance there appears to be a continuous improvement with time

in gas production rates in both reservoirs. However, the data used are only based on announcements by the different operators.

There is usually no information on the geological characteristics of the wells and the grouping may have to be refined for the

10 SPE 134602

purpose of comparison. Another uncertainty is the definition of production rate. Most companies report the peak flow rate right

after completion while others report a 30 day Initial Production Rate (IP). Care must be taken to use consistent data.

The latest horizontal well drilled in the Utica shales in early 2010 was the Saint Eduard No. 1A with a reported maximum flow rate

of over 5 MMscfd (Web Sites of Companies Operating in Shale Gas Reservoirs). This rate is anomalous compared to previous

data and is expected to decline substantially. If sustained rates can be confirmed in additional wells, portions of the Utica shale gas

play can be reclassified as Contingent Resources. At present, Utica resources are sub-commercial but depending on the pilot

results and other commerciality issues, portions of these resources may meet Reserves criteria in the future.

Fayetteville

Utica

Figure 7: Learning Curves Comparison between the Fayetteville and the Utica Shales

(Web Sites of Companies Operating in Shale Gas Reservoirs)

Most of the new shale plays have been compared to the Barnett which has substantially more production history and the production decline rates are rolling over. Table 1 compares the characteristics of the Utica and the Barnett. This is not intended to

draw an analogy between the two but rather to show that even though there are variances in the formations, the original gas in-

place calculations may result in similar numbers. However depending on the maturity of the shale projects, the outcomes may be

quite different when classifying the original gas in place into Resources and Reserves.

The methodology for the calculations shown on Table 1 has been presented by Aguilera (2010). An important objective is

determining gas in-place and what portion of the total volume is stored as free gas. Some of the characteristics of the Utica and

Barnett shales are different, for example, the percent TOC, the carbonate content and the directional stress of the formation.

Others, such as free gas porosities are considered to be of the same order of magnitude. For example, free gas porosity for the

Barnett has been estimated at 1.7% by Wang and Reed (2009) while free gas porosity for the Utica shale has been estimated at

1.4% by (Aguilera, 1978).

Volumetric estimates of total OGIP per acre-ft are of the same order of magnitude (104.8 for the Barnett and 96.5 for the Utica).

Volumetric estimates of free OGIP per acre-ft also compare reasonably well (50.9 for the Barnett and 40.9 for the Utica).

Furthermore both reservoirs have readily available access to markets.

SPE 134602 11

Item Characteristic Barnett, FWB Utica, Québec

1 Total porosity of shale, øsh 0.050* 0.066**

2 Free gas porosity, øfree 0.017* 0.014**

3 Percent total organic content by weight, TOCwgt 5.00* 1.70

4 Percent total organic content by volume, TOCvol 10.00* 3.40

5 Percent of total porosity filled with free gas, Vfree 34.00 21.21

6 Assumed temperature, Deg. F 180 115

7 Assumed pressure, psia 3,800 3,000**

8 Gas formation volume factor, Bgi, cf/scf 0.00419 0.00477**

9 Assumed Swif in free gas porosity, percent 0.00 0.00

10 Assumed Swi total in composite system, percent 30.00 50.00**

11 Total gas porosity, øgas 0.035 0.033**

12 Free original gas-in-place, OGIPfree, scf/acre ft 176,743 127,900

13 Total original gas-in-place, OGIPt, scf/acre ft 363,883 301,479

14 Original gas-in-place adsorbed in matrix, OGIPadsorbed, scf/acre ft 187,140 173,579

15 Percent of free gas 48.57 42.42

16 Percent of adsorbed gas 51.43 57.58

17 Thickness, ft 450 500

18 Total OGIP per section (bscf/section) 104.80 96.48

19 Free OGIP per section (Bscf/section) 50.90 40.93

* Data from Wang and Reed, 2009

** Data from Aguilera, 1978

Table 1: Comparison of the Barnett Shale, Fort Worth Basin (FWB), United States; and Utica Shale, Quebec, Canada.

In spite of the above reasonable comparisons most of the Barnett is assigned Reserves because the „project base‟ evaluation,

including pilots, is commercial, presents low risk, and has well defined production decline type curves that decrease significantly

the range of uncertainty. On the other hand, the Utica is still lacking definitive results from pilot projects and clearly defined production decline curves. Recent Utica well test results, even though encouraging, may not be sufficient to allow moving some

of the gas volumes from the Prospective to the Contingent Resource class. Commerciality depends on production rates and until

we have a better understanding of that parameter we cannot establish this criterion.

Conclusion The Petroleum Resources Management System (PRMS) has proved to be a valuable tool for consistent evaluation and reporting of

conventional hydrocarbon reserves and resources. The same basic principles regards risk and uncertainty apply to unconventional

resource assessments:

classification is based on the chance of commerciality of the project being applied

categorization describes the relative uncertainty in the range of marketable volumes derived from applying the

development project to an accumulation

12 SPE 134602

Once exploratory drilling has demonstrated the presence of producible hydrocarbons in sufficient quantities to justify potential

development, portions of the accumulation may be deemed “discovered” and thus reclassified from Prospective to Contingent

Resources. In the early stages assessments are influenced by comparisons to similar reservoirs in more mature development

phases. This approach is illustrated by comparing three North American shale gas projects at different stages of maturity. The

Utica Shale is in the very early stages of study. The Barnett Shale projects are considered as mature; however, there remain major

uncertainties regards ultimate recoveries. The Fayetteville is at an interim stage of maturity. While there are significant differences

in the detailed geology, there are sufficient similarities to allow transfer of learning regards completion and development scenarios

to make preliminary estimations of overall potential in the Utica Shale. However, the technical and commercial viability for

development of this unconventional resource must be first be demonstrated by successful pilot projects before conversion to

Reserves.

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