arc · as the slickline company continued to grow, an emerging technology, memory production...

ARC Pressure Data Inc.

ARCARCARCARCPRESSURE DATA

I N C O R P O R A T E DI N C O R P O R A T E DI N C O R P O R A T E DI N C O R P O R A T E D

June 1, 2001

PRESSURE TRANSIENTTEST GUIDE

TABLE OF CONTENTS

ARC Pressure Data Inc. i

Chapter Heading Page 1 Introduction 1-1 Purpose 1-3 ARC Vision and Mission 1-4 Company Profile 1-5 Surface Equipment Capabilities 1-6 Safety, Training, and Insurance 1-7 2 Well Test Instrumentation 2-1 Pressure Gauge Attributes 2-3 Accuracy 2-3 Resolution 2-3 Range 2-4 Response Time 2-4 Sampling Rate/Programmability 2-4 Durability 2-4 Tandem/Backup Gauges 2-5 Pressure Gauge Types 2-6 Bottomhole Pressure Gauges 2-6 Surface Readout Gauges 2-7 Automatic Well Sounder Systems (AWS) 2-7 Surface Pressure Gauges 2-8 3 Gauge Setting and Deployment Methods 3-1 Background and Assumptions 3-3 No-Go on Seating Nipple 3-4 Whiskered Bomb Hanger for Collars 3-5 Whiskered Bomb Hanger for Tubing 3-6 Whiskered Bomb Hanger for Casing 3-7 Gauge Carrier Below Bridge Plug 3-8 Mud Anchor Below Rod-Pump 3-9 “Piggyback” Gauge Carrier 3-10 Pup Joint Gauge Carrier 3-11 Hang On Wire 3-12

TABLE OF CONTENTS (Cont.)

ARC Pressure Data Inc. ii

Chapter Heading Pressure Transient Test Types 4-1

Overview of Test Types 4-3 Single-Rate Tests / Producing Wells 4-4 Pressure Buildup Test 4-4 Flowing Wells 4-5 Sucker Rod Pumped Wells 4-7 Swabbing 4-10

Gas Lift 4-12 Plunger Lift 4-13

Electrical Submersible Pump 4-15 Jet Pump 4-18 Summary of Production and Test Methods 4-19 Pressure Drawdown Test 4-20 Flowing Wells 4-21 Sucker Rod Pumped Wells 4-23 Electrical Submersible Pump 4-25 Summary of Production and Test Methods 4-28

Single-Rate Tests / Injection Wells 4-29 Pressure Falloff Test 4-29 Falloff Test Methods 4-30 Pressure Injectivity Test 4-32 Injectivity Test Methods 4-34 Multirate Tests 4-35 Flow-After-Flow Test 4-35 Isochronal Test 4-37 Modified Isochronal Test 4-39 Step-Rate Test 4-41 Railroad Commission of Texas Guidelines 4-43 Multiwell Tests 4-44 Interference Test 4-44 Pulse Test 4-46 Specialized Tests 4-48 Vertical Interference/Pulse Test 4-48 Measurement While Hydraulically Fracturing 4-49 5 Diagnostic and Wireline Services 5-1

Logging 5-3 Diagnostic Services 5-3 Regulatory Forms 5-3 Wireline Services 5-3

TABLE OF CONTENTS (Cont.)

ARC Pressure Data Inc. iii

Chapter Heading Page 6 Regulatory Testing Services 6-1

Texas 6-3 New Mexico 6-3 Other States 6-3

7 The Well Test 7-1

Scheduling and Setting Up the Test 7-3 Reporting the Data 7-6 Quality Control 7-8

8 Pressure Transient Analysis Services 8-1

Analysis Input Parameters 8-3 Reporting of Analysis Results 8-7

ARC’s philosophy - Application of Results 8-10 Appendix Job Input Sheets

AWS Job Input Sheet Analysis Input Parameter Sheets

Abstract – “Establishing Design Criteria for Pressure Buildup Tests”, Scott M. Frailey, Aaron E. Pierce, and Gary E. Crawford

Abstract – “Errors in Input Data and the Effect on Well-Test Interpretation Results”, J.P. Spivey and D.A. Pursell

ARC Pressure Data Inc. iv

ARC Pressure Data Inc. 1-1

CHAPTER 1

INTRODUCTION

INTRODUCTION PURPOSE


Over the years, numerous published materials and training courses have been available for the purpose of learning pressure transient test theory. Also available are materials and courses for learning wireline skills. However, there is little information available addressing the everyday problems associated with “getting the bomb down the hole” while at the same time adhering to the theoretical constraints of pressure transient theory as closely as possible. This service catalog was created to help “fill the gap” between pressure transient textbooks and wireline training manuals. The intent of this catalog is to assist customers in designing tests that will result in useable pressure transient test data. It should be understood that this catalog assumes a basic understanding of pressure testing theory, that it mainly serves to help connect the theory to the field operations. It is always an engineers ultimate responsibility to verify that a test is being designed and performed properly. It should also be understood that this is not a wireline training manual. Although this catalog discusses many wireline procedures associated with well testing, it does not thoroughly cover this subject. Again, an assumption is made, that all wireline personnel associated with the conduct of a well test are fully trained and knowledgeable of required wireline procedures and equipment. This catalog does not and cannot pretend to cover every pressure transient test scenario possible. However, what it can do is present many of the common test scenarios that have occurred over the years. Although the complete procedure for a particular test may not be explicitly covered in this catalog, it should at least lead an engineer to ask the questions required to properly design a test. This catalog was developed from years of experience in mainly the Permian Basin area of West Texas. Some of the topics covered here may not be totally applicable in other parts of the world. However, test methods described in this catalog should be applicable to other similar producing areas.

INTRODUCTION ARC VISION AND MISSION


ARC VISION ARC Pressure Data Inc. is a service company that provides the highest level of technology in slickline operations and data acquisition, reporting, and analysis to the petroleum industry. We seek to expand these services throughout the U.S. domestic market and grow internationally through stratigic alliances with other service providers. ARC MISSION • To understand and exceed our customer’s needs for high quality, best value

services and products • To provide innovative solutions through implementation of “cutting-edge” service

methods and development of proprietary products • To conduct our tasks with the utmost safety • To develop the knowledge and skills of all our people while fostering teamwork and

pride in their work • To achieve profitable growth and a fair return on capital for our shareholders • And in everything we do, maintain the highest level of integrity

INTRODUCTION COMPANY PROFILE


ORIGIN ARC Pressure Data, Inc. had its beginnings with the Tom Hansen Company, Inc. which started its operations in 1959 as a bottomhole pressure data company. In 1965, tubing testing was added to the product line, followed ten years later with production logging and perforating. In 1981, the slickline division was spun off to create what is today ARC Pressure Data, Inc. For over a decade, ARC has been the slickline data acquisition service company leader in the Permian Basin area. TECHNOLOGY LEADER ARC made a commitment to fund the development of an electronic memory gauge with a quartz transducer in 1985. ARC Pressure Data was one of the first service companies to introduce a quartz memory pressure gauge in the Permian Basin.

As the slickline company continued to grow, an emerging technology, memory production logging, was added to its pressure transient testing, general wireline, and engineering services. In 1994, an aggressive research and development effort was spearheaded by ARC, which has resulted in a reliable suite of memory-based production logging tools. The tools are designed, built, and serviced by ARC Pressure Data, Inc. Development continues with ongoing proprietary projects and a slate of additional tools to bring to market. “SERVICE BY DESIGN” ARC Pressure Data, Inc. offers service by design. We design the tests, service, tools, training, and manpower to meet the needs of our clients. Through flexible testing and logging procedure design, as well as multiple data acquisition methods, ARC can lower data acquisition costs, while offering customers a full array of wireline services.

INTRODUCTION SURFACE EQUIPMENT CAPABILITIES


PRESSURE CONTROL • 5000# working pressure lubricator and blowout preventer. • 10000# working pressure lubricator and blowout preventer. • 15000# working pressure lubricator and blowout preventer. • 5000# H2S rated lubricator and blowout preventer. WIRELINE UNITS Single drum units mounted on: • Trailers • 1-ton “boom” trucks • 2-ton “boom” trucks • Large capsule trucks All units except trailer units capable of handling 25000’ wire spools. MAST UNITS • 45’ mast units WIRELINE • 0.092” Carbon Steel Wire • 0.092” MP35N Wire available, rated best by NACE for H2S and CO2 environments

INTRODUCTION SAFETY, TRAINING, AND INSURANCE


SAFETY AND TRAINING ARC Pressure Data, Inc. believes that the safety of employees is of utmost importance, along with quality and cost-control. Maintenance of safe operating procedures at all times is of both monetary and human value, with the human value being far greater to the employer, the employee, and the community. ARC complies with appropriate safety and security laws and regulations such as those established by:

• The Occupational Safety and Health Act (OSHA) • The Environmental Protection Agency (EPA) • All other applicable federal, state, and local safety and health regulations

In pursuit of a safe workplace, ARC has developed a safety manual to help provide guidance and direction for many safety issues. The material in this manual discusses the following topics: • Behavior-Based Safety • First Aid • Personal Protective Equipment • Hydrogen Sulfide • Accident Reporting & Investigation • Emergency Action • Housekeeping • Fire Prevention • Electrical Safety • Hazard Communication • Respiratory Protection • Hearing Conservation • Temperature Extreme Management • Hot Oiling

• Opening Flanges, Valves, and Unions • Fall Protection • Compressed Gas • Forklift Operation • Crane & Derrick Operation • Machine/Equipment Safety & Guarding • Welding & Cutting • Automobiles • Lockout/Tagout – Energy Control • Stairway and Ladder Safety • Universal Waste Management • Used Oil Management • Ergonomics

In addition to the company safety manual, ARC actively provides the following training. This list is not necessarily all-inclusive and is revised as needed. • H2S • CPR • FIRST AID

• PETROLEUM EDUCATION COUNCIL (PEC) • BASIC ORIENTATION PLUS (BOP)

INSURANCE ARC provides at least the minimum required amount of insurance required for Liability, Auto Liability, and Workers Compensation. For more information, please feel free to contact ARC.


CHAPTER 2

WELL TEST INSTRUMENTATION

INSTRUMENTATION PRESSURE GAUGE ATTRIBUTES


ARC Pressure Data, Inc. provides a wide range of pressure gauges for well testing. Critical to successful well testing is the selection of an appropriate gauge type. There is no one single “best” gauge that exists. All gauge types have their strengths and weaknesses. Gauge attributes that need to be considered before choosing a gauge type include: • Accuracy • Resolution • Range • Response time • Sampling Rate / Programmability • Durability These attributes will be briefly discussed to better understand the different gauge types. Accuracy Accuracy typically refers to how close a gauge is to the actual pressure being measured. It can be stated as an absolute value such as +/- 1.0 psi or as a relative error such as percentage of the overall range. Gauge accuracy can vary greatly between the different types of gauges. Regular calibrations and calibration checks are required to help insure that gauges are performing within their stated accuracy. Even with a rigorous calibration schedule, a gauge’s calibration can actually change during a test. This is especially true if the gauge is pushed to its operational limits, whether it is with pressure, temperature, or rough treatment. Resolution The resolution of a gauge is the smallest change in pressure that can be sensed

by the gauge. It should not be confused with gauge accuracy. During a well test, it is possible for the pressure response during consecutive samples to vary by

less than gauge resolution. With some gauge systems this can show up as a stair-step response if the data is “zoomed in on” sufficiently. With other gauge systems, it can show up as a band of scattered or noisy data. The net effect is the same.

1241.05

1241.15

1241.25

1241.35

1241.45

Pres

sure

, psi

a61.79 61.80 61.81 61.82 61.83 61.84

Time, hours

Test data with pressure response less thangauge resolution.

Stair-Step Response

1241.05

1241.15

1241.25

1241.35

1241.45

Pres

sure

, psi

a

61.79 61.80 61.81 61.82 61.83 61.84

Time, hours

Test data with pressure response less thangauge resolution.

Data Scatter or “Noisy” Response



Range Pressure gauges are designed to operate within a specific range of temperature and pressure. When a gauge exceeds one or both of these ranges, erroneous data or destruction of the gauge may result. Some gauges can be “overranged” where the recommended maximum pressure is exceeded but where the data can still be reported. Data in this case is not guaranteed to be within specifications of accuracy and resolution. Gauges can also be run outside of the recommended operating range by running at temperatures and pressures below this range. Although this generally does not damage the gauge, data can lose some accuracy. For example, data taken from gauges at atmospheric pressure and low temperatures is generally somewhat off. Keep in mind that these gauges are designed for optimum performance at typical downhole pressure and temperature conditions. Response Time The response time of a gauge is the amount of time required for a gauge to respond to a given change in temperature. Depending on the type of gauge and the degree of change, this time can range from a few seconds to several hours. Quartz transducer gauges, which typically exhibit high resolution and accuracy, tend to also exhibit a slow pressure response time to a given temperature change. Sampling Rate / Programmability Because the pressure response of a pressure transient type test generally

occurs as a function of the logarithm of elapsed test time, high sample rates are generally required during the early portions of a test. Because of memory limitations many gauges are programmable so that data can be collected at a high frequency during the early portion of a test and slowed as the test progresses. As memory density has increased, more data can be sampled and stored in downhole gauges. This has somewhat reduced the need for programmable gauges. With a sufficient amount of memory, a high data sampling frequency can be maintained throughout the entire length of a test. Benefits of this type of approach include increased flexibility in test operations and ease of use for the gauge technician. Durability Expected test conditions should be considered when choosing a gauge. Different gauge types have varying degrees of durability. When severe conditions are encountered such as when measuring downhole pressures during a hydraulic fracturing job, tradeoffs may have to be made between accuracy and durability. Additional protection, such as gauge shock absorbers, can help but are not a “cure-all” for rough treatment. Surprisingly, the modern circuitry of an electronic memory gauge successfully samples and retains data in many cases where mechanical type gauges fail. In many of these cases, after a mechanical gauge receives excessively rough treatment, loose parts can literally be “poured” out after the test.



Tandem/Backup Gauges Tandem gauges are often used as insurance against gauge failure. Similarly rated gauges should be used together to back each other up. However, budget constraints often result in a lower resolution/accuracy gauge being used as a backup gauge. The problem with this scenario is that if a high resolution/accuracy gauge has been deemed necessary for a test, then a lower rated gauge may not be capable of adequately backing up the primary gauge because of resolution and accuracy limitations. In many cases the backup gauge is used to resolve questions about data taken from the primary gauge, not because of total failure of the primary gauge. However, in this case it should be remembered that the limitations of a lower resolution/accuracy gauge may render it incapable of resolving questions about data taken from a higher rated primary gauge. The following example illustrates a case where a mechanical gauge is unable to adequately backup a high precision quartz gauge. In this case it can be seen that the derivative plot generated from data taken from a high precision quartz gauge “kicks up” during late-time. Various interpretations of this behavior could include a single no-flow boundary or a lateral change in reservoir or fluid properties. However, when the data from a mechanical backup gauge is used to verify this response it can be seen that the lack of resolution with the mechanical gauge obscures any boundary response that might otherwise be seen. One can see that the situation

for the well test analyst can easily evolve from identifying possible sources of the behavior of the pressure response to whether the response ever actually occurred. In this case the mechanical backup gauge neither contradicts nor confirms the data taken from the electronic quartz gauge.

Log-Log/Derivative Plot

Mechanical Pressure Gauge Response- boundary not detected

Log-Log/Derivative Plot

Quartz Pressure Gauge Response- boundary detected

INSTRUMENTATION PRESSURE GAUGE TYPES


There are many different types of pressure gauges available for well testing purposes. The following outline and discussion gives an overview of many of the available gauge types. • Bottomhole Pressure Gauges

− Self-Contained Slickline Gauges − Mechanical Gauges − Electronic Memory Gauges

− Strain Gauges − Quartz Gauges

− Electronic Surface Readout Gauges

• Automatic Well Sounder Systems • Surface Pressure Gauges Bottomhole Pressure Gauges Bottomhole pressure gauges can be either self-contained gauges or surface readout type gauges. Self-contained gauges record pressure data internally throughout the length of the test. The gauges must be retrieved before the pressure data is taken from the gauge. Among the self-contained gauges are two basic gauge types – mechanical gauges and electronic memory gauges. Mechanical gauges generally use a pressure transmission mechanism such as a hollow helical tube to transmit pressure changes. These pressure changes are scribed onto a metallic chart by a stylus. A clock drives the chart carrier to give a pressure versus time record on the chart. Electronic pressure memory gauges rely on pressure transducers to translate the strain exerted on a pressure-sensing element to an electrical signal. This signal is then converted to a digital format and stored on electronic memory

chips. There is a wide range of electronic transducer types. Although an oversimplification, they often tend to be classified into two major catagories: the strain gauge type sensor and the quartz transducer type sensor. Strain gauge sensors are generally rugged, accurate, and respond quickly to temperature changes. Quartz transducers, in comparison have higher accuracy and resolution, but tend to respond slower to temperature changes. The following table shows example gauge specifications taken from several commercially available downhole pressure gauges. It gives a quick illustrative comparison between typical mechanical, electronic strain, and electronic quartz type gauges. Individual gauge specifications should be consulted when additional information is required. Type Accuracy,

psi Resolution, psi

Mechanical 10 N/A Strain 1.5 0.02 Quartz 1.0 0.005 * Accuracy’s and resolutions are stated for 5000 psia rated gauges.



Surface Readout Gauges Surface readout electronic gauges basically use the same sensor technology as electronic memory gauges. However, instead of an encoded electrical signal being stored on a memory chip downhole, it is instead transmitted up an electric line to surface instrumentation for display and storage. The advantage of a surface readout system is the ability to monitor the progress of a test in realtime and tailor the length of the test procedures as needed. The disadvantages include higher costs compared to electronic memory gauges, and exposure of the electric line to potentially corrosive wellbore fluids for extended periods of time. A lubricator is also required throughout the entire test length with its inherent problem of maintaining a long-term seal against high surface pressure. Automatic Well Sounder Systems Automatic Well Sounder (AWS) technology works by measuring and recording the casing (gas) pressure and the annular liquid level simultaneously. The total of the casing pressure, weight of the gas column, and weight of the fluid column are used to determine the bottomhole pressure. Although AWS technology is most often used with sucker-rod pumped wells, it can also be used in other instances where the well does not have a packer, allowing measurement of fluid level and surface pressure. There are two major assumptions underlying AWS technology. The first is 1) all fluid above the pump at shut-in is

entirely oil due to gravity segregation. The second is 2) after shut-in, the afterflow of fluid into the wellbore maintains the same proportions of water and oil production as before shut-in. Although this is not universally true, for the majority of rod-pumped wells, these assumptions are close enough to provide adequate bottomhole pressure values for transient analysis.

Care should be taken on wells with thick non-contiguous zones, where individual layers exhibit different flow characteristics and pressures. This is especially true in mature waterfloods. The standard AWS assumptions tend to not hold true in these types of situations. AWS bottomhole pressure calculations are also highly dependent on accurate input parameters. Inaccurate input parameters will result in equally inaccurate bottomhole pressure calculations.

OIL

WATER

INTERFACELEVEL

GAS

AWS Measurement Principle

Pumping Shut-in



The following diagram identifies the major components of an AWS system set up for a well test.

Surface Pressure Gauges Surface pressure gauges are often acceptable for testing gas wells. As with AWS testing, bottomhole pressure calculations are highly dependent on accurate input parameters. High velocity gas streams can lead to inaccurate pressures being calculated if friction is not correctly accounted for. High temperature wells can also lead to inaccuracies if the temperature profile is not correctly and accurately modeled.

Water injection wells can also be tested with surface pressure gauges if the well maintains surface pressure throughout the duration of the test. Accurate determination of bottomhole pressure depends on accurate input data such as the density of the injected water. Friction in the tubing could also lead to inaccurate calculations of bottomhole pressure during periods of injection, if the friction is excessive. If the tubing pressure ever goes on vacuum, where the water level in the tubing drops below the surface, bottomhole pressures cannot be calculated since the fluid level will not be known.

AWS Computer

Gun, Microphone,& Pressure Transducer

Nitrogen BottleBattery

AWS Measurement System


CHAPTER 3

GAUGE SETTING AND DEPLOYMENT METHODS

GAUGE SETTING AND DEPLOYMENT METHODS BACKGROUND AND ASSUMPTIONS


This section discusses a variety of gauge setting and deployment methods available for releasing bottomhole pressure gauges. These methods are well established, lower cost operations designed for use in production scenarios (cased hole, completed wells) and do not incorporate high-end gauge carriers for DST, RFT, and permanent installations. The primary reasoning behind the usage of releasing methods, as opposed to “hanging the gauges on the wire”, is to: 1) Reduce the cost of surface equipment, such as wireline units, tied up for long

periods, 2) Provide a “secure” high pressure seal with master-valve shut-in’s on buildup tests, 3) Provide a less hazardous method to acquire data in highly corrosive (H2S, CO2)

environments by reducing wireline exposure time. The procedures presented for these methods are somewhat simplified. In “real-life” situations they are often much more complicated and may be modified or combined with other methods. Also, the methods discussed in this section do not comprise an all-inclusive list of available methods. These methods tend to be more applicable to vertical wells. Other methods and equipment developed specifically for horizontal and highly deviated wells are not covered here. It is expected that experienced wireline personnel be involved in the design and conduct of all wireline jobs. This catalog does not attempt to fully cover all wireline operations. Specialized tools to aid in running gauges, such as “No-Blow”* tools and “Springloads”*, are often required with many of the methods discussed in this section. However, detailed use of these tools is not discussed here. Procedures associated with running gauges in deviated wells and in wells with conditions such as paraffin buildup are also not discussed. * Springloads prevent a toolstring from dropping when prematurely released while using softset releasing tools. A No-Blow tool is used to prevent a toolstring from being blown up the hole on high-rate wells or on wells where the flow rate is surging. These tools can have various names depending on the tool source and/or geographical area.

GAUGE SETTING AND DEPLOYMENT METHODS NO-GO ON SEATING NIPPLE


General Usage: Used when the well has either a seating nipple or profile nipple. PROCEDURE: 1. Make a dummy run with the No-Go attached to

the bottom of a sinker bar. 2. Release sinker bar on nipple. 3. Run gauge(s) and release on top of the sinker

bar. SPECIAL CONSIDERATIONS: As the tubing ID and the nipple ID approach each other in size, it can become difficult to appropriately size the No-Go. As these sizes near each other, the danger increases of sticking the No-Go in either the tubing or the nipple, depending on if the No-Go is slightly undersized or slightly oversized.

CASING

TUBING

GAUGE/BAR

NO-GO

COLLAR

SEATINGNIPPLE

GAUGE SETTING AND DEPLOYMENT METHODS WHISKERED BOMB HANGER FOR COLLARS


General Usage: Used when the well does not have either a seating or profile nipple, or the nipple is sized such that a No-Go will not work. Requires the well to have upset tubing with collars. Rounded Dog Grabs* are available for IPC** tubing. PROCEDURE: 1. Make a dummy run with Bomb Hanger

attached to the bottom of a sinker bar. 2. Run sinker bar about one collar below the

target setting depth. 3. Pull the sinker bar up the hole past a collar to

trip the Bomb Hanger Dog Grabs. 4. Lower sinker bar until the Bomb Hanger sets

on the next collar down. 5. Release sinker bar on collar. 6. Run gauge(s) and release on top of sinker bar. SPECIAL CONSIDERATIONS: Dog grabs or the pin holding them can break, allowing the tools to drop. Rounded Dog Grabs may still damage IPC coating in tubing. * In the context of downhole wireline tools Dog Grabs are usually a mechanical device with small sharp teeth for gripping the inside of pipe such as tubing or casing. Rounded Dog Grabs are available that help minimize damage to the plastic coating inside IPC tubing. ** Internally Plastic Coated

CASING

TUBING

GAUGE/BAR

WHISKEREDBOMB HANGERFOR COLLARS

COLLAR

GAUGE SETTING AND DEPLOYMENT METHODS WHISKERED BOMB HANGER FOR TUBING


General Usage: Used when the well does not have either a seating or profile nipple, or the nipple is sized such that a No-Go will not work, and the well does not have upset type tubing with collars. PROCEDURE: 1. Make a dummy run with Bomb Hanger

attached to the bottom of a sinker bar. 2. Run sinker bar to where the bomb hanger

drops just below the bottom of the tubing. This may require several approaches. Care should be taken so that the entire toolstring is not run below the tubing. Only the bomb hanger should drop below the bottom of the tubing. Allowing the entire toolstring to go beyond the bottom of the tubing increases the chance of losing the tools.

3. Pull the sinker bar up into the tubing to trip the

Bomb Hanger Dog Grabs and up to the target setting depth.

4. Lower the sinker bar to release it at the target

depth. If the Bomb Hanger does not “grab” the tubing and in turn support the weight of the sinker bar, repeat steps 2 and 3 while running the toolstring a couple of feet lower below the bottom of the tubing to reattempt to trip the Dog Grabs.

5. Run the gauge(s) and release on the top of the

sinker bar. SPECIAL CONSIDERATIONS: Dog grabs or the pin holding them can break, allowing the tools to drop. Dog Grabs may not grip the tubing, allowing the tools to fall. If the entire toolstring is run below the bottom of the tubing, it is possible to accidentally release the tools below the tubing and drop them, especially if there is some difficulty getting the tools back up into the tubing.

CASING

FISHINGNECK

TUBING

WHISKEREDBOMB HANGERFOR TUBING

GAUGE/BAR

INTEGRALTUBING JOINT

GAUGE SETTING AND DEPLOYMENT METHODS WHISKERED BOMB HANGER FOR CASING


General Usage: Used when it is desired to release the gauges inside casing. This is often the case when the gauges need to be released close to the perforations and the tubing is set too high. It can also be the case when gauges released in the tubing cause too much restriction to flow. PROCEDURE: 1. Make an initial dummy run to the anticipated

run depth in the casing where gauges are to be released to check well conditions.

2. Run gauges to a depth about one casing joint

below the target setting depth. 3. Pull gauges upward by a casing collar to trip

the Bomb Hanger Dog Grabs. Continue on up to the target setting depth.

4. Lower gauges to release at the target depth. If

the Bomb Hanger does not “grab” the casing and in turn support the weight of the gauges, repeat steps 2 and 3 to trip the Dog Grabs.

SPECIAL CONSIDERATIONS: May be difficult to retrieve the tools if the well is deviated or if debris is present. The use of a casing hanger is not recommended when a well has been recently fractured and/or special proppants (such as glass beads or bauxite) were utilized. The proppant can prevent the successful deployment of the dog grabs. It is also possible to get the retrieving tools, especially the casing centralizer, “hung up” in the casing hanger Dog Grabs if they are run down beside or below the Bomb Hanger. The Dog Grabs or the pin holding them can break, allowing the tools to fall. Dog Grabs may not grip the casing, allowing the tools to fall. There are also minimum tubing and nipple ID restrictions that may prevent the bomb hanger from coming back into the tubing after retrieval.

PACKER

TUBING

TUBINGCOLLAR

FISHINGNECK

WHISKEREDBOMB HANGERFOR CASING

CASING

GAUGE

GAUGE SETTING AND DEPLOYMENT METHODS GAUGE CARRIER BELOW BRIDGE PLUG


General Usage: Use for detection of vertical communication/permeability during pressure buildup tests, frac jobs, etc. Also used for separation of multiple zones during pressure transient testing. PROCEDURE: 1. Place gauge(s) inside gauge carrier with

appropriate shock absorbers. 2. Attach gauge carrier to bridge plug. 3. Run the gauge carrier/bridge plug assembly

down the well using an electric line or tubing. 4. Set and release the bridge plug.

NOTE: Anytime tubing is used to convey wireline instruments in a well, extreme care should be taken running the tubing in the well. It is advisable for the wireline technician to monitor the entire operation until the bridge plug has been successfully set.

5. Retrieve the gauge carrier/bridge plug

assembly after test and/or well treatment. SPECIAL CONSIDERATIONS: Gauges can be damaged when running, setting, or retrieving the bridge plug, whether run in on electric line or on tubing. The shock of the explosive charge used when setting a bridge plug with an electric line can damage gauges. Vibration during a frac job or failure of the bridge plug can also damage the gauges.

TUBING

CASING

BRIDGEPLUG

SHOCKABSORBER

GAUGECARRIER

GAUGE

SPACERS

SHOCKABSORBER

BULL PLUG

GAUGE SETTING AND DEPLOYMENT METHODS MUD ANCHOR BELOW ROD-PUMP


General Usage: Conducting tests on pumping wells. This is an alternative method to AWS (Automatic Well Sounder) technology for testing a rod-pumped well. PROCEDURE: 1. Pull the rods and pump from the well. 2. Make a dummy run with a gauge ring or No-Go

to tag the seating nipple. Record the depth that the seating nipple was tagged.

3. Run the gauge(s) and release in the mud

anchor. The mud anchor must have a bull plug attached to the bottom for the gauges to set on. The mud anchor must also be of sufficient length to allow the gauges to set safely below the bottom of the rod pump.

4. Run the rods and pump back into the well. SPECIAL CONSIDERATIONS: Vibration while the well is pumping can damage the gauges. If there is not sufficient space underneath the pump, the pump will set on top of the gauges when it is run in and possibly damage the gauges and/or the pump. A “No-Blow” tool is often attached to the top of the tool string to help prevent it from being drawn up into the pump during production.

TUBING

CASING

SUCKERROD STRING

SUCKERROD PUMP

SEATINGNIPPLE

MUDANCHOR

GAUGE

BULL PLUG

FISHINGNECK

GAUGE SETTING AND DEPLOYMENT METHODS “PIGGYBACK” GAUGE CARRIER


General Usage: Used to monitor pressures during frac jobs and similar types of well treatments. Tubing ID is not restricted by gauges sitting inside the tubing. PROCEDURE: 1. Place gauge(s) inside the Piggyback Gauge

Carrier with appropriate shock absorbers. 2. Run the gauge carrier down the well on the

bottom of the tubing.

NOTE: Anytime tubing is used to convey wireline instruments in a well, extreme care should be taken running the tubing in the well. It is advisable for the wireline technician to monitor the entire operation until the tubing has been successfully set.

3. Pull the tubing with the gauge carrier after the

test and/or well treatment is completed. SPECIAL CONSIDERATIONS: Gauges can be damaged when running the gauge carrier in on tubing and when pulling it back out. Vibration during a frac job or other treatment can also damage gauges.

TUBING

CASING

“PIGGYBACK”GAUGE CARRIER

SHOCKABSORBER

SPACERS

GAUGE

SHOCKABSORBER

GAUGE SETTING AND DEPLOYMENT METHODS PUP JOINT GAUGE CARRIER


General Usage: Used to monitor pressures during frac jobs and similar types of well treatments. With this arrangement there are no gauges sitting inside the tubing to restrict the tubing ID. The gauge carrier should always be set on bottom or below point of entry for the treatment. PROCEDURE: 1. Place gauge(s) inside the Piggyback Gauge

Carrier with appropriate shock absorbers. 2. Run the gauge carrier down the well with a

wireline. 3. Retrieve the gauge carrier after the test and/or

well treatment. SPECIAL CONSIDERATIONS: Vibration during a frac job or treatment can damage gauges. This configuration typically involves a “wash-over” after hydraulic fracturing operations because of sand accumulation in the bottom of the wellbore. The pup joint may have to be fished using tubing if attempts using a wireline are not successful.

FISHINGNECK

BULL PLUG

SHOCKABSORBER

GAUGECARRIER

GAUGE

SPACERS

SHOCKABSORBER

BULL PLUG

GAUGE SETTING AND DEPLOYMENT METHODS HANG ON WIRE


General Usage: Commonly used when the wellbore configuration is such that the well cannot be safely or accurately tested by releasing gauges downhole. Surface readout gauges are always suspended on an electric line wire. PROCEDURE: 1. Attach gauge to wire. 2. Run gauge to desired setting depth. SPECIAL CONSIDERATIONS: This method of setting downhole pressure gauges for an extended length test is typically not recommended due to several concerns. One of these is the exposure of the wire to a corrosive environment over an extended period of time. Another concern is that of the surface equipment. If the gauges are suspended on a wireline, it is automatically assumed that surface wireline equipment is present and is at least partially exposed. Problems such as lubricator leaks, vandalism, and damage to equipment due to the elements suddenly become an issue.

CASING

PACKER

TUBING

WIRELINE(SLICKLINE ORELECTRIC LINE)

GAUGE


CHAPTER 4

PRESSURE TRANSIENT TEST TYPES

PRESSURE TRANSIENT TEST TYPES OVERVIEW OF TEST TYPES


ARC Pressure Data, Inc. provides a full range of pressure transient testing services. To aid in proper test design many of the pressure transient test types will be discussed along with common test procedures. Because there are often special cases within each test type, procedures for some of these cases will also be discussed. Pressure transient tests can be organized into several major categories and sub-categories: • SINGLE-RATE TESTS

− Producing Wells − Buildup Test − Drawdown Test

− Injection Wells − Falloff Test − Injectivity Test

• MULTI-RATE TESTS − Flow-After-Flow Test − Isochronal Test − Modified Isochronal Test − Step-Rate Test

• MULTI-WELL Tests − Interference Test − Pulse Test

• SPECIALIZED Tests − Vertical Interference − Measurement While Fracturing

Single-Rate pressure transient tests are the simplest type of transient test to conduct. A single-rate test is just what the name implies – a well test involving a single rate change on either a production or injection well. For producing wells there are two types of single-rate tests: the buildup test and drawdown test. Injection wells also have two types of single-rate tests: the falloff test and injectivity test. Multi-Rate pressure transient tests involve two or more producing or injection rates with a well. These tests require more interaction to stabilize rates and as a result, are more labor-intensive. Multi-Well tests involve two or more wells. They tend to require a good deal of advanced planning and coordination, but field operations are not necessarily any more difficult than those associated with other tests. In “Establishing Design Criteria For Pressure Buildup Tests” by Frailey, Pierce, and Crawford, many aspects of test design are discussed which are frequently overlooked. The information discussed in their paper is very complementary to the material presented in this test guide. The abstract for this paper has been included in the appendix. This paper is recommended for those interested in further pursuing the subject of proper test design.

PRESSURE TRANSIENT TEST TYPES SINGLE-RATE TESTS – PRODUCING WELLS

PRESSURE BUILDUP TEST


The pressure buildup test is one of the more commonly used pressure transient tests, if not the most common. Its main requirement is that a producing well be shut in and the resulting increase in pressure be measured as a function of shut-in time. Buildup tests can be conducted on both flowing and artificially lifted wells. The specific procedure for testing any individual well is highly dependent on the type of lift mechanism, the producing history, and the producing characteristics of the well. It should be kept in mind that the well must be produced for an adequate length of time before shut-in. A good rule of thumb to use is to produce the well at least as long as the shut-in time. The following diagrams show a typical pressure buildup response:

Generic Test Procedure: 1. Produce well (well can be either

flowing or on artificial lift) 2. Install measurement equipment 3. Start recording test data – time,

pressure, flow rates 4. Shut in well 5. Continue recording data throughout

buildup period

6. Conclude test – retrieve data

POINTS TO CONSIDER • Accurate knowledge of the time

and pressure at shut-in is critical. Gauges and/or other instruments should be in place and adequately stabilized so that the flowing pressure and time can be accurately recorded when the well is shut in. Shut-in pressure is recorded as a function of shut-in time.

• Knowledge of the producing history is critical. Variations in producing rates need to be known. The closer a rate change occurs to the shut-in time, the greater its impact will be on the buildup response.

• The temperature response reported from electronic gauges can aid in the interpretation.

Producing methods (not all-inclusive): • Flowing • Sucker-Rod Pump • Swabbing • Gas Lift • Plunger Lift • Electrical Submersible Pump • Jet Pump

Shut-In Pressure

ProducingPressure

p

t (<t=0)

Producing Rate

Shut-In, Rate = 0

t ( < t=0)

q

PRESSURE TRANSIENT TEST TYPES SINGLE-RATE TESTS – PRODUCING WELLS – BUILDUP TESTS

FLOWING WELLS


Flowing wells, whether gas or oil, are generally the most straightforward wells to test. The main considerations tend to be the determination of safe, cost- effective test procedures and gauge setting methods. A flowing well should have a crown valve installed before gauges are run into a well to conduct a buildup test. This allows the test to be conducted without disturbing the well flow. If a crown valve is not present and the well has to be shut in to rig up for the test, the flow rate should be allowed to restabilize for a period at least five times longer than this shut in period. For example, if a well is shut in for 5 minutes to rig up, it should be allowed to restabilize for at least 25 minutes before running the gauges into the well. SUGGESTED TEST PROCEDURES: • Downhole Pressure Measurement

− Gauge Setting Options: No-Go, Whiskered Bomb Hanger for Collars, Whiskered Bomb Hanger for Tubing, Whiskered Bomb Hanger for Casing, Hang on wire*

1. Make dummy run with sinker bar to

desired run depth with well flowing. 2. Run gauge(s) into well under flowing

conditions, make flowing gradient stops while running gauges in the well.

3. Release gauges at the desired depth using the proper setting procedure or leave hanging on wire.

4. Record sufficient flowing data with gauges on bottom, usually one hour. This not only helps characterize the nature of the well during flowing conditions, it also helps the gauges to stabilize at reservoir conditions.

5. Shut in well. The gauges must be in place and adequately stabilized so that the flowing pressure and time can both be accurately recorded at shut-in.

6. Keep well shut in for the duration of the buildup period.

7. Retrieve gauges. Make static gradient stops while retrieving gauges from well.

*Please refer to the previous section, “Gauge Setting and Deployment Methods” for more detailed information on each setting option.

Example Test Configuration - Flowing Well

Seating Nipple

Gauge(s)

Tubing

Gauge(s) set withNo-Go on SeatingNipple

No-Go


FLOWING WELLS


• Surface Pressure Measurement (for dry gas wells)

1. Program and attach surface

pressure gauge. 2. Record sufficient flowing data to

characterize well flowing conditions. 3. Shut in well. The gauge must be in

place and adequately stabilized so that the flowing pressure and time can both be accurately recorded at shut-in.

4. Keep well shut in for the duration of the buildup period. Since the measurement equipment is on surface it should be checked regularly to make sure the test is progressing as anticipated and that the equipment is performing properly.

5. Stop test and download pressure data.


SUCKER ROD PUMPED WELLS


The majority of producing oil wells are sucker rod pumped. There are two major options for testing sucker rod pumped wells – AWS (Automatic Well Sounder) technology, and the use of bottomhole pressure gauges. AWS technology is a good option for conducting tests on many pumping wells. It allows the well to be produced uninterrupted up to the time of shut-in. Costs associated with pulling the pump are also eliminated. Wells that lie outside the constraints associated with AWS technology require the use of bottomhole pressure gauges for accurate measurements. These constraints were discussed in the earlier chapter on instrumentation. Sucker rod pumped wells can often be costly to test when using bottomhole pressure gauges. To conduct a test using bottomhole pressure gauges, the rod string and pump must first be pulled, requiring the use of a pulling unit. Gauges then need to be set below the seating nipple, either in a mud anchor or by using a casing hanger. Production not only ceases when the pump is unseated and the rod string is pulled, an injection transient may also take place as wellbore fluids empty from the tubing and “U-tube” into the casing-tubing annulus with some fluid flowing back into the formation. Because of this, the well must be put back on production with the gauges in place before a true buildup test can be conducted. The well should ideally be produced long enough to overcome the pressure transients caused by ceasing

production and dumping fluid back onto the formation. Producing methods at this point can also include swabbing the well. A frequent occurrence is for a sucker rod string to be pulled from a well, the well worked over, and then be swabbed before being tested. It is important to realize that in this scenario, the swabbing of the well is the artificial lift mechanism. It should be treated accordingly if good test results are desired. Issues with swabbing the well are covered in the next section. Pressure transient tests should be avoided on pumping wells that have been hot-oiled within a time period equal to the estimated test length.

Example Test Configuration - Sucker Rod Pumped Well

Pump

Seating Nipple

Gauge(s)

Mud Anchor

Bull Plug

Sucker Rods andPump run in abovegauge(s)




SUGGESTED TEST PROCEDURES: • AWS Measurement System 1. Program and install the AWS unit. 2. Monitor well until surface pressure

and fluid level is firmly established. (Fluid level ideally should be checked by a second source, such as a single-shot fluid level device. Surface pressures should also be verified with either a deadweight gauge or a high quality test gauge.)

3. Shut in well. The AWS unit must be in place so that the flowing pressure and fluid level can both be accurately recorded at the time of shut-in.

If the unit is on a time clock the well should be shut in and the pump shut down during an actual pump cycle. Care should also be taken to shut the pumping unit down on the downstroke to help insure a closed standing valve. The flow line and casing must both be shut in. Any peripheral equipment, such as chemical injection pumps or vapor recovery equipment, that could affect the test should also be shut off.

4. Keep well shut in for the duration of the buildup period. Since the measurement equipment is on surface it should be checked regularly to make sure the test is progressing as anticipated and that the equipment is performing properly. Data can be downloaded and evaluated as the test progresses.


• Downhole Pressure Measurement

− Gauge Setting Options: Set in Mud Anchor, Whiskered Bomb Hanger for Casing*

1. Pull sucker rods and pump. Also pull

tubing if the string needs to have a mud anchor either added or lengthened to give the gauges ample room to avoid contacting the pump.

2. Run gauge(s) into well and release either in mud anchor or casing.

3. Run the sucker rod string back in and set the pump.

4. Produce the well for the desired amount of time.

5. Shut in the well and record the time. (If operating company personnel shut in the well, the shut in time should be recorded and if possible, synchronized with the wireline operator that started the test.)

The well should be shut in and the pump shut down during an actual pump cycle if the unit is on a time clock. Care should also be taken to shut the pumping unit down on the downstroke to help insure a closed standing valve. The flow line and casing must both be shut in. Any peripheral equipment, such as chemical injection pumps or vapor recovery equipment, that could affect the test should also be shut off.




6. Blow the well down at the conclusion of the test time. This time should be recorded.

7. Unseat the pump and pull the sucker rod string.

8. Retrieve the gauge(s). A pressure gradient survey may be run. However, on pumping wells where the well has been blown down and the pump unseated, it does not yield very meaningful information.

*Please refer to the previous section, “Gauge Setting and Deployment Methods” for more detailed information for each setting option.


SWABBING


Buildup tests are frequently conducted on wells that have been swabbed. These wells are typically: • Newly completed wells • Existing wells undergoing a

recompletion or • Rod pumped wells being reworked The data from these tests is often poor quality largely due to improper test design. If it is desired to derive values for reservoir properties such as permeability, skin damage, and reservoir pressure, then the rules for the conduct of a proper buildup test still apply. That is, the well needs to be produced for an adequate length of time then shut in for the pressure buildup test. In this case the swabbing of the well is the artificial lift mechanism. On a well being swabbed, an adequate producing period usually means that the well should be swabbed for an extended length of time without interruption. As with any buildup test, the length of the drawdown period is crucial for a successful buildup test. If the well is only swabbed once or twice over a short period of time, the resulting data will probably not be analyzable due to wellbore storage-dominated data. In fact, there is often an injection transient still taking place at this point with the fluid level continuing to drop, if the well was previously on pump. Bottomhole pressure gauges should be set in the well early enough to record as much producing data as possible. The gauges must be in place when the well is shut in. Failure to have the gauges in place at shut-in essentially means that

the resulting data will not be analyzable since the producing pressure at shut-in will not be known. SUGGESTED TEST PROCEDURES: • Downhole Pressure Measurement

− Gauge Setting Options: Set in Mud Anchor, Whiskered Bomb Hanger for Casing, No-Go, Whiskered Bomb Hanger for Collars, Whiskered Bomb Hanger for Tubing *

1. Run gauge(s) into well and release using appropriate method. If the well does not have a seating nipple below which the gauges can be set, care should be taken to not damage the gauges while the well is being swabbed. To help protect the gauges from the swab assembly a sinker bar with a whiskered bomb hanger can be set in a collar above the gauges.

Gauge(s) set on seating nipple.Swabbing above top of gauge(s)

Seating Nipple

Gauge(s)

Swab Cup(s)

Weight Bar

Swab Line

Example Test Configuration - Swabbed Well


SWABBING


2. Swab the well long enough to get a sufficient amount of “flowing” data recorded with the gauges downhole. In addition to recording the flowing data, it is essential that the formation be drawdown (by swabbing) for a sufficient length of time to adequately investigate the reservoir. If necessary, leave the well open overnight and continue swabbing operations throughout subsequent days.

3. Shut in well. The gauges must be in place and adequately stabilized so that the flowing pressure and time can both be accurately recorded at shut-in. Although the gauges do not have to be in place during the entire drawdown period, they should always be in place early enough to record the producing conditions at shut in.





GAS LIFT


When testing gas lift systems, the gas injection must be turned off sufficiently early so that a gas lift valve does not open up during the actual buildup test. Additional precautions must also be taken to insure that gauges are not blown up the well because of a valve opening up. Care should be taken to insure that the gauges are released far enough below the lowest gas lift valve so that the gauges are not “blown up the hole” and damaged or lost.

SUGGESTED TEST PROCEDURES: • Downhole Pressure Measurement


1. Run gauge(s) into well and release using an appropriate method. While conducting the flowing gradient stops should be spaced such that it can be determined which valve is the operating valve. A “No-Blow” tool is required to prevent the gauges from being blown up the hole. Although this step is not necessarily required for the buildup test itself, it is an excellent opportunity to obtain valuable data concerning the operations of the gas lift installation.

2. Shut in gas lift injection sufficiently early so that gas lift valves do not open up after the buildup is started.

3. Continue to flow well to record flowing conditions with gauges. If the well tries to die, turn the injection back on and produce the well again for an adequate amount of time.





Gas In

Oil and Gas Out

Reservoir Fluids

Gas Lift Valves

Gauge(s)

Packer

Master Valve

Example Test Configuration - Gas Lift System


PLUNGER LIFT


When testing plunger lift systems, the plunger and bumper spring assembly must both be retrieved from the well before gauges can be run into the well. If the well dies off too much after the plunger is pulled and before the buildup is started, the plunger and bumper spring assembly may need to be run back into the well to allow the well to produce a sufficient length of time before shutting it in. In either case the gauges need to be set on bottom for a sufficient amount of time to record the producing pressures downhole. Flow rates from plunger lift systems tend to be very sporadic as the plunger cycles up and down the well. It is advisable to learn about the nature of the flow rates and their fluctuations before the test is conducted. It is also essential to get an accurate record of the flow rate history before the data is analyzed. Ideally, the plunger should be retrieved during a production cycle at surface and the well shut in at the end of the cycle. If the well is on an intermitter, it should always be shut in during a production cycle. SUGGESTED TEST PROCEDURES: • Downhole Pressure Measurement

− Gauge Setting Options: No-Go, Whiskered Bomb Hanger for Collars, Whiskered Bomb Hanger for Tubing, Hang on wire*

1. Retrieve plunger and bumper spring

assembly.

2. Run gauge(s) into well and release using an appropriate method.

3. Continue to flow well to record flowing conditions with gauges.


5. Keep well shut in for the duration of the buildup period. Do not open the well to flow until the gauges have been pulled and a static gradient run completed.


Example Test Configuration - Plunger Lift System

Oil and Gas Production

Reservoir Fluids

Plunger

Gauge(s) onCasing Hanger

Bumper Spring

Tubing Stop

Master Valve

Catcherw/ Arrival Sensor


PLUNGER LIFT


An alternative procedure is suggested for cases where the well dies off quickly after the plunger is pulled. By using a Whiskered Bomb Hanger for Casing to set the gauges in the casing, the plunger and bumper spring assembly can be run back into the well to allow production to continue for an adequate amount of time. If the well dies after the plunger is pulled, it may require swabbing to restore production. • Downhole Pressure Measurement

− Gauge Setting Options: Whiskered Bomb Hanger for Casing*

1. Retrieve plunger and bumper spring

assembly. 2. If the well rapidly dies off after the

plunger assembly is pulled, the gauges can be set in the casing.

3. Run gauge(s) into well and release in casing.

4. Rerun bumper spring assembly and plunger.

5. Continue to produce well to record flowing conditions with gauges.



8. Set up to pull plunger and bumper spring assembly. Do not open the well to flow until the gauges have been pulled and a static gradient run completed.


* Please refer to the previous section, “Gauge Setting and Deployment Methods” for more detailed information for each setting option.


ELECTRICAL SUBMERSIBLE PUMP


AWS (Automatic Well Sounder) technology can be a good, cost effective option for wells with electrical submersible (ESP) pump installations if there is not a packer in the well. The normal constraints and assumptions hold when AWS is used on ESP- pumped wells as when it is used on sucker rod pumped wells. AWS can also be used as a backup for downhole gauge data, and to provide data for afterflow calculations. ESP-pumped wells tend to be expensive to test when bottomhole pressure gauges have to be run to record the data. Because there is usually a check valve above the pump, bottomhole pressure gauges generally cannot be released in the tubing above the pump to record a pressure buildup test since they would simply be recording the hydrostatic pressure exerted from the fluid column above them. This means that when bottomhole gauges are to be used, the tubing string and the pump must first be pulled. The gauges can then be either run in a mud anchor or in the casing below the pump. Care should be taken to notice whether or not the ESP system has a check valve in the tubing string above the pump. If not, a significant amount of fluid can fall back down after the pump is turned off and inject back into the formation. Additionally, if the well does not have a packer, there can also be “U-tubing” effects as the fluid levels in the tubing and casing attempt to equalize. These effects can render buildup test data unusable.

In some cases, submersible pump installations include a “Y” tool that allows wireline operations, such as running downhole pressure gauges, to be performed without pulling the pump. Other ESP installations include a permanent downhole pressure gauge with surface readout. These gauges can provide a very cost-effective means of providing useful test data. Care must be taken because not all of these gauges provide adequate resolution and accuracy for pressure transient type tests.

Fluid Production

Reservoir Fluids

Check Valve


Pump

Motor

Master Valve

Pump Intake

Power Cable

Example Test Configuration - Electrical Submersible Pump






1. Pull tubing string and pump. 2. Run gauge(s) into well and release

using casing hanger. 3. Run tubing and pump back into well. 4. Turn on pump and produce well for

an adequate amount of time. Record producing pressures.

5. Turn off pump and shut in well. Make sure that the shut-in time is recorded.


7. Pull tubing string and pump to retrieve gauges.

• AWS Measurement System 1. Program and install the AWS unit. 2. Monitor well until surface pressure

and fluid level is firmly established. (Fluid level ideally should be checked by a second source, such as a single-shot fluid level device. Surface pressures should also be verified with either a deadweight gauge or a high quality test gauge.)

3. Shut in well. The AWS unit must be in place so that the flowing pressure and fluid level can both be accurately recorded at the time of shut in.

The flow line and casing must both be shut in. Any peripheral equipment, such as chemical injection pumps or vapor recovery equipment, that could affect the test should also be shut off.

4. Keep well shut in for the duration of the buildup period. Since the measurement equipment is on surface it should be checked regularly to make sure the test is progressing as anticipated and that the equipment is performing properly. Data can be downloaded and evaluated as the test progresses.



− Gauge Setting Options: Mud Anchor below pump*

1. Pull tubing string and pump. 2. Insert gauge(s) into mud anchor.

Attach mud anchor to pump. 3. Run tubing and pump back into well. 4. Turn on pump and produce well for

an adequate amount of time. Record producing pressures.

5. Turn off pump and shut in well. Make sure that the shut-in time is recorded.






• Permanent Downhole Gauge with Surface Readout − ESP systems with permanent

downhole, surface readout pressure gauge installations. These systems offer a very cost effective method for conducting a well test. However, some of these gauges have inadequate resolution and accuracy for obtaining usable pressure transient test data.

1. Produce well for an adequate

amount of time. Record flowing pressures and times.

2. Turn off pump and shut in well. Record shut in pressures and times. Care should be taken to record the flowing pressure and time at shut-in and to record early time data at a high enough sampling frequency to accurately define the buildup response.

3. Keep well shut in for the duration of the buildup period. Pressures should be monitored at surface and evaluated to determine when an adequate amount of test time has been reached.

4. End test. Make sure all data is downloaded and saved.



JET PUMP


To test a well with a jet pump installation the jet pump first needs to be pumped to the surface and removed. The gauges need to be placed under the pump to record the reservoir pressure response. On some pumps, the gauges can be attached directly to the bottom of the pump and pumped back in. On other installations the gauges must be set below the pump out in the casing. Care should be taken when measuring a well’s producing rates. The jet pump system requires a power fluid to be pumped into the well to lift the wellbore fluids up to the surface. The producing rate straight out of the well is the total volume of the produced wellbore fluids and the power fluid. The power fluid volume has to be taken out of the total volume when modeling the true producing rate for analysis of the test data.


− Gauge Setting Options: Whiskered Bomb Hanger for Casing, Attach gauge to pump*

1. Pump the jet pump to the surface. 2. Either attach the gauge(s) to the

bottom of the pump and pump back into the well or run gauge(s) into well and release using a casing hanger.

3. Produce the well an adequate amount of time and record producing pressures.



6. Pump the jet pump to the surface and either remove the gauge(s) from the pump or retrieve the gauges with wireline from downhole.


Fluid Production Out

Power Fluid In

Reservoir Fluids

Pump


Packer

Master Valve

Power Fluid In

Combined Fluid Return

Example Test Configuration - Jet Pump System


SUMMARY OF PRODUCTION AND TEST METHODS


The following table shows a brief overview of the producing methods just discussed with many of the more commonly used test approaches that are available for obtaining pressure buildup data from wells employing these methods. This table is not all- inclusive for either the types of producing methods or test approaches. Additionally, in many cases a combination of these approaches may be required for a successful test.

PRODUCTION METHODS

DEP

LOYM

ENT

OR

M

EASU

REM

ENT

MET

HO

D

FLO

WIN

G

SUC

KER

RO

D P

UM

P

SWAB

GAS

LIF

T

PLU

NG

ER L

IFT

ELEC

TRIC

AL

SUBM

ERSI

BLE

PUM

P

JET

PUM

P

NO-GO ON SEATING NIPPLE * * * *COLLAR-SET * * * *TUBING-HANGER * * * *HANG ON WIRE * * *CASING HANGER * * * * * * *AWS * *2

SURFACE PRESSURE GAUGE *1

MUD ANCHOR BELOW PUMP * *ATTACH TO PUMP *3 *

1 - Dry gas wells with no fluid.2 - Can be used if the well has no packer.3 - Some installations have a permanent downhole gauge.

PRESSURE TRANSIENT TEST TYPES SINGLE-RATE TESTS – PRODUCING WELLS

PRESSURE DRAWDOWN TESTS


Drawdown tests are typically more difficult to conduct compared to buildup tests due to the difficulties associated with maintaining a constant flow rate. The main requirement is that a shut in producing well be opened for production and the resulting decrease in pressure be measured as a function of producing time. The following diagrams show a typical pressure drawdown response:

Generic Test Procedure: 1. Well is shut in until stabilization (may

be a new well) 2. Install measurement equipment 3. Start recording test data – time,

pressure, flow rates (initially zero flow)

4. Start flowing well 5. Continue recording data throughout

the drawdown period 6. Conclude test – retrieve data


and pressure when the well is open to production is critical. Gauges and/or other instruments should be in place and adequately stabilized so that the shut-in pressure and time can both be accurately recorded when the well is open to production. The producing pressure is recorded as a function of the producing time.

• Knowledge of the producing history is critical if the well has not been shut in long enough to reach a static reservoir pressure.

• The drawdown test requires a constant flow rate, which could require constant monitoring of the well.


Producing methods (not all-inclusive): • Flowing • Sucker-Rod Pump • Electrical Submersible Pump

Producing Rate

Shut-In,Rate = 0

t (<t=0)

q

Shut-InPressure

Producing Pressure

p

t (<t=0)

PRESSURE TRANSIENT TEST TYPES SINGLE-RATE TESTS – PRODUCING WELLS – DRAWDOWN TESTS

FLOWING WELLS


Flowing wells, whether gas or oil, are generally the most straightforward wells to test. The main considerations tend to be the determination of safe, cost effective test procedures and gauge setting mechanisms. A flowing well should have a crown valve installed before gauges are run into a well to conduct a drawdown test. This allows gauges to be retrieved during the drawdown test without disturbing the well flow. SUGGESTED TEST PROCEDURES: • Downhole Pressure Measurement


1. Make dummy run with sinker bar to

desired run depth with well shut in. 2. Run gauge(s) into well under shut-in

conditions. Make static gradient stops while running gauges in the well.


4. Record sufficient shut-in data with gauges on bottom to allow the gauges to stabilize, usually one hour.

5. Start flowing the well. The gauges must be in place and adequately stabilized so that the pressure and time can be accurately recorded when the well is opened to flow.

6. Flow well. Maintain a constant rate for the duration of the drawdown period.

7. Retrieve gauges. Make flowing gradient stops while retrieving gauges from well.


Example Test Configuration - Flowing Well

Seating Nipple

Gauge(s)

Tubing


No-Go


FLOWING WELLS


• Surface Pressure Measurement (for dry gas wells)

1. Program and install surface pressure

gauge. 2. Record sufficient shut-in pressure

data to check with a secondary measurement device such as a deadweight gauge.

3. Start flowing the well. The gauge must be in place and adequately stabilized so that the pressure and time can both be accurately recorded at the time the well is opened to flow

4. Flow well, maintain a constant rate for the duration of the drawdown period. Since the measurement equipment is on surface it should be checked regularly to make sure the test is progressing as anticipated and that the equipment is performing properly.





The majority of producing oil wells are sucker rod-pumped. There are two major options for testing sucker rod pumped wells – AWS (Automatic Well Sounder) technology, and the use of bottomhole pressure gauges. AWS technology is a good option for many pumping wells. It eliminates costs associated with pulling the pump. Wells that lie outside the previously discussed constraints associated with AWS technology require the use of bottomhole pressure gauges for accurate measurements. Sucker rod pumped wells can often be costly to test when using bottomhole pressure gauges. To conduct a test using bottomhole pressure gauges, the rod string and pump must first be pulled, requiring the use of a pulling unit. Gauges then need to be set below the seating nipple, either in a mud anchor or using a casing hanger. Production not only ceases when the pump is unseated and the rod string is pulled, an injection transient may also take place as wellbore fluids empty from the tubing and “U-tube” into the casing-tubing annulus with some fluid flowing back into the formation. Because of this, the pump must be run back in and the well allowed to stabilize with the gauges in place before a true drawdown test can be conducted. The well should ideally be shut in long enough for the reservoir pressure to stabilize. Pressure transient tests should be avoided on pumping wells that have been hot-oiled within a time period equal to the estimated test length.

SUGGESTED TEST PROCEDURES: • AWS Measurement System 1. Program and install the AWS unit. 2. Monitor the well until surface

pressure and fluid level are firmly established. (Fluid level ideally should be checked by a second source, such as a single-shot fluid level device. Surface pressures should also be verified with either a deadweight gauge or a high-quality test gauge.) The reservoir pressure should be stabilized before the test is conducted.

3. Start pumping the well. The AWS unit must be in place so that the shut-in pressure and fluid level can both be accurately recorded at the time the pump is started and the well opened up.

Example Test Configuration - Sucker Rod Pumped Well

Pump

Seating Nipple

Gauge(s)

Mud Anchor

Bull Plug

Sucker Rods andPump run in abovegauge(s)




4. Continue pumping the well for the duration of the drawdown period. The producing rate must be kept constant. Since the measurement equipment is on surface it should be checked regularly to make sure the test is progressing as anticipated and that the equipment is performing properly. Data can be downloaded and evaluated as the test progresses.



− Gauge Setting Options: Set in Mud Anchor, Whiskered Bomb Hanger for Casing*

1. Pull sucker rods and pump. Also pull

tubing if the string needs to have a mud anchor either added or lengthened to give the gauges ample room to avoid contacting the pump.

2. Run gauge(s) into well and release either in mud anchor or casing.

3. Run the sucker rod string back in and set the pump.

4. Shut in the well and allow the reservoir pressure to stabilize. Make sure that all valves on surface are closed, both on the tubing and casing sides. The pumping unit should be shut down on the downstroke to help insure a closed standing valve.

Any peripheral equipment, such as chemical injection pumps or vapor recovery equipment, that could affect the test should also be shut off.

5. Start pumping the well and record the time. (If operating company personnel shut in the well, the time that the pump started should be recorded and if possible, synchronized with the wireline operator that initiated the test.)

6. Continue pumping for the duration of the drawdown period. The producing rate must be kept constant.

7. Turn off pump and bleed down well pressure. This time should be recorded.

8. Pull the sucker rod string. 9. Retrieve the gauge(s). *Please refer to the previous section, “Gauge Setting and Deployment Methods” for more detailed information for each setting option.




AWS (Automatic Well Sounder) technology can be a good, cost effective option for wells with electrical submersible (ESP) pump installations if there is not a packer in the well. The normal constraints and assumptions hold when AWS is used on ESP- pumped wells as when it is used on sucker rod pumped wells. AWS can also be used as a backup for downhole gauge data, and to provide data for afterflow calculations. ESP-pumped wells tend to be expensive to test when bottomhole pressure gauges have to be run to record the data. When a pressure drawdown test is conducted, the bottomhole pressure gauges must be set below the pump to record the drawdown of reservoir pressure. This means that when bottomhole pressure gauges are to be used, the tubing string and the pump must first be pulled. The gauges can then be either run in a mud anchor or in the casing below the pump. In some cases, submersible pump installations include a “Y” tool that allows wireline operations, such as running downhole pressure gauges, to be performed without pulling the pump. Other ESP installations include a permanent downhole pressure gauge with surface readout. These gauges can provide a very cost-effective means of providing useful test data. Care must be taken because not all of these gauges provide adequate resolution and accuracy for pressure transient type tests.



1. Pull tubing string and pump. 2. Run gauge(s) into well and release

using casing hanger. 3. Run tubing and pump back into well. 4. Shut in the well and allow the

reservoir pressure to stabilize. Make sure that all valves on surface are closed, both on the tubing and casing sides.

Any peripheral equipment, such as chemical injection pumps or vapor recovery equipment, that could affect the test should also be shut off.

Fluid Production

Reservoir Fluids

Check Valve


Pump

Motor

Master Valve

Pump Intake

Power Cable

Example Test Configuration - Electrical Submersible Pump




5. Turn on the pump, produce the well, and record the time. (If operating company personnel started the pump, the time that the pump was started should be recorded and if possible, synchronized with the wireline operator that initiated the test.)

6. The well must be produced at a constant rate for the duration of the drawdown period.


• AWS Measurement System 1. Program and install the AWS unit. 2. Monitor well until surface pressure

and fluid level is firmly established. (Fluid level ideally should be checked by a second source, such as a single-shot fluid level device. Surface pressures should also be verified with either a deadweight gauge or a high quality test gauge.) The reservoir pressure should be stabilized before the test is conducted.

3. Start pumping the well. The AWS unit must be in place so that the shut in pressure and fluid level can both be accurately recorded at the time the pump is started.

4. Continue pumping the well for the duration of the drawdown period. The producing rate must be kept constant. Since the measurement equipment is on surface it should be checked regularly to make sure the test is progressing as anticipated and that the equipment is performing properly. Data can be downloaded

and evaluated as the test progresses.



− Gauge Setting Options: Mud Anchor below pump*

1. Pull tubing string and pump. 2. Insert gauge(s) into mud anchor.

Attach mud anchor to pump. 3. Run tubing and pump back into well. 4. Shut in well until reservoir pressure

is stabilized. 5. Turn on pump and produce the well.

Make sure that the time and pressure is recorded when the pump is turned on.

6. Produce well for the duration of the drawdown period.





• Permanent Downhole Gauge with Surface Readout − ESP systems with permanent

downhole, surface readout pressure gauge installations. These systems offer a very cost effective method for conducting a well test. However, some of these gauges have inadequate resolution and accuracy for obtaining usable pressure transient test data.

1. Well should be shut in until the

reservoir pressure is stabilized. Record shut in pressures and times.

2. Turn on pump and produce the well. Record producing pressures and times. Care should be taken to record the shut in pressure and time at which the pump is started and to record early time data at a high enough sampling frequency to accurately define the drawdown response.

3. Produce the well at a constant rate for the duration of the drawdown period. Pressures should be monitored at surface and evaluated to determine when an adequate amount of test time has been reached.

4. End test. Make sure all data is downloaded and saved.



SUMMARY OF PRODUCTION AND TEST METHODS


The following table shows a brief overview of the producing methods just discussed with many of the more commonly used test approaches that are available for obtaining pressure drawdown data from wells employing these methods. This table is not all- inclusive for either the types of producing methods or test approaches. Additionally, in many cases a combination of these approaches may be required for a successful test.

PRODUCTION METHODS

DEP

LOYM

ENT

OR

M

EASU

REM

ENT

MET

HO

D

FLO

WIN

G

SUC

KER

RO

D P

UM

P

ELEC

TRIC

AL

SUBM

ERSI

BLE

PUM

P

NO-GO ON SEATING NIPPLE *COLLAR-SET *TUBING-HANGER *HANG ON WIRE *CASING HANGER * * *AWS * *2

SURFACE PRESSURE GAUGE *1

MUD ANCHOR BELOW PUMP * *ATTACH TO PUMP *3

1 - Dry gas wells with no fluid.2 - Can be used if the well has no packer.3 - Some installations have a permanent downhole gauge.

PRESSURE TRANSIENT TEST TYPES SINGLE-RATE TESTS – INJECTION WELLS

PRESSURE FALLOFF TESTS


The pressure falloff test is one of the more commonly used pressure transient tests on injection wells. The pressure falloff test is analogous to the pressure buildup test. Its main requirement is for an active injection well to be shut in and the resulting decrease in pressure measured as a function of shut-in time. The following diagrams show a typical pressure falloff response:

Generic Test Procedure: 1. Inject into well 2. Install measurement equipment 3. Start recording test data – time,

pressure, injection rates 4. Shut in well 5. Continue recording data 6. Conclude test – retrieve data


and pressure at shut-in is critical. Gauges and/or other instruments should be in place and adequately stabilized so that the injection pressure and time can be accurately recorded when the well is shut in. Shut-in pressure is recorded as a function of shut-in time.

• Knowledge of the injection history is critical. Variations in injection rates need to be known. The closer a rate change occurs to the shut-in time, the greater its impact will be on the falloff response.

• Surface gauges can be used to conduct tests on injection wells if they maintain surface pressure throughout the duration of a test.


Injection types (not all inclusive): • Water • Gas • CO2 • Other (Polymers, Steam, etc…)

Injection Rate

Shut-In, Rate = 0

t (<t=0)

q

InjectionPressure

Shut-In Pressure

p

t (<t=0)

PRESSURE TRANSIENT TEST TYPES SINGLE-RATE TESTS – INJECTION WELLS – FALLOFF TESTS

FALLOFF TEST METHODS


Injection wells are generally fairly straightforward wells to test. The main considerations tend to be the determination of safe, cost effective test procedures and gauge setting mechanisms. An injection well should have a crown valve installed before gauges are run into a well to conduct a falloff test. This allows the test to be set up and conducted without disturbing injection into the well.



1. Make dummy run with sinker bar to desired run depth with injection taking place.

2. Run gauge(s) into well under injection conditions, make gradient stops while running gauges in the well.


4. Record sufficient injection data with gauges on bottom, usually one hour. This not only helps characterize the nature of the well during injection conditions, it also helps the gauges to stabilize at reservoir conditions.

5. Shut in well. The gauges must be in place and adequately stabilized so that the injection pressure and time can both be accurately recorded at shut-in.

6. Keep well shut in for the duration of the falloff period.


*Please refer to the previous section, “Gauge Setting and Deployment Methods” for more detailed information for each setting option. • Surface Pressure Measurement 1. Program and attach surface

pressure gauge. 2. Record sufficient injection data to

characterize the well’s injection conditions.

3. Shut in well. The gauge must be in place and measuring the surface injection pressure at the time of shut in.

Seating Nipple

Gauge(s)

Tubing


No-Go

Example Test Configuration - Injection Well

PRESSURE TRANSIENT TEST TYPES SINGLE-RATE TESTS – INJECTION WELLS – FALLOFF TESTS

FALLOFF TEST METHODS


4. Keep well shut in for the duration of the falloff period. Since the measurement equipment is on surface it should be checked regularly to make sure the test is progressing as anticipated and that the equipment is performing properly. Data can be downloaded and evaluated as the test progresses.


6. A static pressure gradient can also be conducted to verify that there is a constant gradient of injection fluid to datum. If there is not a constant gradient, the calculated bottomhole pressures will not be correct. Some CO2 floods have shown banking of oil near the injector and had significant oil columns form in the wellbore during falloff tests.


PRESSURE INJECTIVITY TESTS


The pressure injectivity test is one of the least used pressure transient tests. The pressure injectivity test is analogous to the pressure drawdown test. Its main requirement is that an injection well, which is either new or that has been shut in to stabilization, be injected into and the resulting increase in pressure be measured as a function of injection time. Best attempts at injectivity testing are during pilot flood testing. However, due to the many issues related to fill-up and fingering versus banking, useful information is difficult to acquire from tighter zones. The following diagrams show a typical injectivity test response:

Generic Test Procedure: 1. Well is shut in until stabilization (may

be a new well) 2. Install measurement equipment 3. Start recording test data – time,

pressure, injection rates (initially zero injection)

4. Start injecting into well 5. Continue recording data throughout

injection period 6. Conclude test – retrieve data


and pressure when injection is started is critical. Gauges and/or other instruments should be in place and adequately stabilized so that the shut in pressure and time can be accurately recorded when injection is started. The injection pressure is recorded as a function of the injection time.

• Knowledge of the injection history is critical if the well has not been shut in long enough to reach a static reservoir pressure.

Injection Rate

Shut-In,Rate = 0

t (<t=0)

q

Injection Pressure

Shut-InPressure

p

t (<t=0)


PRESSURE INJECTIVITY TESTS


• The injectivity test requires constant injection rates – this may require constant monitoring of the well and surface injection facilities.

• The temperature response reported from electronic pressure gauges can aid in the interpretation.

Injection types (not all inclusive): • Water • Gas • CO2 • Other (Polymers, Steam, etc…)

PRESSURE TRANSIENT TEST TYPES SINGLE-RATE TESTS – INJECTION WELLS– INJECTIVITY TESTS

INJECTIVITY TEST METHODS


Injection wells are generally fairly straightforward wells to test. The main considerations tend to be the determination of safe, cost effective test procedures and gauge setting mechanisms. An injection well should have a crown valve installed before gauges are run into a well to conduct an injectivity test. This allows the test to be set up and conducted without disturbing the well during the injection portion of the test.



1. Make dummy run with sinker bar to desired run depth with well shut-in.

2. Run gauge(s) into well under shut-in conditions, make static gradient stops while running gauges in the well.


4. Record sufficient shut-in data with gauges on bottom to allow the gauges to stabilize, usually one hour.

5. Start injection. The gauges must be in place and adequately stabilized so that the shut-in pressure and time can both be accurately recorded when the well injection is started.

6. Continue injection for the duration of the test period. A constant injection rate must be maintained.

7. Retrieve gauges. Make injection gradient stops while retrieving gauges from well.


Seating Nipple

Gauge(s)

Tubing


No-Go

Example Test Configuration - Injection Well

PRESSURE TRANSIENT TEST TYPES MULTIRATE TESTS

FLOW-AFTER-FLOW TEST


The flow-after-flow test consists of a series of extended flowing periods, each of which is flowed until the pressure stabilizes. Some of the uses for flow-after-flow tests include the determination of a well’s deliverability and the calculation of rate-dependent skin. Although flow-after-flow tests are most often used with gas wells, it has been shown that such testing can also be used with oil wells. Flow-after-flow tests are often conducted to determine a well’s deliverability for regulatory purposes. When designing a flow-after-flow test it is important to consider whether the purpose of the test is for regulatory use, internal company use, or both. Regulatory requirements can sometimes

conflict with otherwise valid test procedures. These conflicts are best resolved before the test is conducted. Generic Test Procedure: 1. Install measurement equipment.

This includes surface equipment, for measurement of flow rates, and pressure gauges, either surface or downhole, for pressure measurement.

2. Produce well at multiple rates, typically four or more. Record flow rate and pressure data. Tests are normally conducted by starting at the lowest rate and progressing to the highest. Each rate is to be of sufficient length to allow stabilization of pressure.

q

p

pR

pwf1

pwf2

pwf3

pwf4

q1

q2

q3

q4

t

t

FLOW -AFTER-FLO WProducing Rates

FLOW -AFTER-FLO WPressure Response


FLOW-AFTER-FLOW TEST


3. Tests can also be conducted by starting a well flowing at the highest rate then progressing down to the lowest. This can be useful for wells that may have problems unloading liquids. The higher initial gas velocities can often lift liquids that may otherwise not be lifted at lower rates. This can be especially useful for newly completed wells that may not have had completion fluids adequately cleaned out.

4. Collect gas and liquid samples as needed.

5. Conclude test – retrieve data.

POINTS TO CONSIDER

• Flow rates should be run until pressure stabilization is achieved. Tests not run to pressure stabilization can lead to misleading results. Regulatory agencies have their own definitions of “pressure stabilization” that may or may not be

adequate for all purposes of a given test.

• Tests in low permeability systems can be very lengthy. During this period field personnel may be required to continually monitor and control the test and record test data.

• Field personnel conducting flow-after-flow tests typically need to have the ability to perform the following tasks: • Operate surface and downhole

measurement equipment. • Operate separators, line heaters,

and other equipment. • Ability to perform field

calculations and make operational decisions in the field.

• Shorter term transient stabilization (regulatory and IPR purposes) usually dictates opening the well up to specific choke (back-pressure) settings and allowing the well to gravitate towards its natural stabilized rate. However, for longer term pseudo-steady state (high productivity reservoir) stabilization the choke may have to be manipulated to maintain the stable surface rate.

• Rates need to be of sufficient velocity to lift liquids in gas wells and to maintain natural flow in flowing oil wells.

* See previous sections for discussions on bottomhole pressure gauge setting methods and the usage of bottomhole pressure gauges versus surface pressure gauges.

p S2 - p

f2

q

Reflects zero flowing pressure

AbsoluteOpen FlowPotential

1

10

100

1000

10 100 1000 10000

StabilizedDeliverability

Deliverability Plot

PRESSURE TRANSIENT TEST TYPES MULTIRATE TESTS ISOCHRONAL TEST


An isochronal test consists of a series of transient flowing periods of equal duration, separated by buildups to stabilization, followed by an extended flow period to stabilization. The rates are run from lowest to highest. In an isochronal test the transient flow points establish the slope of the deliverability curve. The extended, stabilized rate is then used to position the deliverability curve. Uses for isochronal tests include the determination of a wells deliverability and the calculation of rate dependent skin. Although isochronal tests are most often used with gas wells, it has been shown that such testing can be also used with oil wells.

Generic Test Procedure: 1. Install measurement equipment.


2. Produce well at multiple rates, each followed by a shut-in period until pressure stabilizes. Record flow rate and pressure data. Each rate is to be of equal duration.

3. Collect gas and liquid samples as needed.

4. Conclude test – retrieve data.

q

p

pR

pwf1pwf2

pwf3

pwf4

q1

q2

q3

q4

t

t

pwf5

Extended Flow Rate

ISO CHRO NA LProducing Rates

ISO CHRO NA LPressure Response

PRESSURE TRANSIENT TEST TYPES MULTIRATE TESTS ISOCHRONAL TEST


POINTS TO CONSIDER • Flow rates are to be of equal

duration. Each flow period is to be followed by a period where the well is shut in until pressure stabilization. A final long-term rate is to also be run to stabilization. Tests where the shut-in pressure is not allowed to stabilize can lead to misleading results. Regulatory agencies have their own definitions of “pressure stabilization” that may or may not be adequate for all purposes of a given test.


• Field personnel conducting isochronal tests typically need to have the ability to perform the following tasks: • Operate surface and downhole




• The results of the isochronal test can be used to establish long term deliverability into a pipeline based on various line pressures.


* See previous sections for discussions on bottomhole pressure gauge setting methods and the usage of bottomhole pressure gauges versus surface pressure gauges. p S2 -

pf2

q



1

10

100

1000

10 100 1000 10000

TransientDeliverability


Deliverability Plot


MODIFIED ISOCHRONAL TEST


Although isochronal tests can be used to reduce test time compared to a flow-after-flow test, in very tight reservoirs the amount of time required to conduct an isochronal test can still be too long to be practical. The modified isochronal test reduces this test time. It consists of a series of transient flowing periods of equal duration, separated by buildups of the same duration as the flow rates, followed by an extended flow period to stabilization. In a modified isochronal test the transient flow points establish the slope of the deliverability curve. The extended, stabilized rate is then used to position the deliverability curve. Uses for modified isochronal tests include the determination of a wells deliverability and the calculation of rate dependent

skin. Although modified isochronal tests are most often used with gas wells, it has been shown that such testing can also be used with oil wells. Generic Test Procedure: 1. Install measurement equipment.


2. Produce well at multiple equal length rates, each followed by a shut-in period of the same duration. Record flow rates and pressure data.

3. Collect fluid samples as needed. 4. Conclude test – retrieve data.

q

p

pR

pwf1pwf2

pwf3

pwf4

q1

q2

q3

q4

t

t

pwf5

Extended Flow Rate

MODIFIED ISOCHRONALProducing Rates

MODIFIED ISOCHRONALPressure Response


MODIFIED ISOCHRONAL TEST


POINTS TO CONSIDER • Flow rates are to be of equal

duration. Each flow period is to be followed by an equal length shut-in period. A final long-term rate is to be run to stabilization. Regulatory agencies have their own definitions of “pressure stabilization” that may or may not be adequate for all purposes of a given test.



• The results of the modified isochronal test can be used to establish long term deliverability into a pipeline based on various line pressures.

• Field personnel conducting modified isochronal tests typically need to have the ability to perform the following tasks: • Operate surface and downhole




* See previous sections for discussions on bottomhole pressure gauge setting methods and the usage of bottomhole pressure gauges versus surface pressure gauges.

p S2 - p

f2

q



1

10

100

1000

10 100 1000 10000

TransientDeliverability


Deliverability Plot

PRESSURE TRANSIENT TEST TYPES MULTIRATE TESTS STEP-RATE TEST


Step-Rate tests are used to estimate the formation parting pressure in an injection well. Each rate is of equal duration. These can range from 15 minutes to one hour in length. Typically six or more rates are desirable with a minimum of least three rates above the parting pressure. The formation parting pressure is dependent on many factors such as reservoir pressure and relative fluid saturations. Over the life of an injection well the parting pressure can change as these factors vary. If injection rates achieve pseudo-radial flow it may be possible to analyze the total pressure response for permeability and skin.

Generic Test Procedure: 1. Shut in well, allow bottomhole

pressure to stabilize. If it is not feasible to shut in the well, the well should be stabilized at the lowest possible rate.

2. Install measurement equipment. 3. Start injecting at the lowest rate.

Record flow rates and pressure data. 4. Continue injecting at increasing rates

until at least three points are recorded after the formation parting point is reached. Because injection pumps and system friction can often result in “noisy” data, additional points may be required before the parting point can be positively determined.

p R

p 1

p 2

p 3

p 4

p 5

p 7p 6

q 1

q 2

q 3

q 4

q 5

q 6

q 7

q = 0 q = 0

q

p

t

t

S T E P -R A T EIn je c tio n R a te s

S T E P -R A T EP re ssu re R e sp o n se



POINTS TO CONSIDER • What is the goal of the test? Must a

parting point be reached or is the goal to simply reach a high enough pressure and/or rate to determine that the formation will not part with current injection facilities. It is important to know whether the test is for internal purposes or if it is to fulfill regulatory requirements.

• Injection periods must all be of the same duration.

• Are existing injection facilities adequate or is a pump truck needed?

• Will the injection source be capable of not only providing the required rates and pressures, but also of providing controllable, steady rates that can be properly monitored and measured?

• If the injection system goes down during the test, the test may have to

be stopped and restarted at a later date. This depends on the relative length of the system down time to the rate duration.

• Properly sized flow meters are required to measure injection rates. Because the required range of injection rates often exceeds the range of a single flow meter, a manifold is often required to allow the use of multiple flow meters.

• How clean is injection fluid. Debris and contaminants in injection fluid can impede the measurement of injection rates. Additionally, at higher injection rates, meters can be physically damaged if debris is caught in impeller blades.

• Friction in the tubing can mask the formation parting point when pressures are monitored at surface. Bottomhole pressure measurement can be used to more accurately determine the actual parting point.

• Some wells may start at pressures above the formation parting point, especially existing injection wells. For wells starting above the parting point, what appears to be a parting pressure during a test, may just be a “fracture extension” pressure. It may be necessary in these cases to back-flow the well to drop the pressure below the parting point prior to starting the test.

• For wells that are in the early stages of injection (within the initial fillup), it may be necessary to begin the test at a very low stabilized rate. This helps to overcome an initial wellbore storage period that may affect the early rates if started from shut-in.

PRES

SUR

E, P

SI

INJECTION RATE, STB/D

Injection Rate atparting pressure

Fracture Pressure

Step-Rate PlotParting Pressure and Rate



• The Step Rate Guidelines of the Railroad Commission of Texas are shown in the following section. They serve as an excellent design guide.

* See previous sections for discussions on bottomhole pressure gauge setting methods and the usage of bottomhole pressure gauges versus surface pressure gauges. RAILROAD COMMISSION OF TEXAS - STEP RATE GUIDELINES A step-rate test is a method used to accurately measure the fracture pressure of a given formation. A step-rate test must demonstrate that formation fracturing will not occur at the proposed injection pressure. The test is conducted by injecting into the formation at a series of increasing rates, allowing each to stabilize, and noting the stabilized injection pressure for each rate. A plot of injection pressure vs. injection rate is then made to identify the fracture pressure. The basic equipment required is as follows: 1. A water supply truck capable of

pumping the water down hole under increasing pressure.

2. Surface monitoring equipment capable of measuring injection rate and pressure.

To convert surface pressure to bottom hole pressure (BHP), you must know the inside diameter and condition of the tubing to compute frictional losses and the density of the frac fluid to compute

the hydrostatic pressure. It is also recommended that a down-hole pressure bomb be used to measure BHP so that you will have two sources of data which can be compared when checking for errors. The following procedure is recommended to ensure meaningful test results. 1. The test well should be shut in long

enough so that the bottom-hole pressure is near the shut-in formation pressure (No less than 48 hours). The well may need to be backflowed if the shut-in pressure is above the expected fracture pressure of 0.5 psi/ft of depth.

2. Suggested rates for the test are 5, 10, 20, 40, 60, 80, & 100% of the proposed maximum daily injection volume and corresponding pressures. The first rate should be the formation matrix rate (the rate at which the formation begins to accept fluid). In addition, at least two rates must be below the expected fracture pressure of 0.5 psi/ft.

3. Each rate must be allowed to stabilize before proceeding to the next higher rate. A step duration of 60 minutes is recommended for formations with permeability less than 10 millidarcies, and 30 minutes for formations with permeability greater than 10 millidarcies.

4. EACH STEP SHOULD LAST EXACTLY AS LONG AS THE PRECEDING STEP.

5. The use of a pressure recorder chart to document the testing process is recommended.

PRESSURE TRANSIENT TEST TYPES MULTIWELL TESTS

INTERFERENCE TEST


Multi-well tests provide a larger areal estimate of reservoir properties such as permeability. These tests require one active well and at least one observation well. When multiple observation wells are used, directional variations in permeability can be detected and quantified. It is also possible to detect the existence of fractures, both natural and man-made, when these fractures extend from well to well. An interference test requires one long- term rate modification in the active well. The observation well is shut in for the duration of the test while the bottomhole pressure response is monitored, recording the response due to the active well rate change.

Generic Test Procedure: 1. Allow observation well(s) to stabilize. 2. Install measurement equipment in

observation well(s). Allow well(s) adequate time to stabilize and for a pressure trend to develop. Record sufficient data to determine the overall trend in reservoir pressure.

3. Change rate in the active well. This could be either an increase or decrease. It could also be a complete shut-in of a producing well or the opening up of a shut-in producer. The active well could also be an injection well.

4. Record sufficient data in observation well(s) to adequately detect and quantify the interference response.

q

p

t0

t

INTERFERENCE TESTActive Well Rates

INTERFERENCE TESTPressure Responses

<t

t0

<t

Time Lag

Observation Well

Established Trend

Active Well


INTERFERENCE TEST


POINTS TO CONSIDER • Multi-well tests typically require a

significant amount of up-front work and input data to successfully design the test.

• Control is needed not only for the active well and observation well(s), but for the reservoir as a whole. Wells on neighboring leases can greatly affect the outcome of a multi-well test. Even short-term events such as frac jobs have been known to adversely effect multiwell tests.

• Good coordination between all involved parties is crucial for a successful outcome.

• High resolution gauges are often required. Backup gauges should be fully capable of detecting the anticipated pressure response.

• It is advisable to have a thorough calibration check conducted on all gauges to be used.

• Downhole gauges need to collect data over a long enough period of time to identify reservoir pressure trends. They also need to be able to distinguish other types of behavior such as tidal effects and background noise.

• An “interference test” run as an afterthought to another test, such as a buildup, is not generally a good idea. It is easy to misinterpret a pressure response as interference when there has been inadequate planning and control over the test.

• Pressure gauges should be placed in observations wells in such a fashion that the threat of potential wellbore effects such as phase redistribution

or moving fluid interfaces will be minimized.

• All possibilities of wellhead leaks should be eliminated.

* See previous sections for discussions on bottomhole pressure gauge setting methods.


PULSE TEST


Multi-well tests provide a larger aerial estimate of reservoir properties such as permeability. These tests require one active well and at least one observation well. When multiple observation wells are used, directional variations in permeability can be detected and quantified. It is also possible to detect the existence of fractures, both natural and man-made, when these fractures extend from well to well. A pulse test requires multiple rate modifications in the active well. These rate changes are typically of shorter duration compared to the rate change in

an equivalent interference test. The observation well is shut in for the duration of the test while the bottomhole pressure response is monitored, recording the response due to the active well rate changes. Generic Test Procedure: 1. Allow observation well(s) to stabilize. 2. Install measurement equipment in

observation well(s). Allow well(s) adequate time to stabilize and for a pressure trend to develop. Record sufficient data to determine the overall trend in reservoir pressure.

q

p

t0

t

PULSE TESTActive Well Pulses

PULSE TESTPressure Responses

t0

Established Trend

Pulse Responses


PULSE TEST


3. Pulse rates in the active well. The active well can be shut-in, opened up, or injected into to create the pulses. All pulses are to be of equal length with each other and all shut-in periods are to be of equal length with each other. However, pulse periods and shut-in periods can be either equal or different.

4. Record sufficient data in observation well(s) to adequately detect and quantify the pulse responses.

POINTS TO CONSIDER

• Multi-well tests typically require a significant amount of up-front work and input data to successfully design the test.

• It is recommended to create a pressure trend in the observation well(s) that can be modeled, such as a buildup test, to aid in the analytical history matching of the response.

• Pulse test responses are typically easier to distinguish from the reservoir trend and background noise as compared to a long-term interference response. The pulses are usually shorter in duration compared to a single long-term rate modification.

• Control is needed not only for the active well and observation well(s), but for the reservoir as a whole. Wells on neighboring leases can greatly affect the outcome of a multi-well test. Even short-term events such as frac jobs have been known to adversely effect multiwell tests.

• Good coordination between all involved parties is crucial for a successful outcome.

• High resolution gauges are often required. Backup gauges should be fully capable of detecting the anticipated pressure response.

• It is advisable to have a thorough calibration check conducted on all gauges to be used.

• Downhole gauges need to collect data over a long enough period of time to identify reservoir pressure trends. They also need to be able to distinguish other types of behavior such as tidal effects and background noise.

• A “pulse test” run as an afterthought to another test, such as a buildup, is not generally a good idea. It is easy to misinterpret a pressure response as a pulse when there has been inadequate planning and control over the test.


PRESSURE TRANSIENT TEST TYPES SPECIALIZED TESTS

VERTICAL INTERFERENCE/PULSE TESTS


Vertical interference and vertical pulse tests can be used to detect communication between zones. They can also be used to check for interference during hydraulic fracturing jobs. When properly designed and conducted, these tests can also be used to estimate vertical permeability.

Generic Test Procedure: 1. Run bottomhole pressure gauges.

Set bridge plug. Gauges can either be attached to the bottom of the plug or run separately and set below the plug.

2. Run tubing. Perform operation on upper zone. This could be producing from or injecting into the zone or another operation such as perforating, acidizing, or fracturing.

3. Record pressure response. 4. Pull tubing. Retrieve bridge plug and

gauges.

POINTS TO CONSIDER • Vertical interference and pulse tests

sometimes require special completions to allow adequate distance between the gauges and the active set of perforations before these tests can be successfully conducted.

• Vertical interference and pulse tests can be very complicated to design and conduct, especially when the data is being using in a formal analysis for evaluating reservoir properties such as vertical permeability.

• Bridge plug and packer leaks can render the data useless. Test procedures should include pressure testing of this equipment. Channeling behind the casing and the presence of vertical fractures can also lead to erroneous interpretation of the data, but are typically more difficult to detect.

* See previous sections for discussions on bottomhole pressure gauge setting methods. Alternative Method: • One alternative to the vertical

interference/pulse type tests is to drill into only the top portion of a zone and perform a partial penetration completion. Vertical permeability can then be determined from a spherical flow portion of a buildup test response conducted on the well. This procedure is sometimes used when a well is first drilled into an upper portion of a zone before ultimately drilling horizontally through the zone.

PRESSURETRANSIENT

PRESSURE GAUGE

VERTICAL INTERFERENCE OR PULSE TEST

TUBING

BRIDGE PLUG


MEASUREMENT WHILE HYDRAULICALLY FRACTURING


Bottomhole pressure gauges can be used during hydraulic fracturing operations to monitor bottomhole pressures during the job. The data allows accurate determination of bottomhole pressures throughout the job which would otherwise have to be calculated during from surface pressures. Calculated bottomhole pressures can be very erroneous due to friction and other flow effects.

Generic Test Procedure: 1. Run bottomhole pressure gauges

either on tubing inside a piggyback gauge carrier or on a wireline inside a pup joint gauge carrier.

2. Perform hydraulic fracturing job. 3. Retrieve gauges after completion of

operation.

POINTS TO CONSIDER • Gauges can be damaged when they

are run in on the tubing inside a piggyback gauge carrier. Although rubber spacers and shock absorbers help to protect the gauges from some of the shock and vibration, rough treatment of the tubing and encounters with downhole obstructions can still damage gauges. Vibrations during the actual

frac job itself can also damage gauges.

• If a pup joint arrangement is used, the well may have to be cleaned out before the gauges can be fished out if sand fills the bottom of the wellbore. This may require a “wash-over” retrieval using tubing if the pup joint cannot be retrieved by wireline.

PIGGYBACK GAUGECARRIER WITH PRESSUREGAUGES INSIDE

PACKER

PERFORATIONS

MEASUREMENT WHILE FRACTURINGUSING PIGGYBACK GAUGE CARRIER

PERFORATIONS

PACKER

PUP JOINT GAUGECARRIER WITH PRESSUREGAUGES INSIDE

MEASUREMENT WHILE FRACTURINGUSING PUP JOINT GAUGE CARRIER


MEASUREMENT WHILE HYDRAULICALLY FRACTURING


• It is imperative to plan the sampling sequence of the electronic gauges so that data is captured at a high sampling frequency while the actual frac job is taking place. The test plan must take into consideration downhole memory gauge limitations for storing data samples as well as the potential for delays with the frac job itself.



CHAPTER 5

DIAGNOSTIC AND WIRELINE SERVICES

DIAGNOSTIC AND WIRELINE SERVICES


In addition to pressure transient testing, ARC provides a wide range of complimentary diagnostic and wireline services. Logging Memory Production Logging Diagnostic Services Static and Flowing Gradient Surveys Acoustic Fluid Levels Bottomhole Fluid Samples Inclination Surveys Packer Leakage Tests Temperature Surveys for locating top of cement Regulatory Forms Railroad Commission Of Texas

G-1 – Gas Well Back Pressure Test G-5 – Gas Well Classification Report G-10 – Gas Well Status Report H-15 – Test On Well More Than 25 Years Old (Fluid Level) W-6 – Communication or Packer Leakage Test

New Mexico Oil Conservation Division C-122 – Multipoint and One Point Back Pressure Test For Gas Well Wireline Services Total Depth Measurements Paraffin Cutting Plugs Fishing Bailing Plungers Broaching Shift Sleeves Pull Standing Valves


CHAPTER 6

REGULATORY TESTING SERVICES

REGULATORY TESTING SERVICES


ARC provides a range of regulatory testing services. These services include the performance of all necessary field operations as well as the completion of all applicable regulatory forms. ARC will work closely with customers to help design the optimal test. Many regulatory tests such as four-point tests are relatively complex and require a good deal of information to properly set up and conduct. When necessary, ARC will call the appropriate regulatory authorities for specific rulings on special conditions or questions concerning any regulatory procedures we perform on behalf of our clients. The policy of ARC Pressure Data Inc. is to sign appropriate regulatory forms as a “third-party” tester provided compliance is maintained regarding ALL regulatory requirements. It should always be remembered that when conducting tests for government agencies all regulatory requirements have to be addressed. Sometimes this entails additional work compared to an equivalent test conducted solely for data acquisition purposes and sometimes it entails less. By understanding these requirements before a test is designed and conducted, a number of potential problems and misunderstandings can be avoided.

Several of the regulatory forms require information concerning the well’s completion history and other types of background information. ARC can populate these forms with this information as an added service for clients if this information is provided in a timely fashion. Texas One-Point and Four-Point Tests Forms: • G-1 – Gas Well Back Pressure Test • G-5 – Gas Well Classification Report • G-10 – Gas Well Status Report Fluid Level on Inactive Wells Forms: • H-15 – Test On Well More Than 25

Years Old (Fluid Level) Packer Leakage Tests Forms: • W-6 – Communications or Packer

Leakage Test New Mexico One-Point and Four-Point Tests Forms: • C-122 – Multipoint and One Point

Back Pressure Test For Gas Well Other States AS NEEDED


CHAPTER 7

THE WELL TEST

THE WELL TEST SCHEDULING AND SETTING UP THE TEST


ARC PRESSURE DATA, INC. - WELL DATA SHEET Page of

JOB NUMBER OPERATOR(S) COMPANY CONTACT LEASE PHONE WELL # FAX FIELD E-MAIL FORMATION DATA TO COUNTY PHONE STATE FAX START DATE: @ E-MAIL

LENGTH, days : hours : DATA TO END DATE: @ PHONE JOB TYPE FAX BILLING ADDRESS E-MAIL

WELLBORE INFORMATION DEPTHS FROM…………… TBG SIZE (1) WT DEPTH ELEV K.B…….. TBG SIZE (2) WT DEPTH ELEV G.L…….. CSG SIZE (1) WT DEPTH WELLHEAD INFORMATION CSG SIZE (2) WT DEPTH CONNECTION LINER SIZE WT DEPTH HEIGHT NIPPLE 1 ID DEPTH CROWN VALVE?…………. NIPPLE 2 ID DEPTH FULL OPENING?………….. NIPPLE 3 ID DEPTH OTHER PACKER ID DEPTH EXPECTED PRESSURES TBG ANCHOR ID DEPTH FLOWING WHP MUD ANCHOR ID DEPTH SHUT-IN WHP MISC. ID DEPTH FLOWING BHP MIN ID ID DEPTH SHUT-IN BHP TD BHT@DEPTH @

COMPLETION DETAILS WELLBORE FLUID PRECAUTIONS PERFORATIONS H2S (PPM , %)………….GRAVEL PACK CO2 (PPM , %)………….SLOTTED LINER OTHER OPEN HOLE

ADDITIONAL PRECAUTIONS WELL ORIENTATION (Paraffin, Compression Packer, Slugging…) (Please include deviation schedule if NOT vertical) VERTICAL

WELL DIRECTIONS / OTHER COMMENTS

Trip Date Unit # Operator Start End Miles 1) 2) 3) 4)

Total:

Pertinent W ell Description,Contact Person(s), Deliveryand Billing Information


W ellbore & Completion Detail- typically on schematic...


Corrosive Fluids and/orTemperature and PressureEnvironment… for specifyingproper lubricator, wire, mastunit, instrumentation, andbatteries...


Directions to W ell andMileage Log


Grayed-out areas are primarily completed by ARC. All other areas are heavily dependent on customer input.

ARC PRESSURE DATA, INC. - WELL DATA SHEET Page of

JOB NUMBER OPERATOR(S) COMPANY CONTACT LEASE PHONE WELL # FAX FIELD E-MAIL FORMATION DATA TO COUNTY PHONE STATE FAX START DATE: @ E-MAIL

LENGTH, days : hours : DATA TO END DATE: @ PHONE JOB TYPE FAX BILLING ADDRESS E-MAIL

WELLBORE INFORMATION DEPTHS FROM…………… TBG SIZE (1) WT DEPTH ELEV K.B…….. TBG SIZE (2) WT DEPTH ELEV G.L…….. CSG SIZE (1) WT DEPTH WELLHEAD INFORMATION CSG SIZE (2) WT DEPTH CONNECTION LINER SIZE WT DEPTH HEIGHT NIPPLE 1 ID DEPTH CROWN VALVE?…………. NIPPLE 2 ID DEPTH FULL OPENING?………….. NIPPLE 3 ID DEPTH OTHER PACKER ID DEPTH EXPECTED PRESSURES TBG ANCHOR ID DEPTH FLOWING WHP MUD ANCHOR ID DEPTH SHUT-IN WHP MISC. ID DEPTH FLOWING BHP MIN ID ID DEPTH SHUT-IN BHP TD BHT@DEPTH @

COMPLETION DETAILS WELLBORE FLUID PRECAUTIONS PERFORATIONS H2S (PPM , %)………….GRAVEL PACK CO2 (PPM , %)………….SLOTTED LINER OTHER OPEN HOLE

ADDITIONAL PRECAUTIONS WELL ORIENTATION (Paraffin, Compression Packer, Slugging…) (Please include deviation schedule if NOT vertical) VERTICAL

WELL DIRECTIONS / OTHER COMMENTS

Trip Date Unit # Operator Start End Miles 1) 2) 3) 4)

Total:









Grayed-out areas are primarily completed by ARC. All other areas are heavily dependent on customer input.Grayed-out areas are primarily completed by ARC. All other areas are heavily dependent on customer input.

ARC Pressure Data Inc. utilizes a set of job order forms that are a very important link in the communication of data acquisition objectives while providing all the necessary wellbore, fluid, and completion information required for safe and successful execution of well tests. The job order forms for a typical bottomhole pressure test consist of a

Well Data Sheet, a Pressure Testing Sheet, and an Operations Log. Full size copies of these forms are included in the appendix. Well Data Sheet The well data sheet provides the information necessary for a well-trained

wireline technician to maneuver tools in and out of a wellbore safely. This sheet is standard for most of ARC’s slickline services. The customer provides most of the information on this sheet. The amount of information requested may seem excessive. However, the more that is known about a well before running equipment into it, the better the

chances are for a safe and successful wireline intervention. Even in cases where equipment is not actually run into a well, such as when “shooting fluid levels”, this same information is often necessary for successful completion of the job.



Pressure Testing Sheet The Pressure Testing Sheet is used for specifying the type of test, such as a pressure buildup test or static gradient. This sheet is completed by ARC when a job is taken and as the job takes place. This sheet is used to describe test objectives, and procedures for meeting those objectives. Instrument types and

specifications are recorded for electronic and mechanical downhole gauges as well as surface equipment. Additional downhole equipment required for safe and successful completion of the test is also noted on this sheet.

ARC PRESSURE DATA, INC. - PRESSURE TESTING SHEET Page of

COMPANY JOB NUMBERLEASE WELL #

TEST TYPE(S) FLOWING GRAD BUILDUP 4 PT / 1 PT INTERFERENCE STATIC GRAD FALLOFF STEP-RATE PULSE OTHER

INSTRUMENTS STRAIN QUARTZ AMERADA SAPHIRE AWS SPIDR OTHER

TOP: RANGE REC. SECTION PITCHCLOCK LENGTH

BOTTOM: RANGE REC. SECTION PITCHCLOCK LENGTH

EQUIPMENT, SIZES RECOMMENDNO-GO COLLAR STOP STOPSCASING HANGER TUBING STOPPLUG BAR SIZE ( OD X L) XOTHER

TEST OBJECTIVE

TEST PROCEDURE

Type of Pressure Test - Buildup,Static Gradient, ...Type of Pressure Test - Buildup,Static Gradient, ...

Instrumentation used for test -serial numbers, ranges, types,...Instrumentation used for test -serial numbers, ranges, types,...

Additional equipment required forrunning gauges - types and sizesAdditional equipment required forrunning gauges - types and sizes

Description of Pressure Test -Objectives and Procedures forsuccessfully fulfilling Objectives


Recommended/planned depthstops for pressure gradientsRecommended/planned depthstops for pressure gradients


ARC PRESSURE DATA, INC. - PRESSURE TESTING SHEET Page of

COMPANY JOB NUMBERLEASE WELL #

TEST TYPE(S) FLOWING GRAD BUILDUP 4 PT / 1 PT INTERFERENCE STATIC GRAD FALLOFF STEP-RATE PULSE OTHER

INSTRUMENTS STRAIN QUARTZ AMERADA SAPHIRE AWS SPIDR OTHER

TOP: RANGE REC. SECTION PITCHCLOCK LENGTH

BOTTOM: RANGE REC. SECTION PITCHCLOCK LENGTH

EQUIPMENT, SIZES RECOMMENDNO-GO COLLAR STOP STOPSCASING HANGER TUBING STOPPLUG BAR SIZE ( OD X L) XOTHER

TEST OBJECTIVE

TEST PROCEDURE

Type of Pressure Test - Buildup,Static Gradient, ...Type of Pressure Test - Buildup,Static Gradient, ...

Instrumentation used for test -serial numbers, ranges, types,...Instrumentation used for test -serial numbers, ranges, types,...

Additional equipment required forrunning gauges - types and sizesAdditional equipment required forrunning gauges - types and sizes



Recommended/planned depthstops for pressure gradientsRecommended/planned depthstops for pressure gradients




Operations Log The Operations Log is a vital component of the data reporting and interpretation process. It is used to coordinate events performed on a well with the data taken from test instrumentation.

ARC PRESSURE DATA, INC. - OPERATIONS LOG Page of

COMPANY JOB NUMBERLEASE WELL #OPERATOR(S)

DATE & TIME DWG DEPTH COMMENTS

Log of all Pertinent Operationsperformed on well throughouttest - crucial for synchronizingsurface events with bottomholepressure data retrieved fromgauges



ARC PRESSURE DATA, INC. - OPERATIONS LOG Page of

COMPANY JOB NUMBERLEASE WELL #OPERATOR(S)

DATE & TIME DWG DEPTH COMMENTS




THE WELL TEST REPORTING THE DATA


Report Format An example report for a typical pressure buildup test is illustrated on this page and the one following. Reports for other single-rate pressure transient tests would be similar in nature. Reports for more complex tests would be handled accordingly. Electronic Data Due to the large number of points acquired by electronic gauges, data

is normally “trimmed and thinned down” to about 300 to 700 data points for the hardcopy of the data report. A typical data listing for a buildup test will have the buildup data thinned logarithmically and the data acquired going in and coming out of the well trimmed off. Although the paper report has the “thinned down” listing of the data, a computer diskette containing all of the original data is also supplied to allow easy import of data into analysis software.

Operations Log - Complete chronologicallog of all events performed in conjunctionwith the test.

Operations Log - Complete chronologicallog of all events performed in conjunctionwith the test.

Gradient Reports - Flowingand static gradients run inconjunction with a pressuretransient test.

Gradient Reports - Flowingand static gradients run inconjunction with a pressuretransient test.

Data Diskette - The complete data file is saved onto adata diskette for easy import into well test analysissoftware. Data can also be “E-Mailed” over the Internetwhen requested.

Data Diskette - The complete data file is saved onto adata diskette for easy import into well test analysissoftware. Data can also be “E-Mailed” over the Internetwhen requested.



Report Options Report plots and listings can be provided in an electronic format (Adobe Acrobat PDF file format) upon request. They can be supplied on 1.44 MB floppy diskettes or E-Mailed over the Internet.

Plots - Basic data plots are reported.These include Coordinate, Log Log, andSemilog Plots. The Data Listing isusually “thinned down” to about 300 to700 data points. The data diskettecontains the complete data set.

Plots - Basic data plots are reported.These include Coordinate, Log Log, andSemilog Plots. The Data Listing isusually “thinned down” to about 300 to700 data points. The data diskettecontains the complete data set.



Quality Control An often-overlooked aspect of the data reporting process is that of quality control. It is during this phase that an in-depth look at the data is taken. During processing of the data several items are considered, among these are: • Do data sets from tandem gauges

agree with each other? Electronic gauges allow for very quick comparison of data from multiple gauges compared to the amount of time required for scanning charts from mechanical type gauges. − Gauges of similar resolution and

accuracy should be run in tandem. If a mechanical gauge is used to backup a higher resolution electronic gauge, data taken from the mechanical gauge may be incapable of verifying the pressure response of the electronic gauge.

• How well do gauge pressures

measured in the lubricator compare with deadweight gauge readings?

• Do pressure gradients measured going in or coming out of the well make sense?

• Do recorded temperatures from electronic gauges make sense? Temperature behavior can help explain anomalies with pressure data.

• Should a calibration check be conducted on one or more gauges?

• Does the overall pressure behavior look normal? Can all pressure events be accounted for?

Which gauge is correct? Maybeboth gauges are measuring withintheir stated accuracy and resolutionand they are “both correct”!

Which gauge is correct? Maybeboth gauges are measuring withintheir stated accuracy and resolutionand they are “both correct”!

Gauge #1 Gauge #2

What caused this event - well openedup accidentally, packer leaked,interference from a neighboring well,…or is it a gauge failure?

What caused this event - well openedup accidentally, packer leaked,interference from a neighboring well,…or is it a gauge failure?


CHAPTER 8

PRESSURE TRANSIENT ANALYSIS SERVICES

PRESSURE TRANSIENT ANALYSIS SERVICES ANALYSIS INPUT PARAMETERS


In addition to the actual data to be analyzed, many other input parameters are also required for a proper analysis of pressure transient data. The figure below points out several of the numerous dependencies between many of these input parameters. One can easily envision the rippling effect that a faulty input parameter may induce throughout an analysis. In “Errors in Input Data and the Effect on Well-Test Interpretation Results” by Spivey and Pursell, the effects of errors in input data on the results of well test interpretation is discussed. The abstract for this paper has been

included in the appendix. This paper is recommended for those interested in further exploring the importance of accurate input parameters for successful test interpretation. To assist with the collection of these parameters, ARC supplies “Well Test Input Parameter” sheets to be filled out for each analysis. The following pages highlight the use of these sheets and the importance of the requested input parameters and many of the interdependencies between these parameters. Full size copies of these forms are included in the appendix.

mhqBk µ6.162=

td

cktr

φµ029.0=

+

−−= 2275.3log1513.1

2

1

wt

ihr

rck

mpps

φµ

wgo γγγ ,,

B

GORBHPBHT ,,

µ

fgwo cccc ,,,

gow sss ,,

tc

φ

Pressure Transient AnalysisRelationships of Input Parameters and Equations



Well Test Input Parameters The importance of many of the input parameters required for a pressure transient test analysis is often underestimated and their effects misunderstood. The following discusses some very pertinent issues that need to be considered before each analysis. Fluid Properties Are reported fluid properties current or are they old? Were they taken from fluids coming from the well being tested, or were they taken from a neighboring well? In either case it needs to be determined whether the fluid properties are close enough to be applicable or whether they are going to lead to erroneous results.

A water gravity is often not reported for wells that produce only negligible amounts of water. However, since virtually all reservoirs contain at least some water, and this water gravity affects reservoir compressibility, this information is needed even though the well does not produce an appreciable amount of water. If a water sample has not been taken, a water resistivity taken from a well log can be used to estimate the water gravity. For waterfloods, are the water properties being reported for injected water, or are they for the original connate water?

Permeability, skin, boundary conditions, interference,fractures…?

Fluid gravity’s and GOR’s - skin, permeability,compressibility, viscosity, distance calculations...

Porosity - skin, compressibility, distancecalculations...

Formation height - permeability, skin, distancecalculations...

Fluid Saturations - skin, compressibility, distancecalculations...

Flow Rates and Flow History - permeability, skin,distance calculations...

Bottomhole Temperature, Initial Reservoir Pressure -fluid properties, reserves/depletion calculations...

Separator Pressure and Temperature - recombinationof condensate production into gas stream for totaldownhole flow rate...



Initial vs. Current GOR An initial GOR can be a better indicator of the actual reservoir fluids as opposed to fluids closer to the wellbore where the reservoir may have dropped below the bubble-point pressure. Gross vs. Net Height, Partial Penetration, Limited Entry, Deviated Wellbore The distribution of the net thickness throughout the gross thickness can affect the interpretation of a test. Does it tend to be contiguous, are there a couple of distinct zones, or are there numerous thin layers scattered throughout the gross height?

A partial penetration response with the test can simply be a confirmation of a limited entry into a formation. It can also be an indicator that only a limited portion of the perforations are contributing to production. A deviated wellbore can lead to miscalculation of permeability and skin properties if the reservoir height is not handled correctly.

Stimulation Detail - Hydraulically fractured/plannedfracture length?, acidized?, when was stimulationperformed?, was it successful or were theresuspected problems?...

Pre-Frac Permeability - If not known, the fracturelength, permeability, and skin can be very difficult todetermine

Completion Type - Affects qualitative and quantitativedecisions concerning the analysis approach

Horizontal Well - Requires additional input foranalysis

Additional information that could affect qualitative andquantitative decisions concerning the analysisapproach

Fluid properties at current reservoir conditions shouldbe provided if possible, otherwise various correlationswill be used to compute these values.



Fluid Saturations Are reported fluid saturations and compressibilities current or are they old? For waterfloods, is the reported water saturation current, or is it the original connate water saturation? Has CO2 been factored into the oil saturation and compressibility? Producing Rates Inaccurate producing rates are sometimes reported where they are taken from a very rough estimate. A look at the equation for calculating permeability quickly shows that it is directly proportional to the flow rate. An inaccurately reported flow rate will result in an inaccurate permeability. The effects of an inaccurate permeability then propagate throughout the analysis. Frequently, the goal of a test on a new well is to get an idea of reservoir properties and pressures to help determine whether or not the company would be justified in hydraulically fracturing the well, and if so, help supply better information for the design of the frac job. A common mistake on new gas well completions in tight zones is to report a flow rate of zero because the rate is “too small to measure”. Too often, if a flow rate is too small to be measured by a standard orifice meter, it is considered to be immeasurable. However, since permeability is directly proportional to the flow rate, the permeability calculated from a “zero” flow rate will be zero. One option to get around this is to just assume a very low value for a flow rate, however this can lead to very misleading answers. It turns out that these “immeasurable” flow

rates can often be measured by using a small residential type meter like those mounted outside a home or small business. These small meters are capable of measuring low flow rates of just a few mcf per day. The rate history of a well is also important. Rate changes should be modeled as closely as possible. Effects of rate changes that occur close to the start of a test tend to be greatly magnified compared to similar changes that may have occurred many weeks or months prior to the test. Pre-fracture Permeability When hydraulically fractured wells are tested, it is very helpful to know the “pre-fracture” permeability of the formation. This is because there is often very little uniqueness in the buildup curves if late-time pseudo-radial flow is not reached during the test. The result is that a wide variety of permeability, skin, and fracture half-length combinations can often be used to produce multiple type curve matches. In other words, the analyst may be able to come up with many answers, but not know which one is correct. Knowing the pre-fracture permeability allows the analyst to “lock in” on the permeability. The skin factor and fracture half-length can then be more easily determined. Geological Deposition What type of scenario does the team geologist or geophysicist perceive for the zone(s) being tested? Many times, this additional insight can be the “tie-breaker” when the analyst is faced with multiple scenarios that describe the data response equally well.

PRESSURE TRANSIENT ANALYSIS SERVICES REPORTING OF ANALYSIS RESULTS


Software ARC Pressure Data Inc. uses PanSystem, a powerful well test software system by Edinburgh Petroleum Services Limited, for analysis of pressure transient data. PanSystem’s capabilities include the use of pseudopressures and multiple time functions for handling varying production histories. Numerous models are available for wellbore storage, reservoir, and boundary responses. Oil,

water, & gas properties can be entered directly when available, or can be calculated from correlations or equations of state. Advanced simulation capabilities are available to model both multi-well and multi-layer scenarios. Well Test Analysis Single rate tests (pressure buildup, drawdown, falloff, and injectivity) performed on oil, gas, and water injection wells are analyzed for properties such as permeability, skin

SUMMARY OF RESULTS REPORT•One page overview of analysis results

SUMMARY OF RESULTS REPORT•One page overview of analysis results

COVER PAGECOVER PAGE

WELL TEST ANALYSIS RESULTS•Introduction - Discussion of well history and test scenario•Summary of Results - Summary of models utilized and well test results•Discussion of Results - Discussion of conclusions, assumptions, remaining issues

WELL TEST ANALYSIS RESULTS•Introduction - Discussion of well history and test scenario•Summary of Results - Summary of models utilized and well test results•Discussion of Results - Discussion of conclusions, assumptions, remaining issues



damage, extrapolated pressure, fracture half-length, fracture conductivity, and boundary conditions among others. By use of the Log-Log / Derivative plot, the well test analyst can make an initial evaluation of well test data. During this initial evaluation suitable models are chosen for inner boundary conditions, reservoir behavior, and outer boundary conditions. This initial evaluation is further evaluated by a series of steps ranging from a Horner analysis of a radial flow period to a type-curve / model matching process.

Pressure transient analysis often produces results that are non-unique. This is especially true for tests where there is not a distinct period of radial flow. In these cases multiple solutions can often be used to produce equally acceptable matches with the data. This is often the nature of pressure transient testing – the result being that additional information sources external to the well test must be leveraged to help narrow down the potential solutions. In these situations, the ARC well test analyst will work closely with customers in pursuing a solution.

Relevant analysis plots such as Log-Log, Horner, Type-Curve Model Match,Radial Flow Model Match Overlay, Square-Root, Spherical Flow,...

Relevant analysis plots such as Log-Log, Horner, Type-Curve Model Match,Radial Flow Model Match Overlay, Square-Root, Spherical Flow,...



Analysis Results The Well Test Analysis Results section consists of a discussion of the test scenario, analysis methodologies, test results, and reservoir models used. The Discussion of Results concludes by discussing any assumptions made during the analysis, remaining questions and ambiguities, and implications arising out of the analysis. Multiple, non-unique “solutions” are discussed that may require additional input from other sources such as seismic, logging, etc.

A brief Summary of Results is provided along with any applicable plots, and a listing of input parameters and input data.

Listing of wellbore and reservoir input parameters, analysis results, and test data.Additional listings of gas pseudo pressures, viscosity,… included as required.

Listing of wellbore and reservoir input parameters, analysis results, and test data.Additional listings of gas pseudo pressures, viscosity,… included as required.



ARC’s philosophy on practical application of transient test theory… “Over the years, we have come to embrace the approach of trying our best, with all of the advanced computational tools we have, to determine what a test is trying to tell us about a well’s completion or about the reservoir. We prefer to provide insights, inferences, and even multiple choice scenarios where obvious “textbook” solutions may not exist. We do this while adhering to the theoretical constraints as closely as possible. Our engineers work for you. Our hope is that you see this as an invaluable quality to have as an extension of your team, to help leverage those hard decisions that improve or maintain your well’s or your reservoir’s productivity.”


APPENDIX

ARC PRESSURE DATA, INC. - WELL DATA SHEET Page of TICKET/JOB NUMBER OPERATOR(S) COMPANY CONTACT LEASE PHONE WELL # FAX FIELD DATA TO FORMATION PHONE COUNTY FAX STATE E-MAIL SCHEDULED DATE/TIME DATA TO BILLING ADDRESS PHONE FAX JOB TYPE E-MAIL

WELLBORE INFORMATION TBG1 SIZE WT DEPTH DEPTHS FROM..... KB / GL TBG2 SIZE WT DEPTH ELEV. KB GL CSG1 SIZE WT DEPTH WELLHEAD INFORMATION CSG2 SIZE WT DEPTH CONNECTION LINER SIZE WT DEPTH HEIGHT NIPPLE 1 ID DEPTH CROWN/SWAB VALVE?.... Y / N NIPPLE 2 ID DEPTH FULL OPENING?................... Y / N NIPPLE 3 ID DEPTH OTHER PKR ID DEPTH EXPECTED PRESSURE/TEMP. TBG ANCHOR ID DEPTH FLOWING WHP MUD ANCHOR ID DEPTH SHUT-IN WHP MISC ID DEPTH FLOWING BHP MIN ID ID DEPTH SHUT-IN BHP TD BHT@DEPTH @

COMPLETION DETAILS WELLBORE FLUID PRECAUTIONS PERFS H2S PPM / % GRAVEL PACK CO2 PPM / % SLOTTED LINER OTHER OPEN HOLE ADDITIONAL PRECAUTIONS WELL ORIENTATION (Paraffin, Comp. Packer, Slugging,...) (Please include deviation schedule if yes to either) DEVIATED?..... Y / N HORIZONTAL?..... Y / N

WELL DIRECTIONS / OTHER COMMENTS:

Trip Date Unit # Operator Start End Trip Date Unit # Operator Start End 1) 5) 2) 6) 3) 7) 4) 8)

ARC PRESSURE DATA, INC. - PRESSURE TESTING SHEET Page of COMPANY TICKET/JOB NUMBER LEASE WELL #

TEST TYPE(S) FLOWING GRAD BUILDUP 4 PT / 1 PT STATIC GRAD FALLOFF STEP RATE PULSE INTERFERENCE OTHER INSTRUMENTS STRAIN QUARTZ AMERADA SAPHIRE AWS SPIDR OTHER

TOP: RANGE: REC. SECTION: PITCH: S / D CLOCK: LENGTH: BOTTOM: RANGE: REC. SECTION: PITCH: S / D CLOCK: LENGTH:

EQUIPMENT, SIZES RECOMMENDED GRADIENT STOPS BAR SIZE COLLAR STOP NO-GO TUBING STOP CASING HANGER PLUG OTHER TEST OBJECTIVE: TEST PROCEDURE:

ARC PRESSURE DATA, INC. - OPERATIONS LOG Page of COMPANY TICKET/JOB NUMBER LEASE WELL # OPERATOR(S)

DATE TIME DWG DEPTH COMMENTS

ARC PRESSURE DATA, INC. - AWS WELL DATA SHEET Page ofJOB NUMBER: TOOL # :COMPANY LEASE WELL #FORMATION FIELD TEST DATESCOUNTY STATE START ENDOPERATOR(S)

CONTACT: DATA TO: DATA TO:

PHONE PHONE PHONEFAX FAX FAX

E-MAIL ADDRESSES:

TUBING DETAIL: FLUID DATA:#JOINTS TUBING OIL GRAVITY H2S PPM/%AVG JOINT LENGTH WATER GRAVITY CO2 PPM/%SIZES & DEPTHS: GAS GRAVITY OTHERTUBING O.D. RESERVOIR TEMPERATURE:CASING SIZE BHTCASING WEIGHT PRODUCING RATES:LINER TOP BOPDLINER O.D BWPDLINER WEIGHT MCFDPUMP (SN) (Denote if gas is vented annulus gas or total produced)TBG ANCHORPERFORATIONS

BHP CALC DEPTHPLUG-BACK DEPTH PUMPING CYCLE:WELL ORIENTATION 1) CONTINUOUS (Please include deviation schedule if not vertical) 2) ON OFFANALYSIS INFORMATION:POROSITY GROSS HEIGHT WATERFLOOD:WATER SATURATION NET HEIGHT PATTERNOIL SATURATION DRAINAGE AREA AREAGAS SATURATION FORMATION TYPESTIMULATION INFO:

Pre-Frac Permeability (if hydraulically fractured) : md

TIME SINCE LAST MAJOR SHUT-IN:A major shut-in could consist of the last time the rods were pulled, a stimulation treatment, a batchchemical pump, a pre-planned down period, or a re-completion … etc. This is used to estimate aconsistent producing time using the last stabilized production test as shown above. If the pumpspeed was changed or a large increase or decrease in rates occurred since the last major shut-in,please provide a production history for use in variable-rate superposition.

Several of the above parameters are typically used with various correlations to calculate fluid and rockproperties required for a pressure transient analysis. If available, please supply the actual values ofthese properties for current reservoir conditions or attach the complete PVT analysis results.

CURRENT RESERVOIR CONDITIONS:Pressure: psia Temperature: oF

B o, RB/STB B w, RB/STB B g, ft3/scf

lo, cp lw, cp lg, cpco, psi-1 cw, psi-1 cg, psi-1

cf, psi-1

WELL TEST INPUT PARAMETERS

ARCARCPRESSURE DATA

I N C O R P O R A T E DI N C O R P O R A T E D

Company ___________________________ Phone # ______________________ Lease & Well # ______________________ Fax # ________________________ Field (formation) ___________________________________________________ County, State ______________________________________________________ Engineer ___________________________ Primary Purpose of Test _____________________________________________ __________________________________________________________________ __________________________________________________________________ Oil Gravity, (cco) ....................................................................__________ Deg API Gas Gravity, (ccg)...................................................................__________ Water Gravity, (ccw) ..............................................................__________ or PPM Chlorides...........................................................__________ ppm Cl- Initial Gas-Oil Ratio (GOR)................................................__________ Scf/STB Condensate Yield ................................................................__________ STB/MMcf Net Effective Porosity, (vv) ...................................................__________ % Gross Formation Thickness, (hg) ........................................__________ feet Net Formation Thickness, (hg) ............................................__________ feet Hole Radius, (rw) ..................................................................__________ feet Current Water Saturation, (Sw)..........................................__________ % Current Oil Saturation, (So)................................................__________ % Current Gas Saturation, (Sg) ..............................................__________ % Formation Lithology_____________________________________________ Bottomhole Temperature ...................................................__________ Deg F Initial reservoir pressure estimate, (Pi) ..............................__________ psia Stabilized Oil Rate, (qo) .......................................................__________ STB/day Stabilized Gas Rate, (qg) ......................................................__________ Mcf/day Stabilized Water Rate, (qw) .................................................__________ STB/day Producing time or rate schedule prior to test....................__________ hours (please include breakdown of rates/times on separate paper...) Drainage area, (A)................................................................__________ acres Separator Pressure...............................................................__________ psig Separator Temperature.......................................................__________ Deg F

WELL TEST INPUT PARAMETERS

ARCARCPRESSURE DATA

I N C O R P O R A T E DI N C O R P O R A T E D

Stimulation Detail: _____________________________________________________________ __________________________________________________________________________________________________________________________________________________________________________________________________________________________________________ If Hydraulically fractured: Pre-Frac Permeability, (k)...................................................__________ md COMPLETION TYPE Vertical / Horizontal Perforated / Open Hole / Slotted Liner / Gravel Pack / Limited Entry Horizontal: Lateral Length, (Lw) ...........................................................__________ feet Penetration Ratio, (Zwd) ....................................................__________ ratio Kick-off Depth......................................................................__________ ft MD / TVD 90 Deg Depth ........................................................................__________ ft MD ................................................................................................__________ ft TVD Total Depth ...........................................................................__________ ft MD ................................................................................................__________ ft TVD General known or suspected information about well such as a naturally fractured system, partial penetration into zone, fault(s), water drive or gas cap, waterflood, layering, etc... : ____________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________ Several of the above parameters are typically used with various correlations to calculate fluid and rock properties required for a pressure transient analysis. If available, please supply the actual values of these properties for current reservoir conditions or attach the complete PVT analysis results. Current Reservoir Conditions: Pressure: psia Temperature: o F Bo .......... RB/STB Bw........... RB/STB Bg .............. ft3/scf llo ........... cp llw .......... cp llg .............. cp co ........... psi-1 cw........... psi-1 cg .............. psi-1 cf ............ psi-1

Establishing Design Criteria for Pressure Buildup Tests Scott M. Frailey, Texas Tech University Aaron E. Pierce, Aaron E. Pierce & Associates Gary E. Crawford, BP Exploration (Houston), Inc. Abstract The designs of pressure buildup tests are of equal importance to the analysis of the measured rate, pressure, and time data. Buildup analysis techniques are the focus of many texts, journal articles, and short courses, while discussions of the design of the tests are minimal. Many tests are unsuccessful as a result of poor or little design effort and inadequate instructions concerning field data acquisition. An effective design not only maximizes the chances of a successful test, but also eliminates unnecessary testing. For example, a design recommendation may be not to conduct the test because the results cannot meet the desired objectives. This paper discusses criteria vital to an effective buildup design to insure the successful measurement of rate and pressure data. Factors which must be considered include: identifying test objectives, establishing the optimal rate and duration of the drawdown period, and determining the length of the shut-in period. This paper was presented at the Forty-First Annual Southwestern Petroleum Short Course held at Texas Tech University, Lubbock, Texas, April 20-21, 1994.

SPE 39773

Errors in Input Data and the Effect on Well-Test Interpretation Results J. P. Spivey, SPE, S.A. Holditch & Associates, Inc. D.A., Pursell, SPE, S.A. Holditch & Associates, Inc. Abstract Parameter estimation is one of the two principal functions of well test interpretation. Accurate parameter estimation depends on several factors, including correct reservoir model selection, sufficient test data within the flow regime(s) of interest, and accurate input data. The focus of this paper is the effects of errors in input data such as net pay, porosity, viscosity, formation volume factor, flow rate, and compressibility on the results of well test interpretation. We consider two of the most commonly used reservoir models – a vertical well with wellbore storage and skin, and a finite-conductivity hydraulically fractured well. For the vertical well case, we allow for the presence of one or more boundaries, and for homogeneous or dual porosity behavior. Many, if not all, of the observations offered in this paper are part of the working knowledge of the full-time well test analyst. However, these observations have not been systematically catalogued and discussed in the literature. The purpose of this paper is to provide just such a systematic catalog and discussion. Copyright 1998, Society of Petroleum Engineers, Inc. This paper was prepared for presentation at the SPE Permian Basin Oil & Gas Recovery Conference Held in Midland, Texas, 23-26 March 1998.

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