grigg proposal doe april 2001baervan.nmt.edu/groups/gas-flooding/media/pdf... · 2006. 9. 19. · 2...

Improving CO2 Efficiency for Recovering Oil in Heterogeneous Reservoirs

NMIMT/PRRC (R.B. Grigg, Application # 1022) 4/11/01 DE-PS26-01NT41048

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B. TABLE OF CONTENTS

A. TITLE PAGE ............................................................................................................................ 1

B. TABLE OF CONTENTS ........................................................................................................... 2

C. PUBLIC ABSTRACT ................................................................................................................ 4

D. TECHNICAL DISCUSSION..................................................................................................... 5

1. SCIENTIFIC AND TECHNICAL MERIT................................................................................. 5

(1) Proposal Relevance to Area of Interest ............................................................................... 5

(2) Proposed Improvements over Existing Technologies ......................................................... 8

(3) Potential Breakthroughs ...................................................................................................... 8

(4) Scientific and Technical Basis and Merit ............................................................................ 9

A. Foam for Mobility Control and Profile Modification .................................................... 9

B. Injectivity Loss and Related Flow Mechanisms ......................................................... 11

C. Modeling CO2 Flooding Mechanisms ......................................................................... 14

(5) Anticipated Benefits ......................................................................................................... 14

2. TECHNICAL APPROACH AND UNDERSTANDING ......................................................... 16

(1) Statement of Project Objective .......................................................................................... 16

A. Objective ..................................................................................................................... 16

B. Scope of Work............................................................................................................. 16

C. Task to be Performed .................................................................................................. 17

Task 1 Foam for Mobility Control and Profile Modification...................................... 17

Task 2 Injectivity Loss and Related Flow Mechanisms.............................................. 19

Task 3 Modeling CO2 Flooding Mechanisms ............................................................. 22

Task 4 Transfer Technology ....................................................................................... 23



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D. Deliverables .................................................................................................................23

E. Briefing/Technical Presentations ................................................................................ 24

(2) Project Network ................................................................................................................. 25

(3) Project Schedule ................................................................................................................ 26

(4) Staffing Plan ...................................................................................................................... 26

(5) Travel Requirements.......................................................................................................... 26

3. Technical and Management Capabilities .................................................................................. 27

(1) Project Team Credentials, Capability, and Commitment .................................................. 27

(2) Relevant Prior and Current Experience ............................................................................. 28

(3) Organization, Mission Statement, and Commitment......................................................... 29

(4) Facilities and Equipment ................................................................................................... 30

4. References ................................................................................................................................. 31

E. APPENDICES .......................................................................................................................... 36

a. Technical Exceptions and Deviations – none

b. Resumes ............................................................................................................................ 36

c. Letters of Support.............................................................................................................. 45

d. Additional Pertinent Publications – none



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C. PUBLIC ABSTRACT

Of the available advanced oil recovery methods, CO2 injection has the greatest potential for im-

proved oil recovery (IOR) from light oil reservoirs in the United States. Presently eleven states

have CO2 injection projects, with 75% found in west Texas and southeast New Mexico. Almost

universally, CO2 injection has been a technical success when applied, and has proven profitable

in the majority of reported projects. New CO2 projects commence yearly but many reservoirs are

not considered for CO2 flooding because of low fracture pressure, poor injectivity, and/or ex-

treme heterogeneity. The proposed work centers on crucial research to optimize CO2 injection to

maximize domestic hydrocarbon reserves. This project will expand the range of reservoirs ame-

nable to CO2 flooding. The objective of this work is to improve CO2 flood sweep efficiency and

to identify causes and remediation of injectivity reduction due to mobility control, including wa-

ter alternating with gas (WAG) processes.

During the course of our investigations, we will determine parameters and methodologies

that will result in more efficient CO2 flooding in heterogeneous reservoirs. Major areas of inter-

ests are: identifying reservoirs amenable to CO2 flooding, characterizing CO2 foaming agents,

CO2 flooding predictions, and parameters that effect CO2 sweep efficiency, production rate, res-

ervoir retention (sequestration), and injectivity change (also water injectivity changes).

Benefits will include: increasing the range of reservoirs amenable to CO2 flooding, improv-

ing efficiency and lowering cost of CO2 foam systems, improving CO2 flooding predictions, im-

proving sweep efficiency, controlling production timing, and optimizing retention and injectivity

changes.



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D. TECHNICAL DISCUSSION

1. SCIENTIFIC AND TECHNICAL MERIT

(1) Proposal Relevance to Area of Interest

The proposed study, “Improving CO2 Efficiency for Recovering Oil in Heterogeneous Res-

ervoirs,” will encompass goals and objectives of Area of Interest 11, “Reservoir Efficiency Proc-

esses.” The proposal emphasizes laboratory studies with related analytical models for improved

oil recovery (IOR).

In the United States (US), oil that is potentially producible by IOR methods amounts to ap-

proximately 32 billion cubic meters (m3) (200 billion barrels) of the 56 billion m3 (351 billion

barrels) remaining in US oil reserves. Of the available IOR methods, carbon dioxide (CO2) injec-

tion holds the greatest promise for additional oil recovery from light oil reservoirs in the US.

CO2 flooding is a proven IOR technology for IOR that extends the life of mature oilfields. It is

almost universally a technical success when applied, and is reported to be profitable in a vast ma-

jority of projects.1,2 Even during the 1998–1999 oil price collapse, most CO2 recovery projects

continued, although a number acquired new operators.

New CO2 projects are being initiated and new sources of CO2 are being identified every year.

The Permian Basin of west Texas and southeast New Mexico is the oil province most active in

CO2 usage, yielding about 80% of the oil produced by CO2 injection in the US—29,000 cubic

meters per day (m3/d) (180,000 barrels of oil per day (BOPD)). Additionally, there are at least

nine other states that have active or planned CO2 projects: California, Colorado, Kansas, Louisi-

ana, Michigan, Mississippi, Oklahoma, Utah, and Wyoming. With increasing natural and man-

made (waste industrial products) CO2 sources, there will be continuing incentive to increase the

use of CO2 for economic benefits.



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The use of CO2 is not foolproof, as many CO2 floods display inadequate injectivity and/or

poor sweep efficiency. Many reservoirs have not been considered for CO2 flooding because of

low fracture pressure, poor injectivity, and/or extreme heterogeneity. The CO2 floods that have

not been economic successes are usually the results of poorly understood mechanisms of sweep

and displacement efficiency in heterogeneous reservoirs. Factors that increase sweep efficiency

also create resistance to flow and limit injectivity. A better understanding of these mechanisms

will lead to improved project economics, or prevent implementation of an uneconomic project.

The proposed study will improve sweep efficiency through examining mobility control while

minimizing the effects of injectivity decreases. Sweep efficiency is adversely affected by strati-

fied reservoirs having high permeability contrast, of which highly conductive fracture is an ex-

treme example. Although our purpose is not to judge the economics of systems, we will concen-

trate on products and methods that have a realistic potential for economic viability.

Because of the importance of CO2 flooding to future oil recovery in the US, the New Mexico

Petroleum Recovery Research Center (PRRC), a research division of the New Mexico Institute

of Mining and Technology (NMIMT), has maintained a vigorous CO2 flooding research program

for over two decades. The Department of Energy (DOE)/National Petroleum Technology Office

(NPTO), the State of New Mexico, and a consortium of oil companies have supported this re-

search since its inception.

The Gas Flooding Processes and Flow Heterogeneities Section (GFPFH) of the PRRC is

pleased to offer this proposal to the DOE/National Energy Technology Laboratory (NETL). The

proposal describes new research in CO2 flooding as well as the extension of previous work for

understanding and improving CO2 and other gas injection processes for IOR in heterogeneous

reservoirs. It is more crucial than ever that research organizations and the DOE work with US



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operators on IOR techniques for optimizing CO2 injection, in order to maximize domestic hy-

drocarbon reserves. The successful completion of this project will result in the expansion of the

range of reservoirs amenable to CO2 flooding. The proposed research is a direct result of the

GFPFH group’s interaction with CO2 operators—it focuses on solving the most important ongo-

ing technical challenges in CO2 flooding. Thus, developments from our present and future pro-

jects are an asset to the economic and strategic future of the US.

Results of previous work have been described in reports to DOE/NPTO, in papers presented

to the Society of Petroleum Engineers (SPE), and in other conference proceedings and refereed

publications. A comprehensive review of recent accomplishments can be obtained from DOE

Annual and Final Project Reports3 and in nearly 40 publications on specific topics, including:

injectivity,2,4,5 phase behavior and multiphase flow,6-9 pressure effects,10 mobility control and

foam properties,11-14 selective mobility reduction (SMR),15-17 foam mechanisms,18 mixed surfac-

tants and sacrificial agents,19-22 gravity drainage,23 imbibition,24-26 interfacial tension (IFT),12,27,28

field foam modeling and history matching,29-31 numerical methods,32-35 and CO2 reservoir injec-

tion studies.36-39 Also, during the last five years four CO2-Oil Recovery Forums were organized

by the PRRC and the Petroleum Technology Transfer Council (PTTC). Participants represented

over 40 major and independent oil companies (foreign and domestic) and over 30 service, con-

sulting, and governmental (local, state, tribal, and federal) organizations.

The following sections outline the background, work, and current state-of-the-art research

that will optimize utilization and dramatically extend the practice of CO2 flooding. Areas of in-

terests are: 1) mobility control, 2) understanding and mitigation of reduced injectivity, and 3)

modeling process mechanisms.



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(2) Proposed Improvements over Existing Technologies: Despite favorable characteristics of

CO2 for IOR,40 CO2 floods frequently experience poor sweep efficiency caused by gas fingering

and gravity override, augmented by reservoir heterogeneity,41 and low productivity caused by

lower-than-expected injectivity. Poor sweep efficiency results from a high mobility ratio caused

by the low viscosity of even high density CO2 compared to that of water or oil. The effectiveness

of water injection alternating with gas (WAG), a common process used for mobility control dur-

ing CO2 floods, is reduced by gravity segregation between water and CO2 and amplified by per-

meability differences. Foaming agents introduced in the aqueous phase control mobility. How-

ever, costs incurred by the loss of expensive chemicals to adsorption on reservoir rock often

exclude this potentially beneficial option for many well operators. We will develop systems with

lower concentrations of good foaming agents that will reduce cost. These systems are derived

using a sacrificial agent or a cosurfactant that shows synergistic improvements when mixed with

the good foaming agents.

The WAG process frequently reduces injectivity more than expected and the addition of mo-

bility control agents inherently compounds this problem. Normally, improved mobility ratios

will reduce injectivity, and for this purpose it is critical that we optimize the two effects together.

Improved injectivity will also result from the lower chemical concentrations and through some of

the synergistic improvements using the cosurfactant systems mentioned above. We will examine

and optimize the phenomenon wherein mobility reduction using foam is greater in higher than in

lower permeability regions, or what we referred to as selective mobility reduction (SMR).

(3) Potential Breakthroughs: The following are anticipated results of this project:

• Identification of properties that affect foaming agent adsorption, i.e.: rock type, surfactant

type, surfactant concentration, co-surfactants, and sacrificial agents.



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• Understanding of synergistic effects on foam in dual chemical systems.

• Identification and understanding of fundamentals of systems with varying degrees of SMR.

• Determine parameters that increase injectivity and improve sweep efficiency.

• Understanding of what causes injectivity reduction: contamination, fines migration, perme-

ability changes, stress/pressure gradient, phase behavior, flow rate, etc.

• Development of required models to predict frontal advancing rates of individual components

in mixed chemical systems with adsorption and desorption rates, foam behavior in heteroge-

neous systems, and injectivity.

(4) Scientific and Technical Basis and Merit

A. Foam for Mobility Control and Profile Modification

Direct thickening of CO2 is one method to control mobility but it has proven difficult to formu-

late and, even with recent encouraging results, the combined concentration and chemical cost are

at least three orders of magnitude too high.42 The use of CO2-foam is a more technically ad-

vanced approach to improving CO2 sweep efficiency. Numerous laboratory and field studies

have demonstrated the effectiveness of CO2-foam for mobility control and fluid diversion. Pro-

gress that has been made during the past decade includes:

• Identification of foam strength in high pressure CO2 systems;43

• Identification of properties that affect foaming agent adsorption in a porous medium: rock

type,21,22 surfactant type,43 surfactant concentration,43 and co-surfactants;19

• Identification of co-surfactants and sacrificial agents;20,21

• Effects of heterogeneity with and without capillary contact;13,14,17

• Identification of a number of systems with varying degrees of SMR;28 and

• Development of models to predict reservoir response to the identified foam systems.



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Mobility tests show behavior that reduces CO2 mobility by a greater factor in high perme-

ability zones than in lower permeability zones or selective mobility reduction (SMR). SMR be-

havior has been identified in both small, fairly homogeneous cores16 and larger dual permeability

composite cores having permeability differences of about an order of magnitude.13,17 One foam

systems, 0.25 wt% Chaser CD1045, has been applied successfully in a field pilot project spon-

sored by DOE and a consortium of oil companies in the East Vacuum Grayburg/San Andres

Unit, Lea County, New Mexicio.44 A new mixed surfactant foam system, 0.05 wt% CD1045/0.5

wt% lignosulfonate, has yet to be applied in a field test. However, noticeable experimental bene-

fits of using the mixed surfactant system are:

• Efficiency: About half the injection fluid was required to reach the ultimate oil recovery.

• Injectivity: A lower pressure gradient was required, thus increased injectivity.

• Increased oil saturation tolerance: Earlier production and pressure response measured.

• Lower chemical cost: Though the total surfactant concentration was greater, the use of the

low cost lignosulfonate offers a potential total chemical cost reduction of more than 75%.

Lower surfactant concentrations minimize loses of adsorption and injectivity. Adsorption

was found to be a function of surfactant concentration, co-surfactant or sacrificial agent, and in-

jection sequence for the two rock types tested.21 Results from recent research indicate the poten-

tial of using mixed surfactants at low concentrations to significantly reduce the required amount

of quality foaming agents and the subsequent cost of a foam flood project.22

Mixed surfactant systems containing alpha olefin sulfonate, ethoxylated alcohol sulfate, and

lignosulfonate have been examined.19,22 Some mixed systems demonstrate synergistic behavior,

enhancing mobility reduction over a single component19-22 while maintaining SMR properties.

The mechanisms for this phenomenon are yet to be identified. Also, lignosulfonate was tested as



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a sacrificial agent for CO2-foam flooding with some mixtures reducing adsorption losses of the

quality foaming agent while maintaining or improving the oil production.21 Lower cost mobility

control will be vital to expand CO2 flooding to heterogeneous reservoirs.

Physical mechanisms of foams must be understood in order to predict foam flooding. One

factor affecting foam performance is surfactant propagation rate through the reservoir. It is im-

portant to understand and model the transport behavior of injected, multi-component surfactant

solution in order to achieve accurate field predictions. Preliminary results from testing mixed

surfactant CO2-foam performance in demonstrate a chromatographic effect in a porous media.21

The areas that are targeted in this proposal to improve our capability to predict and design

foam systems that will be used in the field to economically increase oil production are:

• Development of low cost co-surfactant and/or sacrificial agent systems with SMR properties,

• Understanding of what makes a good CO2 foaming agent,

• A method of predicting system parameters,

• Assessment of the potential for using developed systems in fractured reservoirs, and

• Development of field applications.

B. Injectivity Loss and Related Flow Mechanisms

In many reservoirs, injectivity during WAG cycles has been lower than expected. In many cases

the low injectivity rates prolong injection time and play havoc with project economics. There-

fore, a study of injectivity loss is warranted. Early CO2 injection projects displayed a number of

problems including water blocking, corrosion, production concerns, and WAG injectivity losses

(WAGIL).45 Careful planning, good design, and progressive management practices have elimi-

nated or minimized all these ill effects, except WAGIL.45,46

A 1996 PRRC survey of CO2 field projects listed WAGIL as a crucial limiting factor in many



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projects.2 A 1999 forum on WAGIL in San Andres reservoirs47 was attended by representative

from ten oil companies that represented 61% of all US CO2 projects and 85% of the increased oil

production from all US CO2 projects at the time.45 Twelve field projects that exhibited WAGIL

were reviewed. Generally, water injection rates were lower after the switch from CO2 to water,

and persisted longer than accounted for by multiphase flow. In an example, the pre-WAG water

injection rate of 286 m3/d (1800 BPD) was not pressure-limited, while after a couple of WAG

cycles the CO2 and water injection rates were limited by pressure to about 160 and 130 m3/d

(1000 and 800 BPD), respectively. Injectivity loss appears to be common during the water half-

cycle for both low and medium permeability reservoirs and during the CO2 cycle for low perme-

ability reservoirs. With low viscosity and high mobility, one would expect increased CO2 injec-

tion rates. A number of field solutions for improving injectivity have been attempted with mixed

results. Currently, there are no clear explanations of the factors influencing WAGIL, nor meth-

ods available to mitigate this problem.

Laboratory attempts to identify the causes of WAGIL, as described in the literature, have

been marginally successful.49,50 Current research at the PRRC using quarry and field cores is

testing possible mechanisms for injectivity loss. Test show erosion and migration of fines, disso-

lution of rock cement, and chemical deposition cause permeability changes. Back Scanning Elec-

tron Microscope analyses of carbonate samples have revealed extreme dissolution of both ce-

ment and granules during laboratory WAG tests, as well as what appears to be recrystallization a

few inches downstream from the dissolution.

Wellbore oil contamination has been suggested as one possible cause of injectivity reduction.

Both surface and downhole contamination sources are suspect. The solution is simplified when

the contamination results from inadequate surface treatment. However, the treatment of down-



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hole contamination is not straightforward. Low-permeability or noncontinuous layers are poten-

tial contamination sources during a time of pressure loss such as the switchover period between

WAG half-cycles.

Phase behavior and relative permeability interactions should produce at least temporary in-

jectivity loss when switching from one fluid to another during WAG injection. Therefore, in-

teraction between phases on fluid flow throughout the reservoir will be investigated. The long-

term effects of phase behavior and multiphase flow on WAGIL deep in the reservoir have not

been addressed experimentally. These effects are amplified when a third phase is introduced,

such as oil contamination. It is necessary to increase our understanding of multiphase relative

permeability and develop methods to modify relative permeability. A number of parameters that

are believed to affect multiphase flow are: capillary pressure and fluid saturations, permeability,

IFT, pore size, and three-phase flow.51,52

Studies indicate that both high flow rate5,53,55,56 and rock mechanics57,58 have significant ef-

fects on the flow behavior of injection and production fluids. Fluid flow rate is dependent on the

pressure gradient that can limit flow and injection rates. Both fractured and consolidated forma-

tions are thought to be stress-sensitive.53 Near-wellbore regions are expected to have the highest

stress changes from large pressure gradients. Liquid dropout caused by severe pressure gradients

near the wellbore can potentially affect production, where CO2 changes from a high-density fluid

with a high-solubility parameter to a low-density gas with a low solubility parameter.54 Liquid

dropout at the producer restricts production rates and decreases the reservoir pressure gradient,

thus reducing injectivity. Change in stress and flow rate results in changes in pressure gradient

and phase behavior, in turn effecting additional changes in stress, relative permeability, and flow

rate.



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There are a number of parameters affecting fluid flow that are severe near the production

well. At the higher-pressure injector, the effects should not be as significant, but could still be a

problem. These parameters include:

• CO2 volume increasing as pressure decreases, accelerating the flow rate.

• CO2 solubility parameter reduction, resulting in hydrocarbon and water dropouts and flow

restrictions.

• Higher than expected pressure gradient, resulting in higher flow rates that in turn promote

even higher-pressure gradients.

C. Modeling CO2 Flooding Mechanisms

An efficient evaluation of reservoirs as potential candidates for IOR by CO2 injection requires a

fundamental understanding of CO2 flooding mechanisms under various conditions that can be

incorporated into field models. Even though studies19,29,30 at the PRRC have shown very promis-

ing results in simulating CO2-foam, some mechanisms and parameters affecting CO2 flooding

behavior remain to be defined. We have been working on modeling these mechanisms and their

effects on CO2 flooding behavior using an existing simulator MASTER (Miscible Applied Simu-

lation Techniques for Energy Recovery), supplied by DOE. MASTER has been modified exten-

sively at PRRC to include foam features developed here,30 horizontal wells, and other mecha-

nisms.29 Parameters to be modeled include:

• Frontal advancing rates of each component of a mixed chemical system,

• Adsorption and desorption rates for each foam component,

• Foam fracture behavior, and

• Injectivity

(5) Anticipated Benefits: Project results will have immense consequences for the future of IOR.



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Parameters will be determined that will result in more efficient CO2 flooding in heterogeneous

reservoirs and will include the following benefits:

• Extending the life of the petroleum reservoir, maintaining or increasing employment, and in-

creasing oil recovery.

• Expanded range of reservoirs amenable to CO2 flooding, and

• Reduction of chemical cost: optimizing oil saturation tolerance of foam, decreasing primary

foaming agent adsorption, and decreasing required primary foaming agent concentration.

• Improved sweep efficiency using SMR foam to decreased CO2 mobility,

• Delayed production of CO2 and increased retention of CO2 in the reservoir (sequestration),

• Improved injectivity of CO2 and water,

• Improved CO2 flooding predictions, and

• Decrease in the mobility of CO2 during the alternate injection of brine and CO2.

CO2 flooding potential has been demonstrated in the US, particularly in the Permian Basin of

west Texas and southeast New Mexico. Much of the research on CO2 flooding methods can be

applied to other gas flooding processes, such as hydrocarbon injection projects. Today over

48,000 m3/d (300,000 BOPD) are being produced by gas injection in the US; 60% of this oil or

~10.5 million m3 (66 million barrels) of oil per year, is from CO2 injection. Out of the 56 billion

m3 (351 billion) remaining US oil reserves, this amount barely scratches the surface of this re-

source. The potential recovery is at least one order of magnitude greater.

The current US oil production would be 48,000 m3/d (180,000 BOPD) less if it were not for

the advanced methods developed through gas injection research at institutions such as the PRRC.

Many of these producing reservoirs would have been abandoned using conventional recovery

methods alone. The profitable uses of CO2 injection will be improved as a result of this study. As



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more domestic reservoirs approach conventional economic limits, the need for advanced recov-

ery technologies such as CO2 flooding will increase. As methods of CO2 use improve, more CO2

will become available through the development of new sources, the capture of industrial waste,

and expanded transportation systems. The areas of interest in this proposal concentrate on the

ways of improving the industry’s understanding of the processes and mechanics of CO2 flooding.

CO2 injection increases oil production in the US by 29,000 m3/d (180,000 BOPD), which at

$190 per m3 ($30 per barrel) is almost $2 billion less in imports each year, as well as providing a

significant number of domestic jobs. Moderately successful future research will maintain current

production rates, whereas good to excellent success in research, expanding market availability of

CO2 and/or sequestration incentives, has the potential of increasing CO2 use in IOR by several

fold. The potential is easily several billion dollars each year in reduced foreign imports and

maximization of US resources.

2. TECHNICAL APPROACH AND UNDERSTANDING

(1) Statement of Project Objectives for

“Improving CO2 Efficiency for Recovering Oil in Heterogeneous Reservoirs”

A. OBJECTIVE: The objective of this study is to increase effectiveness and viability of CO2

mobility control using foaming systems, to minimize injectivity losses, and to model these

mechanisms. This will include an improved understanding of foaming agents and injectivity.

B. SCOPE OF WORK: Most of the study will be laboratory-related with supporting modeling

and field liaison projects. The foam study will include: 1) systematic evaluation of hybrid foam

systems (synergetic effects of multi-component systems), 2) evaluation of low-cost/higher per-

formance systems, 3) studies investigating how SMR works, 4) development of transport and

adsorption models, and 5) evaluation of mobility improvements for reservoirs with severe het-



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erogeneities. The injectivity and related flow mechanisms study will: 1) review field data to as-

sess extent and causes of WAGIL, 2) conduct laboratory tests to identify mechanisms, and 3)

perform tests to determine the effects of permeability alteration, contamination, relative perme-

ability, saturation, flow rate, stress, and other identified parameters. Modeling will include: 1)

sweep mechanisms, 2) SMR behavior, 3) hybrid foam flow adsorption and transport, and 4) in-

jectivity. Finally, optimizing the benefits of using public funds will be achieved by transferring

to the public information of the discoveries and developments of this project.

C. TASKS TO BE PERFORMED:

Task 1: Foam for Mobility Control and Profile Modification

Laboratory work and analysis will be performed to explore the applicability of hybrid foam sys-

tems (HFS) in heterogeneous reservoirs. The HFS include mixed surfactant systems and surfac-

tant/sacrificial agent systems. This research will include laboratory tests, mechanistic models,

and guidelines for reservoir scale simulations.

Subtask 1.1 Evaluation of SMR Using HFS: Commercially available surfactants will be evalu-

ated in HFS (mixed surfactant and sacrificial agents) for effects of pressure, temperature, brine

composition, and oil on foam durability and IFT. Sacrificial agent candidates must be potentially

lower in cost than primary foaming agents. They will include low cost components such as lig-

nosulfonates (by-products of the paper industry) and polymers such as polyacrylamide and xan-

than gum. Based on the foam durability/IFT evaluation, the more promising systems will be

tested for foam mobility and SMR in a coaxial dual-permeability, composite core system. Oil

recovery efficiency will be correlated with the foam properties to:

• Establish a database of foam performance for HFS for several rock types.

• Obtain an optimum formula of HFS for possible application conditions.



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• Provide information about the synergetic mechanism of HFS.

Subtask 1.2 Determine How SMR Works: SMR has a profound effect on sweep efficiency and

has been observed over a wide range of permeabilities,26 but apparently disappears at very low

and very high permeabilities. It is postulated that capillary pressure influences the occurrence of

SMR. This will be examined by conducting tests over an appropriate range of permeabilities.

The data will be used to test both existing and new SMR models to:

• Determine the mechanism that results in SMR variances from surfactant to surfactant.

• Identify the permeability range of SMR and test the theory of capillary effects.

• Identify chemical structure effects of the surfactant on SMR.

Subtask 1.3 Develop Transport and Adsorption Models: A circulation method will be used to

assess the effect of injection schemes on surfactant adsorption in mixed surfactant systems. The

rate of propagation (chromatographic effects) will be determined by tracking injection and efflu-

ent surfactant concentrations. The results will be used to determine model parameters for trans-

port and adsorption of multiple components in the porous media. The objectives are to:

• Determine adsorption and propagation isotherms.

• Establish mixed surfactant adsorption effects when other absorbable species are present.

• Identify effects of chemical structure and rock type.

Subtask 1.4 Evaluate Mobility Improvements in Heterogeneous Reservoirs: Core systems

will be constructed by inducing a known large permeability contrast in a core parallel to the flow

direction. The following will be considered:

• Foam rheology in fracture and matrix to characterize flow parameters required for modeling.

• Pressure gradients before and after foam and water, oil, and gas production.

• Fundamental study of a suitable HFS for oil recovery evaluation.



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Task 2: Injectivity and Related Flow Mechanisms

Fluid injection that is consistently lower than expected results in extended time needed to

achieve the required injection volumes and subsequent production rates, as well as ultimately

adversely affecting economics. In this area of interest the goal will be to understand WAGIL

mechanisms and their effect on a specific reservoir type. Investigations of mechanisms of injec-

tivity loss and possible prevention or remediation strategies will be conducted in the laboratory.

Subtask 2.1 Perform an Industrial Injectivity Review: Participants from 10 oil companies at-

tending the June 1999 forum on WAGIL agreed that collaboration and data sharing with PRRC

would be advantageous to the industry. The causes of and remedies for unacceptable injectivity

losses are unknown. Because of the incomplete understanding of WAGIL mechanisms, we pro-

pose to perform a review of the mechanisms and prevention or remediation techniques. This will

not be a literature review, (this has been completed4) but an on-site review of field projects. The

study will include consultations with engineers and geologists working on WAG floods. During

March 2001 we visited with engineers at Texaco, Kinder Morgan, Occidental Permian, Amerada

Hess, Transpetco, ExxonMobil, and First Permian. We outlined plans to examine field data to

identify mobility control problems and injectivity reduction that were well received, so we ex-

pect full cooperation, pending managerial approval (see appendix c for example support letters.)

Initially, we expect to concentrate on a single reservoir type, probably Permian Basin San Andres

reservoirs and will be expanded if time permits. This review will provide:

• In-depth understanding of one reservoir type that should translate to other reservoirs.

• Development of a standard format to correlated with existing reservoir characterization.

• Insight into WAGIL mechanisms, frequency of occurrence, and possible prevention and/or

remediation.



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To date, several possible WAGIL mechanisms have been identified: permeability/saturation

relations, contamination, and pressure gradients/stress near the wellbore. If the field review iden-

tifies higher priority mechanisms, the program will be appropriately modified.

Subtask 2.2 WAGIL–Permeability Alterations: Both increased and decreased permeabilities

have been observed in laboratory coreflooding. Causes of permeability decreases include fines

migration, precipitation, and crystallization. Causes of permeability increases include erosion

and dissolution of cement material. The extent to which these changes occur in the reservoir is

uncertain. This work will do the following:

• Establish brine/core compatibility before CO2 is introduced.

• Conduct WAG series and oil displacement tests that represent various field scenarios.

• Postflood analysis of effluent and core material.

• Cores such as those presently being used (San Andres CO2 injection areas) will be tested.

Subtask 2.3 WAGIL–Relative Permeability and Saturation: Relative permeabilities and satu-

ration changes reduce injectivity when the system switches from one injection fluid to another.

The extent to which two- and three-phase relative permeability and phase behavior in the reser-

voir affect injectivity is poorly documented. Each reservoir system has unique oil, water, and

CO2 phase behavior that determines the flow behavior. The pressure-temperature-volume-

composition phase relationships will be used to improve models for reservoir flow behavior.

These phase relationships will also be applied to corefloods to include rock interaction using

quarry and reservoir core.

Quarried and reservoir core will be used in this study. Quarried materials include Berea sand-

stone, Indiana limestone, and Coconino sandstone. Berea sandstone and Indiana limestone have

been widely used in the laboratory; both are sensitive to brine composition and CO2,22,24,31-33 re-



21

sulting in porosity and permeability alterations.43 Coconino sandstone is a clean quartz sand-

stone (quartz arenite) with a silica cement and permeability range similar to San Andres dolo-

mites. It has not yet been used in PRRC laboratory tests, but is expected to be stable in a CO2-

brine environment.

The introduction of a third (oil) phase into the core complicates the permeability response of

the core. Of the infinite saturation scenarios involving brine, oil, and CO2 in the core, our interest

lies primarily in the cases where residual brine or CO2 saturations have been established by

WAG and a relatively small amount of oil is then introduced, simulating oil contamination that

occurs during the switchover from one injection phase to another. Another scenario that will be

examined is coinjection of oil with brine and/or CO2. This allows flow in a short core to model

the three-phase pressure transient properties of the mixing zone that occurs near-wellbore and

propagates into the field.

Potential additives will be investigated with and without oil present that may be included in

the initial stage of the water or CO2 half-cycle to decrease the amplitude of the multiphase pres-

sure transient. The properties of a successful additive will be defined. High precision saturations

will be required, so some of the tests will have high-resolution saturation measurements per-

formed on them using image scanning equipment at a core service laboratory.

Subtask 2.4 WAGIL – Flow Rate and Stress Sensitivity: Most formations are affected by

stress, especially in regions of high and varying pressure gradients. Near-wellbore regions,

whether at the injector or producer, exhibit a stress gradient. Both flow rate and stress affect flow

behavior. The effects of pressure gradients on phase behavior and subsequent pressure gradient

increase near the wellbore will be examined. Tests at the PRRC show that stress and flow rate

both significantly affect flow behavior. Earlier tests recorded the effect of having a second phase



22

present.13 Flow and phase behavior tests on systems with CO2 will determine the following:

• CO2 flow acceleration with decreasing pressure.

• CO2 solubility changes, hydrocarbon and water dropout, and flow restrictions.

• Effect of pressure gradient on stress and flow.

Task 3: Modeling CO2 Flooding Mechanisms

Concepts and methods developed from the other tasks will be modeled and incorporated into res-

ervoir simulators for predictions of reservoir performance.

Subtask 3.1 Model Hybrid Foam flow Behavior: To provide a better understanding of the

transport mechanisms of the mixed surfactants affecting CO2-foam behavior, propagation and

adsorption mechanisms of the mixed surfactants in reservoir rock, models for each mixture will

be developed. MASTER has been modified extensively at PRRC to include foam features.43 Cur-

rently, MASTER can only track one surfactant in the water phase. In order to track mixed surfac-

tants in the water phase, MASTER will have models added:

• To incorporate a propagation (chromatographic) model for mixed surfactants,

• To model adsorption of mixed surfactants.

• To add foam features for mixed surfactants.

• The new and existing foam features in MASTER will be validated and calibrated using exist-

ing and new laboratory data that will be applicable to other simulators.

Subtask 3.2 Develop Foam Models in Heterogeneous Formations: After reviewing experi-

mental results we will model the effects of foam on flow in fractures. This will probably require

a dual porosity model that can have both the fracture and matrix porous systems altered by foam

injection.

Subtask 3.3 Model SMR Behavior: SMR foam behavior has been incorporated into MASTER,



23

but has not been tested for multicomponent systems. A feature will be added to MASTER that

will allow several chemicals to advance at different rates (chromatographic effect) in the

reservoir. This will allow incorporation of the flow behavior, adsorption, and desorption of

several surfactants and/or sacrificial agents.

Task 4: Transfer Technology

The PRRC has long been aggressive in technology transfer. We will continue to bring forward

the results of our research on IOR topics of interest to oil and gas producers. As in the past, these

will include Quarterly, Annual, and Final Project Reports and papers on specific topics published

and/or presented at international science and engineering conferences. We will ensure a prompt

and efficient transfer to the end users of technology developed during this project. This transfer

of technology includes the integration of this information with similar developments in the petro-

leum field.

D. DELIVERABLES

Task 1.0 Foam for Mobility Control and Profile Modification

• HFS performance database for a variety of rock systems

• Adsorption, transport, and SMR mechanistic assessment of mixed surfactant systems.

• Laboratory results showing rheological properties of foam in heterogeneous systems.

• Laboratory results demonstrating CO2-foam oil recovery.

Task 2.0 Injectivity and Related Flow Mechanisms

• Understanding of causes and extent of WAGIL.

• Analysis of permeability alterations due to brine, oil, and/or CO2.

• Results of multiphase flow effects in reservoir core.

• Demonstration of the effects of flow rate and stress conditions on injectivity.



24

• Strategies for prevention and/or remediation of WAGIL.

Task 3.0 Modeling CO2 Flooding Mechanisms

• Development of a mixed surfactant-SMR-foam model.

• Identification of the requirements for a stress sensitivity foam model.

• Development of a mathematical transport model for a mixed surfactant system.

• Foam in heterogeneous reservoirs.

Task 4.0 Technology Transfer

• Quarterly, Annual, and Final Technical Progress Reports; Federal Assistance Man-

agement Summary and Federal Assistance Program/Project Reports.

• Publication by professional organizations and in refereed journals.

• Workshops, forums, and website presentations.

E. BRIEFING/TECHNICAL PRESENTATIONS

• A briefing will be prepared and presented each year to the COR at the COR’s facility located

in Pittsburgh, PA or Morgantown, WV to cover technical plans, progress, and results.

• Technical results will be prepared and presented for technology transfer and critique at least

yearly to the project Industrial Advisory Committee.

• Papers will be prepared and presented at various SPE annual and topical meetings; other

similar relevant conferences, forums, and symposia; and when appropriate, published in refe-

reed journals.

• Other necessary trips include visits to petroleum production companies that presently have or

have had CO2 injection projects. These trips will be used to obtain field data necessary to

analyze field injectivity and possible causes and remediation of reduced injectivity.



25

(2) Project Network: No task or subtask is totally dependent on any other task or subtask.

Even when some dependence exists such as modeling work on laboratory tests and injectivity

tests related to the review of injectivity losses in the field, baseline work can be done in advance.

The diagram below shows the project flow paths and interrelationships.

SMR foam modeling

Assessment of SMR properties

Evaluation of hybrid/mixed surfactants

Adsorption/transport effect

Foam rheology and test in heterogeneous cores

HFS adsorption/propagation modeling

Technology transfer

Permeability injectivity alteration modeling

Injectivity review

Injectivity laboratory test

Remediation tests



26

(3) Project Schedule and Major Milestones -Time Months - 0 6 12 18 24 30 36 Task 1. Foam for mobility control and profile modification

1. Assessment of SMR properties 2. Evaluation of hybrid/mixed surfactants: cost, SMR, adsorp-

tion, and oil resistance.

3. Adsorption and transport tests and models 4. Foam rheology and tests in heterogeneous cores

Task 2. Injectivity and related flow mechanisms 1. Injectivity review 2. Permeability alterations, stress, flow rate, 3. Stress and flow rate 4. Multiphase flow and phase behavior 5. Foam and WAGIL remediation tests

Task 3. Modeling improved sweep mechanisms 1. SMR foam 2. Hybrid/mixed surfactant foam/adsorption/propagation 3. Permeability/injectivity alteration

Task 4. Technology transfer Publications, presentations, and reports

(4) Staffing Plan

First Year by Task Second Year by Task Third Year by Task Name Hrs/yr 1 2 3 4 1 2 3 4 1 2 3 4 Reid Grigg 400 620 200 444 620 400 200 444 620 400 200 444 Robert Svec 280 1200 280 320 480 1000 280 320 480 1000 280 320 Res. Assistant 450 200 230 160 800 300 660 320 800 300 660 320 Grad. Stud. A 880 160 880 160 880 160 Grad. Stud. B 880 160 880 160 880 160 Grad. Stud. C 880 160 880 160 880 160 Totals 2010 2900 1590 1404 2780 2580 2020 1564 2780 2580 2020 1564

(5) Travel Requirements – location, purpose, and (number of trips/people per trip) – Many

meeting locations are to be determined; thus those listed are feasible or probable sites.

• Midland: data gathering (8/1), advisory committee (2/3), and technical meetings (3/2).

• Houston: data gathering (4/1) and advisory committee (1/2).

• Dallas: data gathering (3/1), and technical meetings (3/2).



27

• Tulsa: IOR meetings (2/2or3).

• Pittsburgh/Morgantown: COR presentation (3/1).

3. TECHNICAL AND MANAGEMENT CAPABILITIES

(1) Project Team Credentials, Capability, and Commitment

Dr. Reid Grigg, Project Director and Principal Investigator, is a Senior Engineer and Section

Head at the PRRC and adjunct professor of Petroleum and Chemical Engineering at NMIMT. He

reports to Dr. Robert L. Lee, director of the PRRC, who reports directly to NMIMT President,

Dr. Daniel López. Members of the Gas Flooding Processes and Flow Heterogeneity Section will

be significant contributors to this project. These will include two Research Associates, one Con-

sultant, and three graduate students.

Dr. Reid Grigg (Ph.D. in Chemistry, Senior Engineer at the PRRC, Project Director and

Principal Investigator for this project) has over 20 years’ experience in reservoir fluid phase be-

havior, fluid properties, and fluid flow in porous media, including more than 18 years in miscible

CO2 flooding research. Dr. Grigg joined the PRRC in 1992 as Section Head. As Principal In-

vestigator he will assign tasks according to the appropriate level of effort required. Supervision

of work will be carried out on a day-to-day basis with progress reviewed monthly (or as needed)

at internal project meetings. Technical progress reports will be provided quarterly, annually, and

at the conclusion of the project. At least a yearly advisory meeting will be held to review pro-

gress and future direction with industry supporters.

Mr. Robert Svec (MS in Geophysics) has been associated with our CO2 project since joining

the PRRC in 1995. He has exceptional talents in experimental design and construction of high-

pressure, high-temperature apparatus, characterization and preparation of core, and log

interpretation.



28

Research Associate (position to be filled) will have expertise in as many of the following ar-

eas as possible: high-pressure, high-temperature flow experiments, gas injection processes, sur-

factant chemistry, relative permeability determination, and modeling.

F. David Martin, Manager and Chief Operating Officer of Strategic Technology Resources,

L.L.C., will be a consultant to this project. He has contributed to IOR for over thirty years and

has been involved in numerous research and field projects. Mr. Martin will bring his expertise as

a liaison to the petroleum industry and his experience in IOR research.

(2) Relevant Prior and Current Experience

Recent Research Projects in CO2 Flooding Dates

East Vacuum CO2 – Foam Field Pilot, East Vacuum, New Mexico, DOE/NPTO 1989-1995

Improved Efficiency of Miscible CO2, DOE/NPTO 1994-1997

Huff and Puff, Vacuum Field, Texaco, New Mexico, DOE/NPTO 1994-1998

Reservoir Characterization and Evaluation of CO2 in Spraberry, DOE/NPTO 1995-2000

Non-Darcy Flow, Mobil 1995-1999

Feasibility of Gravity Stable CO2 Flood in the Wellman Unit, Wiser Oil, Texas 1996-1997

Improved Efficiency Miscible CO2 Flooding, DOE/NPTO 1997-2000

Feasibility of CO2 Injection in the Teague-Blinebry Unit, POGO, New Mexico 1998-1999

Listed above are research projects that demonstrate some of the experience PRRC has and

our record of achievement in CO2 research. A number of other related research projects by other

research sections at the PRRC are under way or have been completed. These include research in

the areas of reservoir fluid chemistry, water profile modification, reservoir characterization and

modeling, and technology transfer.

The PRRC has conducted research and provided advancements in CO2 flooding for over 20



29

years. We have many achievements in the areas of research and of equipment and software de-

velopment and modification. These have significantly increased our ability to advance in the ar-

eas outlined in this proposal. These can be found in recent publications.2-39

Research consortia are essential to continuing research in nonprofit institutions. The con-

tinuation of this project is contingent upon the continued support of the DOE, the State of New

Mexico, and private industry. We anticipate continued industry participation to further research

in new avenues as the project progresses. To this end, we are dedicated to remaining closely

linked to oil companies pursuing CO2 or gas injection to insure relevance in our research. An In-

dustrial Advisory Committee will be formed to critique and guide the project. This will ensure

work that is timely and pertinent to the improved oil recovery endeavors of the petroleum

industry.

(3) Organization, Mission Statement, and Commitment

The founding charter of the PRRC states that the mission of the PRRC is to: 1) engage in theo-

retical and practical research in the recovery of petroleum, 2) disseminate the knowledge ac-

quired, 3) assist others in their efforts to recover petroleum, 4) perform petroleum or other en-

ergy research as directed by NMIMT’s Board of Regents, and 5) cooperate with other state and

federal agencies in carrying out the work of the Center. Current research at the Center involves

petrophysics and surface chemistry, polymer gels for improved flood performance, reservoir

characterization, gas flooding processes and CO2 mobility control, reservoir simulation, and field

applications.

The PRRC has a proven track record of conducting successful research programs, delivering

specific technology and technology improvements to the industry in the short- and mid-term.

Because of the large future potential of CO2 flooding in New Mexico, a major area of research



30

emphasis at the PRRC has been on improvements in CO2 flooding. The State of New Mexico

and NMIMT continue to support our efforts in CO2 flooding research. This commitment is re-

flected by their willingness to provide matching funds for the project.

(4) Facilities and Equipment

The offices and laboratories at the PRRC in Socorro, NM will be the facilities used for the

proposed work. The PRRC is housed in the John M. Kelly Petroleum Building on the campus of

NMIMT. The laboratories belonging to the Center are modern and well equipped to handle the

diverse research problems involved in oil and gas recovery. There are 20 laboratories (about

20,000 square feet), a core cutting and welding facility, machine shop, woodworking shop, spe-

cially designed chemical storage room, a small library, and meeting and seminar rooms.

The Center is well equipped with standard scientific equipment needed for research on high-

pressure flow in porous media, as well as with equipment designed and constructed at the Center

for specialized and novel measurements. Listed below is some of the GFPFH Section equipment.

In addition to the PRRC facilities, diverse types of analytical equipment are available at the New

Mexico Bureau of Mines and the College Division of NMIMT.

EQUIPMENT LIST

• High-pressure, high-temperature apparatus for determining density, viscosity, and IFT.

• Slim tube systems for determination of minimum miscibility pressure (MMP).

• Windowed PVT cell for determination of phase behavior at reservoir conditions.

• Several systems with air baths, pumps, accumulators, transducers, coreholders, data acquisi-

tion, and effluent metering for reservoir-condition, porous-medium flow studies.

• Apparatus for preparing high-pressure fluids.



31

• Differential refractometer, spectrophotometer, and gas chromatographs for composition

analyses.

• Many Pentium-class PCs with commercial software; e.g. ECLIPSE, GEOGRAPHIX, VIP,

and MASTER.

• Auxiliary equipment; e.g., analytical balances, minipermeameter, and video imaging.

4. REFERENCES

1. Moritis, G.: Oil & Gas Journal, (20 March, 2000) 39-61.

2. Grigg, R.B. and Schechter, D.S.: paper SPE 38849 presented at the 1997 SPE Annual Tech-

nical Conference and Exhibition, San Antonio, TX, Oct. 6-9, 1997.

3. Grigg, R.B., et. al.: US DOE Contract No. DE-FG22-94BC14977, Annual/Final Reports:

(April 1995), (April 1996), (Feb. 1998), (July 1998), (Oct. 1999), and (submitted Jan. 2001).

4. Rogers, J.D. and Grigg, R.B.: paper SPE 59329 presented at the 2000 SPE/DOE IOR Sym-

posium, Tulsa, April 3-5.

5. Grigg, R.B. and Hwang, M.K.: paper SPE 39978 presented at the 1998 SPE Gas Technology

Symposium, Calgary, March 15-18.

6. Grigg, R.B.: paper SPE 28974 presented at the 1995 SPE International Symposium on Oil-

field Chemistry, San Antonio, Feb. 14-17.

7. Siagian, U.W.R. and Grigg, R.B.: paper SPE 39684 presented at the 1998 SPE/DOE Im-

proved Oil Recovery Symposium, Tulsa, April 19-22.

8. Grigg, R.B. and Siagian, U.W.R.: paper SPE 39790 presented at the 1998 SPE Permian Ba-

sin Oil and Gas Recovery Conference, Midland, March 25-27.

9. Chang, S.-H., et. al.: Fuel Science and Technology Intl. (1996) 14(1&2), 179-201.

10. Grigg, R.B., et. al.: SPERE (Aug. 1997) 179.



32

11. Chang, S-H. and Grigg, R.B.: SPERE, 2 (3), June 1999.

12. Tsau, J-S. and Grigg, R.B.: paper SPE 37221 presented at the 1997 International Symposium

on Oilfield Chemistry, Houston, Feb. 18-21.

13. Yaghoobi, H. and Heller, J.P.: paper SPE 35169 presented at the 1996 Permian Basin Oil and

Gas Recovery Conference, Midland, March 27-29.

14. Yaghoobi, H., et. al.: paper SPE 35403 presented at the 1996 SPE/DOE Improved Oil Re-

covery Symposium, Tulsa, April 21-24, 1996.

15. Yaghoobi, H., et. al.: paper SPE 39789 presented at the 1998 SPE Permian Basin Oil and Gas

Recovery Conference, Midland, March 25-27.

16. Tsau, J-S., and Heller, J.P.: paper SPE 35168 presented at the 1996 Permian Basin Oil and


17. Tsau, J-S., et. al.: paper SPE 39677 presented at the 1998 SPE/DOE Improved Oil Recovery

Symposium, Tulsa, April 19-22.

18. Chang, S.-H. and Grigg, R.B.: paper SPE/DOE 35401 presented at the 1996 SPE/DOE Tenth

Improved Oil Recovery Symposium, Tulsa, April 22-24.

19. Tsau, J-S., et. al.: paper SPE 39792 presented at the 1998 SPE Permian Basin Oil and Gas

Recovery Conference, Midland, March 25-27.

20. Tsau, J-S., et. al.: paper SPE 56609 presented at the 1999 SPE Annual Technical Conference

and Exhibition, Houston, Oct. 3-6.

21. Tsau, J-S., et. al.: paper SPE 59365 presented at the 2000 SPE/DOE Improved Oil Recovery


22. Syahputra, A.E., et. al.: paper SPE 59368 presented at the 2000 SPE/DOE Improved Oil Re-

covery Symposium, Tulsa, April 3-5.



33

23. Schechter, D.S. and Guo, B.: paper SPE 35170 presented at the 1996 Improved Oil Recov-

ery Symposium, Tulsa, April 22–24.

24. Li, H., et. al.: paper SPE 64510 presented at the 2000 SPE Asia Pacific Oil and Gas Confer-

ence and Exhibition, Brisbane, October 16-18.

25. Putra, E., et. al.: paper SPE 54336 presented at the 1999 Annual Technical Conference and

Exhibition, Houston, TX, Oct. 3-6.

26. Guo, B, et. al.: paper SPE 39801 presented at the 1998 Permian Basin Oil & Gas Recovery

Conference, Midland, TX, March 25–27.

27. Guo, B., and Schechter, D.S.: paper SPE 37216 presented at the 1997 SPE International

Symposium on Oilfield Chemistry, Houston, Feb. 18-21.

28. Schechter, D.S. and Guo, B.: paper SPE 30785 presented at the 1995 SPE Annual Technical

Conference and Exhibition, Dallas, Oct. 22-25.

29. Chang, S-H. and Grigg, R.B.: paper SPE 39793 presented at the 1998 SPE Permian Basin Oil

and Gas Recovery Conference, Midland, March 25-27.

30. Chang, S-H. and Grigg, R.B.: paper SPE/DOE 35401 presented at the 1996 SPE/DOE Sym-

posium on Improved Oil Recovery, Tulsa, April 21-24.

31. Putra, E. and Schechter, D.S.: paper SPE 54336 presented at the 1999 Asia Pacific Oil and

Gas Conference and Exhibition, Jakarta, Indonesia, April 20-22.

32. Janoski, G., et. al.: SCS High Performance Computing Symposium –HPC 2000, Washington,

D.C, April 16-20, 2000.

33. Sung, A.H., et. al.: Proceedings of the IASTED International Conference on Artificial Intelli-

gence and Soft Computing, Honolulu, August 9-12, 1999.

34. Janoski, G., et. al.: JCIS, Feb. 2000.



34

35. Chang, S-H., et. al.: paper SPE 62617 presented at the 2000 SPE/AAPG Western Regional

Meeting, Long Beach, June 19-23.

36. Schechter, D.S., et. al.: paper SPE 48948 presented at the 1998 SPE Annual Technical Con-

ference and Exhibition, New Orleans, Sep. 27-30.

37. Svec, R. and Grigg, R.B.: paper SCA 99581 presented at the 1999 Society of Core Analysis

Conference, Denver, Aug. 1-4.

38. Schechter, D.S., et. al.: paper SPE 35469 presented at the 1996 Permian Basin Oil & Gas Re-

covery Conference, Midland, March 27–29.

39. Svec, R.K. and Grigg R.B.: paper SPE 59550 to be presented at the 2000 SPE Permian Basin

Oil and Gas Recovery Conference, Midland, March 21-23.

40. Taber, J.J.: In Situ (1990) 14(4), 345-404.

41. Stalkup, F.I.Jr.: Miscible Displacement, SPE Monograph No. 8, New York (1983).

42. Enick, R.M., et. al.: paper SPE 59325 presented at the 2000 SPE/DOE Improved Oil Recov-

ery Symposium, Tulsa, April 3-5.

43. Tsau, J-S. and Heller, J.P.: paper SPE 24013 presented at the 1992 Permian Basin Oil and


44. Martin, F.D., et. al.: SPERE (Nov. 1995) 266.

45. Hadlow, R.E.: paper SPE 24928 presented at the 1992 SPE Annual Technical Conference

and Exhibition, Washington D.C., Oct. 4-7.

46. Gorrell, S.B.: paper SPE 20210 presented at the 1990 SPE/DOE Seventh Symposium on En-

hanced Oil Recovery, Tulsa, April 22-25.

47. “WACO2 Injectivity Loss Forum for San Andres Reservoirs” June 5, 1999, Midland Texas.

48. Moritis, G.: Oil & Gas Journal, (29 April, 1998) 49.



35

49. Prieditis, J., et. al.: paper SPE 22653 presented at the 1991 SPE Annual Technical Confer-

ence and Exhibition, Dallas, Oct. 6-9.

50. Kamath, J., et. al.: paper SPE 39781 presented at the 1998 Permian Basin Oil and Gas Re-

covery Conference, Midland, March 25-27.

51. Blunt, M.J.: paper SPE 56474 presented at the 1999 SPE Annual Technical Conference and

Exhibition, Houston, October 3-6.

52. Sahni, A., et. al.: paper SPE 39655 presented at the 1998 SPE/DOE Improved Oil Recovery


53. Kelly, M., et. al.: paper SPE 38038 presented at the 1997 SPE Asia Pacific Oil and Gas Con-

ference, Kuala Lumpur, April 14-16.

54. Lange, E.A.: paper SPE 35425 presented at the 1996 SPE/DOE Improved Oil Recovery


55. Firoozabadi, A., et. al.: SPERE (May 1995), 149-152.

56. Wong, S.W.: J. Can. Pet. Tech., (Oct.-Dec. 1970) 274-278.

57. Warpinski, N.R., et. al.: paper SPE 22666 presented at the 1991 SPE Annual Technical Con-

ference and Exhibition, Dallas, Oct. 6-9.

58. Walsh, J.B.: Int. J. Rock Mech. Min. Sci & Geomech. Abstr., Vol. 18, 429-435.



36

E. APPENDICES

b. Resumes – Reid B. Grigg, Robert K. Svec, and F. David Martin

REID B. GRIGG

New Mexico Petroleum Recovery Research Center (PRRC) New Mexico Institute of Mining and Technology (NMIMT) 801 Leroy Place, Socorro, New Mexico 87801 Phone: (505) 835-5403 FAX: (505) 835-6031 E-mail: [email protected]

EDUCATION Post-Doctorate (1979-1980): University of Lethbridge, Lethbridge, Alberta, Canada.

Ph.D. in Physical Chemistry (August 1979): Brigham Young University, Provo, UT BS in Chemistry (May 1975): Brigham Young University, Provo, UT. Numerous Short Courses; (each three to ten days in length)

PROFESSIONAL EXPERIENCE 1992-Present: Senior Engineer/Section Head: PRRC. General Interest: Research related to phase behavior of pressurized geological formation flu-ids, fluid properties and flow behavior of high pressure liquids and gases, and high pressure gas flooding processes in porous media. Gas injection for improved oil recovery and greenhouse gas sequestration, reservoir fluid phase behavior, and flow behavior of multi-phase systems such as gas condensate and enhanced oil production mechanisms; their effect on flow in porous media; and improving and understanding mechanisms for improved mobility control. Liquid-Gas Flow: To improve fluid production from hydrocarbon reservoirs, an understand-ing of mobility, relative permeability, and flow patterns is necessary. Work has centered on sys-tems related to effects of injection gas such as CO2, but a project has been done to examine high gas flow rates at near wellbore conditions. Reservoir Simulation: Develop models for simulating improved oil recovery miscible gas injection processes with principal interests on fluid phase behavior and foam mobility modifica-tion mechanisms. Determination of Reservoir Fluid - Injection Gas Phase Behavior: Principal interests have been the phase behavior of pure and impure carbon dioxide gas injection to improve oil recovery and sequester greenhouse gases. Other work interests include hydrocarbon and nitrogen injection gases and gas condensate production. Selective Mobility Reduction: The project is related to improving CO2-foam efficiency by identifying and defining foam systems that not only reduce the mobility, but selectively reduces mobility in higher permeability to a greater extend than in the lower permeability regions of a hydrogenous reservoir. Work includes the determinations of physical properties of surfactant, synergistic effects of mixed surfactant systems, and the determination of sacrificial agents to re-duce the absorption of more expensive surfactants. Laboratory Tests of CO2-Foam in Porous Media: Mechanistic studies to determine optimum surfactant concentration for CO2-foam systems, foam quality, and effects of flow rates. Technology Transfer: A major objective of the PRRC is technology transfer through various publications, presentations, and forums.



37

Adjunct Professor at New Mexico Institute of Mining and Technology: Research tenure was-granted May 1997. My primary function is directing a research group, though every couple of

of years I teach the graduate class, Phase Behavior and Properties of Petroleum Fluids and direct studies on continuing bases with individual students. 1991-92: Director of Reservoir Fluid Technology, Core Laboratories, Dallas, TX Instructional: Taught Reservoir Fluid Phase Behavior inside and outside Core Labs. PVT and Improved Oil Recovery Projects: Supervised and designed special projects, and proposed new or improved services. Projects included identifying causes of asphaltene deposi-tion due to pressure change or solvent injections, developing new procedures for quantitative de-termination of asphaltene precipitation at reservoir conditions, conventional black oil, and gas injection studies for reservoir projects in N. America, S. America, and the Middle East. 1980-91: Senior Research Scientist (1989-91), Senior Research Chemist (1983-89), and Re-search Chemist (1980-83), Conoco Inc., Production Research, Ponca City, OK Researched the technical feasibility of injecting high-pressure gas into several specific oil reservoirs. These included CO2, nitrogen, and enriched hydrocarbon injection gas improved oil recovery projects in North America, Northern Europe, Africa, Middle East, and Southeast Asia. Organized and advised personnel from several research locations (Marshall Labs in Philadelphia, University of Delaware, Dupont Experimental Station in Wilmington, Conoco Research in Ponca City, and Conoco Engineering in Houston) that establishing the feasibility of formulating dense gas viscosifiers. Conceived, designed, and supervised utilization of apparatus to monitor and control temperature and observe phase changes to determine effects of temperature, pressure, and system compositions on gas hydrates formation and dissociation. Various Industrial Consortiums and DOE Review Committees. 1979-80: Research Associate, University of Lethbridge, Lethbridge, Alberta, Canada: Deter-mined and analyzed properties of mixtures of water, clay, hydrocarbons, and surfactant. 1975-79: Research Assistant, Brigham Young University, Provo, UT.: Dissertation Title: “Ther-modynamics of Non-electrolyte Binary Solutions: Excess Volumes, Enthalpies, Gibbs Free En-ergies, and Entropies for Hydrocarbon Mixtures and Excess Volumes for Several Systems Con-taining Carbon Tetrachloride,”

Major Projects: New Mexico Petroleum Recovery Research Center (1992-present) • “Improved Efficiency of Miscible CO2 Floods and Enhanced Prospects for CO2 Flooding

Heterogeneous Reservoirs.” 6/1997-9/2000, Project Manager and Co-PI, DOE project. • “Sequestration of CO2 in a Depleted Oil Reservoir: A Comprehensive Modeling and Site

Monitoring Project.” 7/2000 – 6/2003, subcontract with Los Alamos and Sandia National Laboratories, DOE project.

• “Improved Efficiency of Miscible CO2 Floods and Enhanced Prospects for CO2 Flooding Heterogeneous Reservoirs.” 4/1994-4/1997, Project Manager and Co-PI, DOE project.

• “Near Wellbore Non-Darcy Wet Gas Flow experiments,” PI, Mobil project. • “Reservoir Pressure Reduction and Miscibility Determination for the Wellman Field,” co-PI,

The Wiser Oil Company project. • “CO2 Injection in a Tight Blinebry Reservoir,” co-PI, Arch Petroleum project. • Other PRRC projects in which I am or have been a collaborator:

• Spraberry CO2-Fractured Reservoir DOE Class III Project • East Vacuum Grayburg San Andres CO2-Foam Field Verification • Texaco CO2 Huff-n-Puff Class II Field Project



38

RELEVANT PUBLICATIONS (past ten years) 1. “Modeling and Simulation of the Wafer Non-Darcy Flow Experiments,” paper SPE 68822,

2001 SPE Western Regional Meeting, Bakersfield, 26-30 March. 2. “Experimental Investigation of CO2 Gravity Drainage in a Fractured System,’ paper SPE

64510, 2000 SPE Asia Pacific Oil and Gas Conference and Exhibition, Brisbane, 16-18 Oct. 3. “Use of MASTER Web to Improve History Matching,” paper SPE 62617, 2000 SPE/AAPG

Western Regional Meeting, Long Beach, 19-23 June. 4. “Economic Evaluation of Surfactant Adsorption in CO2 Foam Application,” paper SPE

59365, 2000 SPE/DOE IOR Symposium, Tulsa, 3-5 April. 5. “Laboratory Evaluation of Using Lignosulfonate and Surfactant Mixture in CO2 Flooding,”

paper SPE 59368, 2000 SPE/DOE IOR Symposium, Tulsa, 3-5 April. 6. “A Literature Analysis of the WAG Injectivity Abnormalities in the CO2 Process,” paper

SPE 59329, 2000 SPE/DOE IOR Symposium, Tulsa, 3-5 April. 7. “Reservoir Characterization and Laboratory Studies Assessing Improve Oil Recovery Meth-

ods for the Teague-Blinebry Field” paper SPE 59550, 2000 SPE Permian Basin Oil and Gas Recovery Conference, Midland, 21-23 March.

8. “Application of Fuzzy Control in Reservoir Simulation,” JCIS, Feb. 2000. 9. “Solving Nonlinear Engineering Problems with the Aid of Neural Networks,” 1999 SPIE

Conference on Applications and Science of Neural Networks, Fuzzy Systems, and Evolu-tionary Computation II, SPIE Vol. 3812, Denver, July.

10. “Petroleum Reservoir Simulation with Fuzzy Control,” Proceedings: 1999 Artificial Neural Networks in Engineering Conference (ANNIE ’99), St. Louis, Nov.

11. “Use of Sacrificial Agents in CO2 Foam Flooding Application,” paper SPE 56609, 1999 SPE Annual Technical Conference and Exhibition, Houston, Oct. 3-6.

12. “Applications of Neural Networks in Solving engineering Problems,” Proceedings: 1999 IASTED International Conference on Artificial Intelligence and Soft Computing, Honolulu, Aug. 9-12.

13. “Teague-Blinebry Improved Oil Recovery Feasibility Study,” paper SCA 99581, 1999 Soci-ety of Core Analysts Symposium, Denver, 1-4 Aug.

14. “Wellman Field CO2 Flood: Reservoir Pressure Reduction and Flooding the Water/Oil Tran-sition Zone,” paper SPE 48948, 1998 SPE Annual Technical Conference and Exhibition, New Orleans, Sept. 27-30.

15. “The Extraction of Hydrocarbons from Crude Oil by High Pressure CO2,” paper SPE 39684, 1998 SPE/DOE Symposium on Improved Oil Recovery, Tulsa, 19-22 April.

16. “Effects of Foam Quality and Flow Rate on CO2-Foam Behavior at Reservoir Conditions,” SPE Reservoir Eval. & Eng., Vol. 2, No. 3, June 1999, 248-254 (originally SPE 39679).

17. “Smart Foam to improve Oil Recovery in Heterogeneous Porous Media,” paper SPE 39677, 1998 SPE/DOE Symposium on Improved Oil Recovery, Tulsa, 19-22 April.

18. “History Matching and Modeling the CO2-Foam Pilot Test at EVGSAU,” paper SPE 39793, 1998 SPE Permian Basin Oil and Gas Recovery Conference, Midland, 23-27 March.

19. “Use of Mixed Surfactants to Improve Mobility Control in CO2 Flooding,” paper SPE 39792, 1998 SPE Permian Basin Oil and Gas Recovery Conference, Midland, 23-27 March.

20. “Understanding and Exploiting Four Phase Flow in Low Temperature CO2 Floods,” paper SPE 39790, 1998 SPE Permian Basin Oil and Gas Recovery Conference, Midland, 23-27 March.



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21. “Effect of Foam on CO2 Breakthrough: Is This Favorable to Oil Recovery?” paper SPE 39789, 1998 SPE Permian Basin Oil and Gas Recovery Conference, Midland, 23-27 March.

22. “High Velocity Gas Flow Effects in Porous Gas-Water System,” paper SPE 39978, 1998 SPE Gas Technology Symposium, Calgary, 15-18 March.

23. “State of the Industry in CO2 Floods,” paper SPE 38849, 1997 SPE Annual Technical Con-ference and Exhibition held in San Antonio, 5-8 October.

24. “The Effect of Pressure on Improved Oilflood Recovery From Tertiary Gas Injection,” SPERE (August 1997) 179-187.

25. “Assessment of Foam Properties and Effectiveness in Mobility Reduction for CO2-Foam Floods,” paper SPE 37221, 1997 SPE International Symposium on Oilfield Chemistry, Hous-ton, 18-21 Feb.

26. “Foam Displacement Modeling in CO2 Flooding Processes,” paper SPE 35426, 1996 SPE/DOE IOR Symposium, Tulsa, 21-24 April.

27. “Characterization and Multiphase Equilibrium Prediction of Crude Oil Heavy Components,” Fuel Science and Technology International, (1996) 14(1&2) 179-201.

28. “Dynamic Phase Composition Density, and Viscosity Measurements During CO2 Displace-ment of Reservoir Oil,” paper SPE 28974, SPE International Symposium on Oilfield Chemis-try, San Antonio, 14-17 February 1995.

29. “Effect of Pressure on CO2 Displacements: A Micromodel Visualization Study,” paper SPE 27784, 1994 SPE/DOE IOR Symposium, Tulsa, 17-20 April.

30. “Laboratory Flow Test Used to Determine Reservoir Simulator Foam Parameters for EVGSAU CO2 Foam Pilot,” paper SPE 27675, 1994 SPE Permian Basin Oil and Gas Recov-ery Conference, Midland, 16-18 March 1994.

31. “Oil-Base Mud as a Gas-Hydrates Inhibitor,” SPEDE (March 1992) 32-38.

PROFESSIONAL SOCIETIES AND RELEVANT ACTIVITIES American Chemical Society, SPE (numerous offices, duties, and presentations), Sigma Xi.



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Robert K. Svec New Mexico Petroleum Recovery Research Center (PRRC) New Mexico Institute of Mining and Technology (NMIMT) Socorro, New Mexico 87801 Telephone: (505) 835-5828, Fax: (505) 835-6031, e-mail: [email protected]

EDUCATION M.S Geophysics: NMIMT, Socorro, NM, May 1993.

I.S. title: Bulk and Surface Dielectric Dispersion of Water Ice B.S Physics with electronics: NMIMT, Socorro, NM, Dec. 1988.

PROFESSIONAL EXPERIENCE Oct 1994 – present at the PRRC: Research Geophysicist (Feb. 1999-present), Research Asso-ciate (Jan. 1998 – Feb. 1999), and Technician I & II (Oct. 1994 – Jan 1998). • Reservoir characterization with well log analysis and special core studies. • High-pressure high velocity flow tests on unusual geometry rock samples. • Integration of laboratory core studies (duties as described below) with oil field well log suites

as part of reservoir evaluation study. • Coordination of enhanced oil recovery (EOR) laboratory tasks including: experimental pro-

cedures, data acquisition and analysis, maintenance and calibration of high pressure high temperature equipment and data acquisition systems, safe handling of high pressure gas cyl-inders and laboratory wastes.

• Design and construction of high pressure test systems with data acquisition. • Minipermeameter study of petroleum well cores. Development of fracture study methods. • Purchase of laboratory equipment. • Assist co-workers on other projects and supervise student workers. • Clean up and disposal of mercury and mercurous wastes. May 1993 - June 1994: NMIMT, Research Engineer, Ice Lab, Socorro, NM. • Measurement of ice dielectric parameters as related to atmospheric and polar environmental

processes. • Computer analysis of data using FORTRAN programming and Mathematica 2.0. • Calibration and maintenance of laboratory instrumentation. • Design and construction of laboratory equipment. Aug. 1990 to May 1993: NMIMT, Graduate Assistant, Socorro, NM. • Development and integration of a computer controlled system for measuring the electrical

(dielectric) properties of ice as related to atmospheric and polar environmental processes. • Preparation and presentation of scientific paper to American Geophysical Union Fall Meet-

ing in San Francisco. • Data collection and analysis using FORTRAN, WordPerfect, and Mathematica 2.0. • Design and machining of tools and fixtures in support of lab work. July 31, 1989 to Aug. 1, 1990: Southwest Technology Development Institute, Research Engi-neer, Las Cruces, NM.



41

• Construction of photovoltaic charge controllers for NASA-PSL high altitude circumpolar balloon project.

• Construction of data acquisition systems for Sandia National Labs and Bechtel Industries. • Design and construction of mobile special purpose photovoltaic power systems for US Army

at White Sands Missile Range. • Purchasing of materials for the projects above and supervision of student work on same. • Field test team for evaluation of utility scale photovoltaic array. • Familiarity with stand-alone remote power systems. Aug. 1988 to Dec. 1988: PRRC/NMIMT, Electronics Technician, Socorro, NM. • Design and prototype an optical liquid CO2 interface detector as part of CO2 Mobility study. • Maintenance and repair of high-pressure pumps and transducers.

PAPERS AND PUBLICATIONS • R.K.Svec and R.B. Grigg: “Reservoir Characterization and Laboratory Studies Assessing

Improve Oil Recovery Methods for the Teague-Blinebry Field,” paper SPE 59550, 2000 SPE Permian Basin Oil and Gas Recovery Conference, Midland, 21-23 March.

• R.K. Svec and R.B. Grigg: “Teague-Blinebry Improved Oil Recovery Feasibility Study,” pa-per SCA 99581, 1999 International Symposium of the Society of Core Analysts, Golden, CO, Aug. 1-4.

• R.K. Svec: “Project Report: Teague-Blinebry Reservoir Study Preliminary CO2 Evaluation,” PRRC Report No. 98-31, Aug. 13, 1998.

• G.W. Gross and R.K. Svec. 1997: “Effect of Ammonium on Anion Uptake and Dielectric Relaxation In Laboratory Grown Ice Columns,” J. Phys. Chem., 101, 6282-6284.

• G.W. Gross, R.K. Svec, P.Y. Whung: “Dielectric response of ice grown from dilute sulfate solutions,” Antarctic Journal of the United States, 1994 29(5), 75-76.

• R.K. Svec, et. al.: “Dielectric response of ice grown from dilute sulfate solutions, measured with linear blocking layers,” paper presented at the Fall Meeting, American Geophysical Un-ion, San Francisco, Dec. 6, 1993.

• R.K. Svec and G.W. Gross: “Dielectric spectroscopy of ice with blocking layers,” paper pre-sented at the Fall Meeting, American Geophysical Union, San Francisco, CA, Dec. 7, 1992.

S KI L L S • Experience in MS-DOS, Windows, FORTRAN, BASIC, Lotus 123, Mathematica, PSI-

PLOT, WordPerfect, MS-WORD, and network software. Trouble-shooting of PC systems. • Use of EG&G 1422 shallow exploration seismograph, gravity meter, proton precession mag-

netometer, and methods for electrical resistivity and electromagnetic exploration. • Use of spectrum analyzer, 3-phase power analyzer, oscilloscope, multimeter, soldering and

wire-wrap. • Instrumentation trouble-shooting. • Experience in clean up and disposal of mercury and mercurous waste, personal protective

procedures (gloves, suit, respirator), and management of laboratory chemicals and wastes. • Working knowledge of technical and architectural drawing. • Familiarity with machining techniques (mill and lathe), arc welding, and cutting torch. • Has worked in confined spaces, elevated temperature systems, and using protective gear.



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F. DAVID MARTIN

BUSINESS ADDRESS: EDUCATION: 8620 Beverly Hills Ave NE BS Chemical Engineering, Texas Technological College Albuquerque, New Mexico 87122 MS Petr. Engineering, NM Inst. of Mining & Technology (505) 822-0937

PROFESSIONAL EXPERIENCE: April 1996 to Present: STRATEGIC TECHNOLOGY RESOURCES, L.L.C. Title: Manager and Chief Operating Officer

As manager of a virtual company, demonstrated the use of the Internet-based information superhighway concept to provide advanced technology to U.S. oil and gas companies, especially independent producers. Assembles and coordinates activities of virtual project teams in areas of reservoir characterization and reservoir management, distributed access to advanced reservoir management tools, and expert advisory systems.

April 1996 to Present: DAVE MARTIN AND ASSOCIATES, INC., Title: Vice President Serves as Principal Investigator of reservoir modeling and simulation activities for a DOE

Class III project operated by an independent producer in New Mexico. Supervises a multi-disciplinary team and assists in project coordination and management. Prepares progress reports and technical papers on project results, and delivers presentations at technical meetings and at project workshops. Investigated the feasibility of both lean gas injection and carbon dioxide flooding.

November 1976 to March 1996: NEW MEXICO INSTITUTE OF MINING & TECHNOL-OGY, Positions: Director, New Mexico Petroleum Recovery Research Center, (Mar. 1987-Mar. 1996); Head, Improved Waterflooding and Chemical Flooding Methods, (Nov. 1976-Mar. 1987) As Director, supervised a research division with a $2.8 million annual budget that em-ployed more than 50 scientists engineers, technicians, and administrative personnel, and that supports additional off-campus personnel. Duties included planning and budgeting as well as management and operation of research and development programs and facilities in exploration, drilling, production, and environmental aspects of oil and gas recovery. Supervised laboratory and field projects that involved improving conventional oil and gas recovery, enhanced oil re-covery processes, oilfield waste management problems, and technology transfer. Developed the concept and supervised the implementation of the Gas and Oil Technology Exchange and Communication Highway (GO-TECH), the first Website developed for the petro-leum industry. Served as Director for the Southwest Region of the Petroleum Technology Trans-fer Council. Principal Investigator/Project Manager of DOE-sponsored projects “Field Verification of CO2-Foam,” “Integration of Advanced Geoscience and Engineering Techniques to Quantify In-terwell Heterogeneity in Reservoir Models,” “Improved Efficiency of Miscible CO2 Floods and Enhanced Prospects for CO2 Flooding Heterogeneous Reservoirs,” and “Development of Im-proved Mobility Control Agents for Surfactant/Polymer Flooding.” Principal Investigator on the following State-sponsored field projects: “Field Test of Carbon Dioxide Flooding, Loco Hills Field,” “Steam Flood Pilot in the O'Connell Ranch Field,” “Improvement of Water Injectivity in the Hobbs (Grayburg-San Andres) Field,” “Large-Scale Stimulation of a Low-Permeability, Permo Pennsylvanian, Gas Reservoir,” “Steam Flood Pilots in the O'Connell Ranch Field and



43

T-4 Ranch Field,” “Development of a Petroleum Resource Center and Electronic Information System,” and “Reservoir Management Applications to New Mexico Oil Reservoirs.”

November 1961 to November 1976: CALGON CORPORATION: Positions: Group Leader,

Oilfield Research, Pittsburgh, PA (Mar. 1974-Nov. 1976); Research Associate, Oilfield Re-search, (Sept. 1971-Feb. 1974); Petroleum Industry Specialist, Midland, TX, (Aug. 1969-Sept. 1971), Los Angeles, CA, (Sept. 1967-Aug. 1969); Bradford Laboratories Division, Abilene, TX, District Manager (1964-1967), Field Engineer, (Nov. 1961- Aug. 1967).

Supervised research in the areas of polymer flooding, micellar flooding, friction reduc-tion, oilfield cement additives, clay stabilization, and production chemicals for the oil industry. Evaluated polymers and surfactants for enhanced oil recovery applications. Developed chemicals for corrosion control, scale inhibition, and microbial control in oil production and waterflood projects. Designed several waterflood projects. Designed, implemented and monitored polymer-augmented waterflood projects.

PROFESSIONAL AND INDUSTRY ORGANIZATIONS: • Society of Petroleum Engineers of AIME (1961 to Present): Board of Directors (1987-1990);

Member of several Technical Program Committees; Chairman of Roswell Section (1986); Advisor to Student Chapter, New Mexico Tech (1978-1988).

• Sigma Xi, The Scientific Research Society: 1988-89 President, New Mexico Tech Chapter. • American Petroleum Institute: Subcommittee on Evaluation of Polymers Used in Enhanced

Recovery Operations; Chairman of Work Group on Solution Rheology and Flow Through Porous Media.

• Interstate Oil Compact Commission: Member 1986 to Present; Chairman, Enhanced Recov-ery Committee, (1988-1991).

• Independent Petroleum Association of America: Member of Exploration and Production Committee (1992-1996).

• Petroleum Technology Transfer Council: Member (1992-present); Director of Regional Lead Organization (1993-1996); Member of Regional Producer Advisory Group (1996-present).

• Albuquerque Petroleum Association: Member (1987-present); President (1998-2000).

ARTICLES AUTHORED OR COAUTHORED AND PATENTS ISSUED: Books and Short Courses • Authored a chapter on "Reservoir Engineering" Standard Handbook of Petroleum and Natu-

ral Gas Engineering, Vol. 2, Gulf Publishing (1996). • Compiled and delivered a 5-day industry short course on "Oilfield Water Injection Systems." • Compiled (with J.J. Taber) a Workshop on CO2 Flooding--Application, Mechanism and Re-

sults, and conducted PTTC Focused Technology Workshops in Mt. Pleasant, MI, in Decem-ber 1996 and in Jackson, MS in March 1998.

Patents Inventor or joint inventor of 16 patents related to petroleum production.

PUBLICATIONS Authored more than 60 technical papers related to petroleum production. Selected Publications • Martin, F.D. and Taber, J.J.: "Carbon Dioxide Flooding," SPE Technology Today Series,

JPT (April 1992) 396-400.



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• Martin, F.D., Stevens, J.E. and Harpole, K.J.: “CO2-Foam Field Test at the East Vacuum Grayburg/San Andres Unit,” SPERE (Nov.1995), 266-272.

• Taber, J.J., Martin, F.D., and Seright, R.S.: “EOR Screening Criteria Revisited – Part 1: In-troduction to Screening Criteria and Enhanced Recovery Field Projects,” SPERE (Aug. 1997) 189-198.

• Taber, J.J., Martin, F.D., and Seright, R.S.: “EOR Screening Criteria Revisited – Part 2: Ap-plications and Impact of Oil Prices,” SPERE (Aug. 1997) 199-205.



45

c. Letters of Support

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PO Box 2455 Midland, TX 79702 Phone: 915-688-0607 Fax 915-686-7034

April 4, 2001 U.S. Department of Energy National Energy Technology Laboratory P.O. Box 880 3610 Collins Ferry Road Morgantown, WV 26507-0880 To Whom It May Concern: As an operator of a CO2 flood in the Permian Basin, First Permian, L.L.C. is interested in any research that will improve the efficiency of CO2 projects. Due to the size of our company and our CO2 project, research funding is limited. Therefore, we encourage cooperative projects that develop improved practices such as being done at the New Mexico Petroleum Recovery Research Center (PRRC). We encourage the National Energy Technology Laboratory and the National Petroleum Technology Office to continue their support of the PRRC CO2 program. We intend to support the PRRC through means such as (but not limited to) technology transfer, sharing field data, providing reservoir core samples where available, and participating on their advisory committee. This CO2 program is a valuable resource in developing the technical advances necessary to prolong current CO2 projects and to expand the opportunities for future CO2 project development. Again, we encourage the National Petroleum Technology Office to continue support in this vital area. Sincerely

Edward J. Pittinger, P.E. Division Engineer First Permian, L.L.C.

grigg proposal doe april 2001baervan.nmt.edu/groups/gas-flooding/media/pdf... · 2006. 9. 19. · 2...

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