california water control study

Based on a PTTC West Coast/California Energy Commission (CEC) workshop, February 12, 2004 in Los Angeles, California.

BOTTOM LINE

Produced water management has been a focus for PTTC. In the Midcontinent area, PTTC developed a concise manual outlining the causes and solutions for excess water production, plus operating practices to reduce costs. In California, staff is working alongside producers in a consortium effort. Operators are sharing their data, which is being analyzed to determine trends. Sufficient well and reservoir data is being analyzed for results to be representative of Los Angeles (LA) Basin operations. Results show that water control efforts are generally economic, but more case studies are needed. Data are also clear in that operators need to place more effort in gathering fluid entry data and diagnosing the causes of high water production.

PROBLEM ADDRESSED

Mature oil production in the U.S. often produces at high water cut, increasing operating cost and causing operating and other challenges. Causes and solutions for high water production vary geographically depending upon the geological environment. In a concerted effort in the Midcontinent and California, PTTC is working with industry to better identify causes and cost effective technology solutions. 

KEY WORDS:

Conformance Modeling Software, Diagnostic Methods to Determine Causes of High Water Production, Geological Causes of High Water Production,
Water Control Solutions

SPEAKERS

Water Control, A National Perspective,
Don Duttlinger, PTTC

Decreasing Electric Demand in Oilfield Operations by Reducing Excess Water Production,
Iraj Ershaghi, University of Southern California

Survey of Selected Producers, Preliminary Analysis and Metrics,
Glenn Swanson, Consultant

Geological Causes of High Water Production,
Linda Smith, Texokan Exploration Services

Water Control, State-of-the-Art,
David Smith, Occidental Permian Ltd.

Conformance Modeling Software,
Don Everett, Halliburton Energy Services

Diagnostic Methods, Tracers,
Rob and Ryan Cochran, Rob Cochran Consulting, Inc.

Diagnostic Methods, Fluid Entry Surveys,
Ron Bates, Signal Hill Petroleum and Bob Ullerich, Production Logging Services

Cost Effective Solutions, Sealers,
Rick Curtice, Halliburton Energy Services

Cost Effective Solutions, Relative Permeability Modifiers,
Leonard Kalfayan, BJ Services
 

TECHNOLOGY OVERVIEW

With the U.S.'s mature oil production, water production is a problem. On average, water cut is approaching 90% and, in many mature wells, water cuts in excess of 98% are common. Besides driving operating costs up, excess water production leads to other operational and reservoir problems. When determining constraints that limited oil production as part of its DOE-supported PUMP (Preferred Upstream Management Practices) project, PTTC learned that "Produced Water" and everything associated with it is a primary constraint. PTTC's PUMP project focused on the Midcontinent and California. In the Midcontinent area, PTTC developed a concise manual (http://www.pttc.org/pwm/produced_water.htm) outlining the causes and solutions for excess water production, plus operating practices to reduce costs should one just have to live with high water production.

Recognizing that the causes and solutions vary with geological environment, PTTC's West Coast Region, with funding support from the California Energy Commission (CEC) and DOE's PUMP project, is working with operators in a consortium effort. Operators are sharing data about their wells, and staff is analyzing that data to discern trends. This includes analyzing the effectiveness of solutions that operators have employed. Work is proceeding in the Los Angeles (LA) Basin and the San Joaquin Valley. This workshop focuses on findings from the LA Basin effort.

Geological Causes of High Water Production in California Turbidites
The turbidite environment prevalent in the LA Basin is characterized by large intervals of alternating sand-shale sequences. Saturations in sands can vary widely and any sand, regardless of depth, could be wet. Wells are typically completed in multiple intervals throughout several hundred feet of interval. Fluid entry surveys are infrequent, so operators typically don't know which zones are contributing what. That is especially critical when a well begins producing high water cut.

CEC/PTTC Study of California Excess Water Production/Control
Staff works alongside producers willing to share their data, experience and perceptions about problems and solutions. This workshop focused on the LA Basin area where five operators have shared their data and experience. Data come from seven fields (six waterfloods and one natural water drive) whose combined field production represents about 60% of California's District 1 (LA Basin) production. There were 12 producing zones represented in the seven fields. Data were summarized for 67 producers and 60 injectors. Performance and economics of 17 water control treatments was evaluated. Results from this representative sample provide insights for general LA Basin production.

The three leading reservoir engineering/geology factors contributing to excess water production include: (1) thief zones, (2) faulting, and (3) high water saturation near producers. Leading mechanical and completion factors include: (1) slotted liners (including gravel packs), (2) length of intervals open, and (3) wrong zones open.

Both producers and injectors were classified as either "good" or "bad" and numerous parameters were compared to identify what was different/similar in the good and bad wells. For the injectors, major parameters that differed significantly include (1) BWIPD and (2) % of injection into top subzone. Parameters that did not differ significantly (i.e., did not affect the good/bad determination) include: (1) completion type, (2) length of open interval, (3) # subzones injected, (4) actual BWIPD/ft, and (5) characteristics of the lower thief subzone. In a similar comparison for producers, the major parameters that differed significantly between good and bad wells include: (1) BOPD and (2) water cut. Parameters that did not differ significantly include: (1) well age, (2) slots in completion, (3) length of open interval, and (4) theoretical BPD/ft.

Water control solutions include mechanical, sealants, recompletions including plugbacks, selective stimulations, and waterflood management. For the 17 water control jobs evaluated, the average cost of the water control portion of a job was just over $25,000 (total job cost with additional work averaged $73,000). Average payout was just over seven months. This data establish that water control efforts are generally cost effective. From a perception standpoint, economic factors that would lead operators to take more action with water control solutions are: (1) increased electrical costs and (2) better economics for the solutions employed. More case studies that document technical and economic performance are also important.

Water Control or Conformance Treatments
Developing a correct understanding of the excess water problem is the single most important factor in a water control program. Data from Oxy Permian's Permian Basin operations support this statement with 70% of economic failures (which occurred 40% of the time) being attributed to misdiagnosis of the problem or misunderstanding of the reservoir. Failure of the solution to perform as planned accounted for the remaining 30% of the economic failures.

In diagnosing problems, one must learn how fluid moves through the reservoir and why. One must also know how the wellbore, both past and present, interacts with the reservoir. Understanding the reservoir requires that geologists, reservoir and production engineers, and field staff interact in a multi-disciplined effort. To understand wellbore interactions, one must study the completion, impacts of stimulation treatments that may have been performed, injection projects and revelations from analyzing production/injection data. One must discern whether there are single or multiple problems. If multiple problems exist, does one dominate? Can and should multiple problems be addressed in a solution? Lastly, can one define the chances of success and will the solution be economic?

Placing excess water problems within a matrix is helpful for determining appropriate solutions. Is problem flow dominated near the wellbore or deep in the reservoir? Is problem flow through permeable rock or through void space or high flow conduits? For example, channel flow behind pipe would be flow through a void dominated near the wellbore. In this instance, cement or chemical solutions could be appropriate solutions. Solutions fall within three general categories: (1) existing wellbore interventions, (2) pattern re-configurations, and (3) designer wellbores. Appropriateness of a given solution depends on where the problem lies within the matrix.

Conformance Modeling Software
Engineers faced with modeling well conformance improvement treatments want a tool that combines simplicity (convenient for evaluating single well treatments) and accuracy (compares well with results from full feature simulators) and can model multiple phase flow. Halliburton Energy Service's Windows-based QuikLook^SM simulator meets that objective, incorporating conformance fluid data with basic wellbore and reservoir data. 2-D and 3-D visualization tools illustrate pre- and post-treatment results. Sensitivity studies using different treatment design parameters can be performed quickly, enabling individual treatments to be cost effectively optimized.

Tracer Surveys
Chemical tracer surveys help define often complex injection water flow paths in waterflood operations. There are up to eight different chemicals that can be used as tracers. Chemical tracer slugs, using different tracers for each injection well in a survey, are injected in precise amounts over a set period of time into each well's injection stream. Presence and concentration of tracers in produced water from nearby producers or other producers thought to be influenced by injection are measured. Sampling periods are set so as not to miss the injection water/tracer slugs. The arrival times and concentrations of tracers at different producers reveals much about fluid flow paths in the reservoir. Rapid arrival at high concentration would be indicative of thief zones or very poor sweep. It is not uncommon for tracers to bypass producers near injectors, revealing the often complex flow paths present in injection projects. Multiple tracer arrival peaks can confirm movement through different intervals. Although sampling duration is addressed in project planning, results typically determine when sampling is stopped. Ideally, sampling continues well past peak arrival times since declining tracer concentrations reveal more about fluid flow paths.

Fluid Entry Surveys
Fluid entry surveys have application in problematic high water cut wells, evaluating idle wells and waterflood monitoring. This data may be gathered through temperature surveys or fluid entry/injection profile surveys. When planning fluid entry surveys, one must consider mechanical issues, such as: available tool sizes, clearance checkpoints, wellhead issues, downhole issues, and potential problems. There are equipment differences for rod-pumped and submersible-pumped wells. Fluid entry surveys provide both qualitative and quantitative data. Tracers help define flow rates and capacitance helps distinguish oil and water. Experience indicates that surveys can be obtained on 90% of wells. Fluid entry surveys are a cost effective component of a planned reservoir/field management program.

For injection wells, once profile data are available, there are two key questions. Are the zones currently taking fluid contributing to production? If not, isolate them and treat the offending zones to stop fluid entry. Do the zones not taking fluid have potential to contribute to production? If they could, stimulate them after offending zones have been shut off.

Relative Permeability Modifiers
Relative permeability modifiers (RPMs) are one matrix treatment solution for controlling excess water production. RPMs can be applied by bullheading or through coil tubing. BJ Services presented data from a five-well producer treatment program in Indonesia, illustrating the reductions in water production and increases in oil production that are possible (see SPE #84623). Data were also presented for two successful gas well applications, one in Canada and a second in the U.S. Midcontinent. Halliburton also offers an RPM product, and other vendors continue to develop products. (See PTTC's Network News newsletter, 4th Qtr 2003 http://www.pttc.org/news/4qtr2003/v9n4p5.htm#1 for further information about RPMs.)
 

CONNECTIONS:

Ron Bates
Signal Hill Petroleum, Inc.
2901 Orange Avenue
Long Beach, CA 90806
Phone: 562-595-6440 Fax: 562-426-4587
E-mail: rbates@shpi.net

Rob Cochran
Ryan Cochran
Rob Cochran Consulting, Inc.
PO Box 2154
Midland, TX 79702
Phone: 432-520-5810
E-mail: robc827@aol.com

Rick Curtice
Halliburton Energy Services
PO Box 339
Vernal, UT 84078
Phone: 435-789-2550 Fax: 801-785-2892
E-mail: Richard.curtice@halliburton.com

Don Duttlinger
PTTC
16010 Barkers Point Lane, Suite 220
Houston, TX 77079
Phone: 281-921-1720 Fax: 281-921-1723
E-mail: dond@pttc.org

Iraj Ershaghi
University of Southern California
Petroleum Engineering
HEDCO-316
Los Angeles, CA 90089-1211
Phone: 213-740-0321 Fax: 213-740-0324
E-mail: ershaghi@usc.edu

Don Everett
Halliburton Energy Services
7910 Feather Springs Dr
Houston, TX 77095
Phone: 281-575-5669 Fax: 281-988-2100
E-mail: don.everett@halliburton.com

Leonard Kalfayan
BJ Services Company
11211 FM2920
Tomball, TX 77375
Phone: 281-357-2560 Fax: 281-351-7764
E-Mail: lkalfayan@bjservices.com

David Smith
Occidental Permian Ltd.
PO Box 4294
Houston, TX 77210-4294
Phone: 281-552-1118 Fax: 713-985-1664
E-mail: David_Smith@oxy.com

Linda Smith
Texokan Exploration Services
610 Santa Monica Blvd., Ste 201
Santa Monica, CA 90401
Phone: 310-395-0185

Glenn Swanson
Consultant
3322 Cortese Dr
Los Alamitos, CA 90720
Phone: 562-715-1444 Fax: 562-596-9615
E-mail: swanglenn@aol.com

Bob Ullerich
Production Logging Services
PO Box 9356
Long Beach, CA 90810
Phone: 310-834-3034
 

For information on PTTC’s West Coast Region and its activities contact:
Iraj Ershaghi, Director, Petroleum Engineering Program, HEDCO-316
University of Southern California, Los Angeles, CA 90089-1211
Phone 213-740-0321, Fax 213-740-0324, E-mail ershaghi@usc.edu

Disclaimer: No specific application of products or services is endorsed by PTTC. Reasonable steps are taken to ensure the reliability of sources for information that PTTC disseminates; individuals and institutions are solely responsible for the consequences of its use.

The not-for-profit Petroleum Technology Transfer Council is funded primarily by the US Department of Energy’s Office of Fossil Energy, with additional funding from universities, state geological surveys, several state governments, and industry donations.

Petroleum Technology Transfer Council, 16010 Barkers Point Lane, Ste 220, Houston, TX 77079
toll-free 1-888-THE-PTTC; fax 281-921-1723; Email hq@pttc.org; web www.pttc.org