wellbore management

Based on a workshop sponsored by PTTC's Texas Region on March 22, 2001 in Midland, Texas

BOTTOM LINE

Operators must focus their efforts on wellbore management, paying attention to the total wellbore system (reservoir, downhole and surface equipment) and involving all relevant staff in a team effort to realize the significant reductions in well failures cited for examples discussed during the workshop. Field data must be gathered, thoroughly analyzed, remedial work done, and post-work performance evaluated. Accurate and complete records must be maintained. Doing this and learning from field experience, failure reductions to only a fraction of prior rates can be cost effectively achieved.

PROBLEM ADDRESSED

Wellbore maintenance is an important component of lifting cost. Poorly managed wellbore maintenance leads to high failure frequencies, which can cause lifting cost to spiral out of control. There is a body of knowledge on procedures, approaches and actions that will not only control current costs but also help retain wellbores long term.

KEY WORDS:

Artificial lift surveillance, Asphaltenes and paraffins, Failure reduction, Wellbore management

SPEAKERS

The Producing Well Improvement Process
Kent Gantz and Ed Delgado, Schlumberger Integrated Project Management

Reducing Downhole Failures in the SSAU
Ronnie Aten, Amerada Hess Corporation

Aggressive Action Program and Case Studies on Reducing Wellbore Failures in 22 Fields in Six Permian Basin Counties
Bill Webb, Bill Webb, Inc.

Modern Total Well Management: Sucker-Rod-Lift Case Study
Lynn Rowlan, Echometer Company

Paraffin and Asphaltene Formation Damage
Ken Barker, Baker Petrolite

TECHNOLOGY OVERVIEW

Schlumberger Integrated Project Management (IPM) applied its Producing Well Improvement Process (PWIP) in an 80,000 acre, 1,200 active well (900 producers) mature (producing since 1925) project in the Permian Basin. In 1991, before the effort, well failures exceeded 150 per month. Upon implementing PWIP, well failures were reduced to about 50 per month within the first two years, followed by a further steady decline to the current (2000) level of 18 per month. This equates to a failure rate of 0.25 failures per well per year. More than half of the current failures are tubing failures (includes injectors and wells with submersible pumps). Remaining failures are split evenly between rod and pump failures. Lease operating costs, over $0.70 per barrel of liquid lifted in 1994, have been holding steady at around $0.40 per barrel of liquid lifted since then. 

The PWIP is a systematic, holistic process by which well production optimization and wellbore equipment repair procedures are implemented and improved over time. Decisions are based upon data, not just opinions, using economic parameters consistent with business plans. Pre-planned well service procedures, trained well service and support crews, post-job review and analysis, and automatic operation and continued surveillance are key elements of the process. Pre-planning well service procedures means that there is a written package presenting the data and diagnosis, well information, well servicing procedure, cost estimate and economics, and the appropriate authorization. Forcing a thorough analysis eliminates surprises.

Given a good well servicing plan, well-trained service and support crews execute the job in the field. No job is complete without post-job review and analysis. Well service records must be complete and accurate, failure examinations made, mistakes identified and process improvements discussed. On a post-job basis, pump-off controllers and continued surveillance by the lease operator extend equipment run life. Experience indicates that taking the lowest bid is often not the best option, there is no excuse for repeated failures of the same kind, and repeated failures of different kinds reveals that the initial process was not thorough enough. Tracking failures by lease operator beat allows problem severity and human factors to be assessed.

Philosophies which have proven to be cost effective include: (1) clean older rods while pulling for visual inspection, (2) scan tubing and remove red (> 50% wall loss) and green (31-50% wall loss) band joints, (3) treat rods and tubing with corrosion inhibitor going in hole, (4) run rods with tongs checking coupling displacement, (5) collect samples for analysis when cleaning wellbore, (6) install the smallest pump with the slowest polish rod velocity possible, (7) keep rod loads in the 80% range, (8) always use sinker bars with lift subs between sinker bars, (9) avoid fluid pound by leaving a little production above the pump, and (10) use premium quality pumps with Ni-carb coated brass barrels, 316 SS fittings and silicon nitride valve balls. Depending on well environment, rod strings are case hardened steel, API C, and fiberglass using the lightest effective weight possible. Tubing is seamless J-55 using a 316 SS pup joint above the seating nipple. 

Corrosion protection is critical, since about 40% of the failures are due to wear and wear with corrosion, plus another 20% due to corrosion alone. Scale and sand cause 20% of the failures, while human error causes 20%. For corrosion protection, wells should be treated at least weekly with the minimum treatment being one gallon of inhibitor. Allow one gallon of inhibitor for every 100 bfpd produced. Wells producing above 300 bfpd should be treated continuously with 35-50 ppm of inhibitor. Consider how sour wells are when developing a treating schedule. 

Amerada Hess Corporation (AHC) operates the 17,000-acre Seminole San Andres Unit (SSAU) where CO2 flooding has been in progress since 1983. Currently, there are 571 active wells, 401 producers and 167 injection wells. The additional corrosion and operational problems associated with a CO2 flood make proactive wellbore management especially critical. Work teams, four in all, each containing an engineer, a production foreman, a well technician and a lease operator, are responsible for well work activities and recommendations. The foreman is responsible for all rig work, workover activity and day-to-day operations. The lease operator is responsible for daily maintenance. For the well technician, key responsibilities are to: (1) design, troubleshoot and monitor performance of lift systems, (2) collect field data, (3) evaluate and utilize collected data, (4) analyze lift system, (5) analyze failures, (6) make recommendations based on all of the above, (7) implement planned actions, and (8) monitor other associated area maintenance activities.

Data relevant to analyzing a well's potential include: fluid levels, pump intake pressures, well tests, static bottom hole pressures, initial potential test results, and well characteristics. In monitoring the lift systems, attention is paid to the gearbox, rod strings, pump efficiency, electric motors and dynamometer cards. Thorough analysis of failures helps to prevent future occurrences. Corrective (and preventive) actions may involve the rod string, the tubing string, pumps, electric motors and miscellaneous other equipment. Plans to improve performance address things such as stroke rate, pump size, need for rod guides, need for coated tubing, need for high strength rods, corrosion treating program, and proper rod handling. The well technician must see that recommended changes are understood, made and documented, and results determined. 

An important element of AHC's strategy is to operate its own pump shop. In 1987, there were an increasing number of early time failures in the SSAU. The prior pump shop was some 30 miles away and valuable staff time was lost to inspect pumps. More importantly, AHC could not control quality or exert a significant influence on the practices used by the pump shop. So, beginning in 1988, AHC established it's own pump shop, which has operated continuously since then. With an in-house shop, AHC more thoroughly analyzes pump failures, can build pumps on demand, and can make immediate changes to fix problems. Increased control (and involvement) has led to reduced operating cost, reduced early time failures, reduced pump failures, and increased life of sucker rod systems. More than $1.3 million of savings has been realized on parts and services. For sucker rod systems, the mean time between failures is 3 years. Pump failure frequency is only 0.07 per year (15-year life) and early time failures have essentially been eliminated. Increased involvement from operating the pump shop leads to improved understanding of artificial lift factors. With fewer failures, more time is spent on proactively preventing future problems.

Multiple practices are responsible for AHC achieving these results. New rods are inspected in house using "Go/No Go" test gauges with random rods further sent for full inspection. When rods are laid down, they are fully inspected. Great care is spent on correctly handling (transporting, storing, making up) rods. AHC has found rod guides quite beneficial. Long AF stealth-type rod guides are used, on average 3-4 guides per rod with the number higher on deviated and problem wells. Rod rotators are used to even out wear. Guided stabilizers are used above the pump and between each sinker bar. Although slightly more expensive than a rod with four guides and requiring a larger tubing size, polylined tubing provides greater flow area and less turbulence than with rod guides and is not subject to corrosion. One-inch rods and a lower grade of tubing can be used. Tubing is inspected (hydrotest, scanalog, or complete inspection) when there is a failure or when rods are pulled and wear is noted on the rods or couplings. Tubing anchor catchers are used on all sucker rod lift installations. Internally plastic-coated tubing joints are run as a blast joint on all insert rod pumps. When well work dictates that several trips will be made, a work string is used to prevent wear on the production string. 

Early on, AHC rarely used rod pump controllers, instead choosing to monitor wells closely. But staff reductions and increased workloads led AHC to explore using controllers. Performance during the first nine months of usage was evaluated and benefits determined. Projected benefits from reduced failures and increased production were $395,000. Controllers provide round the clock protection from catastrophic failures, reduce stuffing box leaks and resulting spills, and, in emergencies, allow wells to be shut down more quickly. Controllers also identify wells needing attention before (and after) lease operators make their rounds. Controllers enable well technicians to quickly identify wells needing more detailed analysis, regularly monitor problem wells, and prioritize wells that need changes. Controllers are helpful in identifying intermittent problems, wells that hang up after corrosion inhibitor batch treatments, or flow up the tubing after hot oiling. They also idle the unit when the casing slugs, minimizing the time that the pump experiences gas interference. 

Consultant Bill Webb reported on a wellbore management program encompassing 406 rod-pumped wells on 19 producing leases in six west Texas counties. Prior to the program, in a one-year period, 116 of 406 rod-pumped oil wells experienced failures, which were primarily rod (97 failures) or tubing (75) failures. The action plan entailed changing out the rod strings when failures occurred, and replacing them with an electronically inspected rod string. The sucker rods that had been pulled were then inspected for reuse or sold for scrap. Likewise, tubing failures mandated inspecting the tubing string as it was being pulled or replacing it with an inspected string. The inspection process then classified the used tubing for reuse in pumping wells, other uses or to be sold as junk pipe. Replacing the damaged steel (rods or tubing) was in addition to ensuring proper design, chemical programs and all other considerations in a comprehensive well failure analysis program. All costs were tracked and documented. One year after the 116 wells had been worked on, not one had experienced a rod or tubing failure. Calculated savings, which included production that was not lost due to downtime and avoided pulling costs for 97 rod and 75 tubing failures, were determined. Payouts for the rod and tubing replacement efforts were 0.68 and 0.47 years, respectively. An added benefit was that a lot of company supervision effort could be redirected elsewhere.

Total well management, as defined by the Echometer Company, is an integrated analysis of the pumping system considering all the elements: the prime mover, surface equipment, wellbore equipment, downhole pump, downhole gas separator, and the reservoir. Using Echometer acoustic survey and other tools, all data can be obtained at the surface without entering the wellbore. There are six basic steps in the process: (1) analyze inflow performance to determine if additional production is available, (2) determine the overall efficiency to identify candidate wells (low efficiency), (3) analyze pump performance, (4) analyze performance of downhole gas separator, (5) analyze mechanical loading of rod string and prime mover, and (6) analyze performance of the prime mover. Completing this process, changes can be designed, implemented and improvements verified with retesting. Applying lessons learned, the artificial lift analyst moves from being a data collector to a knowledgeable well analyst and problem solver.

Examples were shared illustrating the data collected and analysis for two situations-an out of balance RotaFlex pumping unit and a marginal oil producer (8 bopd plus 35 bwpd from 5,200 ft). For the marginal producer, the analysis indicated that a collar-size gas separator was needed and a timer should be installed. With the timer, run time was reduced from 24 to 8 hours per day, cutting electric power costs in half. Expected equipment life was increased by a factor of 3. The full case study for the marginal producer has been published in World Oil as part of the Petroleum Digest section (http://www.worldoil.com/magazine/ MAGAZINE_DETAIL.asp?ART_ID=430&MONTH_YEAR=Jun-99).

Controlling asphaltene and paraffin deposition can reduce permeability, causing lower productivity. Therefore, wellbore management should consider their deposition. Although often discussed together, asphaltenes and paraffins are different. Paraffins are n-alkanes that form crystalline structures with melting points up to 240 ºF. Paraffin deposition can occur naturally, due to cooling associated with pressure drop (20 psi drop=1 ºF), high production levels of gas and oil, and from the geothermal gradient. Operational changes that can cause paraffin deposition include cold completion/frac fluids, water or CO2 flooding, and hot oiling down the tubing or casing. Paraffin control options include solvents, dispersants, surfactants, wax crystal modifiers, and heat. Wells can be either batch treated or treated continuously. 

Asphaltenes contain a benzene ring structure. Asphaltenes form an amorphous solid, not a crystalline deposit, that is insoluble in n-pentane/n-heptane. Asphaltenes are black in color, usually brittle, and have charged, high-density molecules. Situations that destabilize the micelle cause asphaltenes to come out of solution. These situations include incompatible liquids (acid jobs, condensate treatments or crude blending) or high gas/liquid ratios (which often occur in gas flooding). Charged surfaces, which can occur with high flow rates, can also cause asphaltene wetting (and deposition)

CONNECTIONS:

Kent Gantz
Schlumberger Integrated Project Management
P.O. Box 1859
Pennwell, TX 79776
Phone: 915-580-4359E
E-mail: kgantz@penwell.ipm.slb.com

Ed Delgado
Schlumberger Integrated Project Management
500 W. Texas, Suite 500
Midland, TX 79701
Phone: 915-571-4600
E-mail: edelgado@midland.ipm.slb.com

Ronnie Aten
Amerada Hess Corporation
P.O. Box 840
Seminole, TX 79360
Phone: 915-758-6794 Fax: 915-758-6715
E-mail: Raten@Hess.com

Bill Webb
Bill Webb, Inc.
P.O. Box 50665
Midland, TX 79710
Phone: 915-682-6821 Fax: 915-682-6871
E-mail: billwebbinc@home.com

Lynn Rowlan
Echometer Company
5001 Ditto Lane
Wichita Falls, TX 76302
Phone: 940-767-4334 Fax: 940-723-7507
E-mail: info@echometer.com

Ken Barker
Baker Petrolite
5032 Darfield Ct
Saint Louis, MO 63128
Phone: 314-968-6001 Fax: 314-968-6013
E-mail: Kenneth.barker@bakerpetrolite.com

For information on PTTC’s Texas Region and its activities contact:
Scott Tinker, Bureau of Economic Geology, University of Texas at Austin,
University Station, Box X, Austin, TX 78713-2924
512-471-0209, fax 512-471-0140, E-mail Scott. Tinker@beg.utexas.edu

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