DOWNHOLE WATER SEPARATION TECHNOLOGIES

Based on a workshop sponsored by PTTC's Central Gulf Region, March 2, 2000 in Baton Rouge, LA

BOTTOM LINE

Evolving technologies for downhole separation— downhole water sink technology, downhole oil water separation technologies, and downhole gas/water technologies— are providing operators with additional options for managing water. Applied in the proper environment, these technologies can be profitable, although field results indicate that there is still significant risk in their application.

PROBLEM ADDRESSED

Evolving technologies for downhole separation-downhole water sink technology, downhole oil water separation technologies, and downhole gas/water technologiesare providing operators with additional options for managing water. Applied in the proper environment, these technologies can be profitable, although field results indicate that there is still significant risk in their application.

KEY WORDS:

Downhole water separation, DWS (Downhole Water Sink), DOWS (Downhole Oil Water Separation), DGWS (Downhole Gas/Water Separation), Produced water management

SPEAKERS

Downhole Water Separation Techniques and Tools
Jeff Knight , Baker Hughes/Centrilift

Nebo-Hemphill Case Study-DWS
Mark Swisher, Aviara Energy Corporation

Performance of DWS Technology, Andrew Wojtanowicz, LSU

Design of DWS Wells, Ephim Shirman , LSU

Status & DOE Funding Opportunities for DOWS
John Veil, Argonne National Lab

Downhole Water Management
Ali Daneshy, Daneshy Consultants Intnl.

Downhole Gas/Water Separation, Jon Rudolph, GRI

Downhole Water Separation with Beam/Rod Pumping Tools
Jeff Miller, DHI Inc.

TECHNOLOGY OVERVIEW

The four cornerstones of a water management strategy include: (1) understanding reservoir structure and heterogeneity, (2) achieving a successful well completion, (3) knowing costs and components of handling water, and (4) knowing applicable regulations. Selective completions and/or water shutoff treatments are one option, but technology advancements have made downhole separation another viable option-for both oil and natural gas wells.

Downhole Water Sink. DWS technology is an alternative for controlling water production in wells producing hydrocarbons from reservoirs with bottom water drives and strong tendencies for water coning (good vertical communication is assumed). With DWS, a well is dually completed for oil production (upper completion) and water drainage (lower completion or water sink) with the two completions separated by a packer. Basically, by adjusting rates of both the upper (oil) and lower (water) completions, one controls the position of the interface at the wellbore and the resulting fluid cuts in each completion. Quality of the drained formation water depends upon DWS completion design and rate adjustment.

DWS drainage-production systems produce water to surface. Systems can be operated in the clean water range, where oil free water is produced from the lower completion. Alternatively, they can be operated for maximum oil production where the upper completion produces water-free oil while some oil may be produced in the lower water sink completion. In drainage-injection systems, the drained water, free from oil contamination, is reinjected in the same well without being produced to surface. The water drainage pump may return the water to the same aquifer (lower in the zone) or into a deeper injection zone.

In a joint project with industry, Louisiana State University has implemented a DWS initiative, currently having nine member companies. The initiative conducts laboratory modeling research and encourages/monitors field applications.

Five field applications are noted to date:

• Louisiana Application. Conventional completions in this strong water drive Wilcox reservoir experience water breakthrough within 6 months. Typically a well in this field would have initial production below 30 BOPD, further declining to 12 BOPD in two years with a water: oil ratio (WOR) exceeding 10: 1. To evaluate DWS technology that Hunt Petroleum drilled a new well in the Nebo-Hemphill Field. It encountered an 18 ft oil column on top of a 64 ft water column. The upper completion was made in the top 3 ft of the oil column, while the lower water sink completion consisted of 5 ft of perforations located 7 ft below the oil/water contact (OWC). Since this is an unconsolidated sand, the water sink completion was gravel packed. Cost for the DWS completion was about 73% more than for a conventional completion. Testing confirmed that by controlling upper and water sink production rates, coning could be controlled. Oil production rates, with no or significantly lower water than with conventional completions, were markedly higher. Payout occurred in 14 months, equal or better than with conventional completions. Importantly, at payout, oil production rates were still over three times higher than observed in conventional completions. The DWS completion outperformed conventional completions by a 5: 1 ratio with regards to net monthly earnings.
• Canadian Application. A DWS completion was tested in a completely watered-out well that was abandoned. The sandstone reservoir with 2-9 Darcy permeability has a 60 ft oil column and a 23 ft aquifer. The recompletion project included squeezing most of the old perforations leaving 10 ft open to flow, and perforating an 8 ft interval below the OWC. Drained water was injected in the open hole section of the Leduc carbonate zone at the bottom of the 5 ½-in casing. A progressing cavity pump was used for oil production and an electric submersible pump for water drainage. Initial production was 250 BOPD (6% oil cut) from the upper completion and 5,400 BWPD from the water drainage completion. As production continued, oil content from the upper completion was steadily increasing about 0.1% per day.
• California Application. Prior production from a 10year old well was 6 BOPD with a 99% water cut. With a DWS completion and 900 BWPD production from the lower water sink completion, oil production from the upper completion increased to 25 BOPD at a 58% water cut.
• East Texas Application. With a DWS completion, production from a watered-out well (producing all water with traces of oil) was increased to 24 BOPD with a total water cut (oil and water drainage completions) of 97%.
• Indonesian Application. The subject well had a 5year history of water coning, with water cuts up to 84%. Several water shutoff treatments had been unsuccessful. With a DWS completion and water drainage rate of 2,550 BWPD, the well was able to produce 298 BOPD.

Performance in most field tests to date (with exception of the Hunt Petroleum well) has been complicated by having been tried in older, conventionally-completed marginal wells that have produced at high water cut for some time. In this situation, the water sink must first drain water saturation around the top completion-a slow process requiring considerable pressure drawdown. Therefore, performance has been mostly proven by laboratory and modeling efforts. Modeling work indicates that a 30% increase in the recovery factor is achievable with a five-fold reduction of the time required to reach the limiting 98% water cut. However, this accelerated recovery requires a 3.5-fold increase in the total water production. Modeling work clearly indicates that the primary advantage of DWS technology is the flexibility in controlling the process, plus higher oil rates, rapid recoveries, and greater recovery factors. Optimization on several parameters, such as maximum recovery, minimum time, or minimum cumulative water, is possible.

Downhole Oil/Water Separation. The opportunity to accelerate oil production provides the primary incentive for DOWS, although potential reduction in operating expense, water handling, and lifting costs are important secondary incentives. DOWS equipment takes two basic approachesgravity separation using rod pumps or enhanced gravity separation using hydrocyclones. Gravity separation systems, which are applicable for lower water volumes, cost from $15,000 to more than $100,000. Hydrocyclone systems, which are applicable for higher water volumes, cost from $90,000 to more than $300,000.

Good candidate wells have a high WOR, good mechanical integrity, sufficient remaining reserves, and a good injection zone (including separation, reasonable pressures, and compatible chemistry with water). In general, DOWS technology does not work with heavy oils (less than 10 o API). Critical factors affecting separation include mixture viscosity, temperature (hotter the better), differential density (minimum difference of 0.05 specific gravity), inlet H 2 0 concentration (higher the better), sand concentration (less than 100 mg/l is better), and gas concentration (up to 5% by volume).

For the higher capacity hydrocyclone applications, capacity depends upon casing size-from 500-4000 bpd in 5 ½-in casing to 2,000-10,000 bpd in 7-in casing. Single stage separation is applicable for a maximum 15% produced oil cut, providing a produced oil (surface) cut of 50%. Two stage separation can process a maximum 35% oil cut, providing a 65% produced oil cut. Important completion issues are monitoring pressure in the disposal zone, cleaning up the disposal zone, and watching for communication behind casing or in the near wellbore region.

Although DOWS does not bring produced water to surface, wells are considered injection wells and are subject to UIC standards. Five states (Colorado, Oklahoma, Kansas, Texas, and Louisiana) have regulatory requirements, similar to or less restrictive than Class II injection wells.

Unocal's Experience with DOWS in East Texas. Unocal tested a hydrocyclone separator in east Texas in the Van Field, well #3722. Pre-test production from the 2600 ft Woodbine B zone was 43 BOPD at a 99% water cut. With the hydrocyclones, target surface production was 300 BOPD with a 10% oil cut. Two 2.5-in Krebs hydrocyclones were installed in parallel providing a total capacity of 4000 BWPD subsurface disposal. The Woodbine C zone at 2,750 ft, thought to have permeability above 1000 mD, was the disposal zone. A preinstallation injectivity test indicated a formation fracture pressure around 1850 psi and an injectivity index of 3.4 to 4.8 bbl/day/psi. Downhole pressure instrumentation and injection water sampling line provided critical data, allowing performance to be both controlled and analyzed.

The unit operated from October 1998 through December 1999. Soon after the test started, the disposal zone pressured up due to debris. It was swabbed and acidized to cleanup. The acid treatment greatly reduced injection pressure causing water disposal rates to exceed pre-test rates by 50%. Later, a back-pressure choke was installed on the separator underflow to limit the injection rate to 3000 BWPD. The unit operated for 14 months when testing was terminated due to low oil production to the surface. The lowered oil production was due to communication, confirmed by tracers, between the production and injection zones. During the 14 months of operation, 1.5 million barrels of water was injected, avoiding $75,000 of water treating costs. Lessons learned during the test included characterization of produced fluids are critical, good system instrumentation is invaluable, and good mechanical integrity is essential. With careful candidate selection, Unocal concluded that DOWS can be as reliable as a conventional downhole pump installation.

DOE/Argonne Study. In a January 1999 study for the US Department of Energy, Argonne National Lab and others analyzed industry's field experience with DOWS technologies. Of 37 reported tests, 21 were hydrocyclone applications while 16 were gravity applications. Nearly threefourths of the tests were in Canada with the remainder in the U. S. Twenty of the field tests were in carbonate formations. Results indicate that DOWS technologies perform better in carbonates-a 47% increase in oil rate vs. 17% in sandstone, an 88% decrease in water vs. 78% in sandstones.

Industry experience has been quite variable-some systems have been in service for more than two years while others failed and were terminated in days or weeks. For wells having both a start and end date, duration ranged from one to 10 months. Those systems which operated as anticipated often achieve quick payout, but rapid failure of many systems indicates that DOWS is still a high risk technology. Recognizing the need for additional controlled field tests, DOE is providing funding through Argonne National Lab for up to six field trials. Up to $30,000 per installation will be provided. These tests will require detailed daily performance records for six months preceding and after DOWS installation. Through February 2000, only one field trial has been funded.

GRI Analysis. GRI recently completed an analysis of DGWS technologies, summarizing field test results and evaluating application criteria and economics for the five basic types of commercial systems for DGWS-bypass tools, modified plunger rod pumps, electrical submersible pumps, coiled tubing electric submersible pumps, and progressive cavity pumps. GRI found 53 commercial field tests involving 34 operators in the U. S. and Canada. Sixty percent of the tests used modified plunger rod pumps, while another 32% used bypass tools. Gas production rates were increased in 57% of the tests with 47% of the field tests termed successful, confirming that there is still significant risk. Half of the 42% failures were attributed to water cycling/injectivity issues. Results in 11% of the tests were considered undefined.

Produced water rates and well depth exert the primary influence on which DWGS tool is appropriate. Bypass tools are appropriate for volumes from 25-250 BWPD and depths in the 2000-8000 ft range. Modified plunger rod pumps can handle 250-800 BWPD at depths in the 2000-8000 ft range. Fully burdened costs for bypass tools and modified plunger rod pumps are about the same, in the $0.30 to $1.10/bbl range. For higher water rates (above 800 BWPD), electrical submersible pumps are typically the most cost effective ($0.20-0.40/bbl), especially at depths greater than 6000 ft.

CONNECTIONS:

Jeff Knight, Baker Hughes/Centrilift
200 W. Stuart Roosa, Claremore, OK 74017
Phone 918-341-9600, E-mail jeff. knight@centrilift.com

Mark Swisher, Aviara Energy Corporation,
P. O. Box 1350, Houston, TX 77251,
Phone 713-871-3400, Fax 713-871-3472, E-mail cgdc2@neosoft.com

Ted Frankiewicz, Unocal EPT,
14141 SW Freeway, Sugarland, TX 77478-3435
Phone 281-287-5214, E-mail frankiewicz@Orion.Unocal.com

John Veil, Argonne National Lab
955 L'Enfant Plaza, SW, Suite 6000, Washington, DC 20024
Phone 202-488-2450, Fax 202-488-2413, E-mail jveil@anl.gov

Jon Rudolph, GRI,
8600 Bryn Mawr Ave, Chicago, IL 60631
Phone 773-399-8185, Fax 773-864-2763, E-mail jrudolph@gri.org

Andrew Wojtanowicz, Petroleum Engineering Department,
LSU, 3516 CEBA, Baton Rouge, LA 70803
Phone 225-388-6049, Fax 225-388-5990, E-mail awojtan@lsu.edu

For information on PTTC’ s Central Gulf Region and its activities contact:
Bob Baumann, Special Assistant to the Provost/Energy Programs,
Louisiana State University, One East Fraternity Circle,
Baton Rouge, LA 70803-0301
Phone 225-388-4400, Fax 225-388-4541, E-mail rbaumann@lsu.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, 2916 West T. C. Jester, Suite 103, Houston, TX 77018
Toll-free 1-888-THE-PTTC; Fax 713-688-0935; E-mail hq@pttc.org; web www.pttc.org