Teamwork, Technology Boost Reserves, Output Off Nigeria

July 14, 1997
Asasa A Platform during batch drilling (Fig. 2). Asasa project work room, Lagos (Fig. 4). Early this year, joint venture partners Mobil Producing Nigeria and the Nigerian National Petroleum Corp. completed a highly efficient fast-track development project in offshore Asasa field combining batch drilling, focused multidisciplinary teamwork, and an integrated suite of geoscience software.
Kirk H. Van Sickle, Elaine L. Cash
Mobil Producing Nigeria
Lagos

Mike Hugentobler
Landmark Graphics Corp.
Houston

Asasa A Platform during batch drilling (Fig. 2).
Asasa project work room, Lagos (Fig. 4).

Early this year, joint venture partners Mobil Producing Nigeria and the Nigerian National Petroleum Corp. completed a highly efficient fast-track development project in offshore Asasa field combining batch drilling, focused multidisciplinary teamwork, and an integrated suite of geoscience software.

The opportunity was identified in October 1994. In 1996, the Asasa team drilled and completed 18 development wells in the field. The first well came on line in June 1996 at 4,800 b/d. At this writing the field is producing 140,000 b/d.

In just over two years, proved and probable reserve estimates tripled, reaching approximately 500 million bbl.

The joint venture

Mobil's roots in Nigeria go back to 1907, when its predecessor first sold kerosene in Lagos.

Early exploration efforts began onshore in the mid-1950s. Its first discovery well was drilled offshore in 1964, and initial oil production began in 1970. Since that time, the MPN/NNPC Joint Venture has discovered almost 40 fields and produced over 2 billion bbl of crude oil and condensate.

Today, the JV is Nigeria's most cost-efficient producer of hydrocarbon liquids and the second largest producer in the nation.

To optimize development of this highly prolific area, MPN began acquiring 3D seismic over its joint venture acreage-more than 1.3 million acres-in 1989. MPN now has Mobil's largest concentration of 3D seismic in the world. Almost every JV geoscientist in Lagos has an interactive desktop workstation to maximize the use of these data. In 1996, the JV drilled 78 wells, and every one was picked using 3D seismic interpretation software.

In 1990, the JV's total proved and probable (P+P) reserves were approximately 3 billion bbl; today, they stand at about 6 billion. Daily production has more than doubled, averaging 523,000 b/d in 1996. The JV is currently targeting 900,000 b/d by 2000.

The Asasa opportunity

Part of a deepwater depositional complex, Asasa field lies south of large Edop and Etim fields about 50 km offshore (Fig. 1 [24327bytes]) . Asasa was discovered in 1981, just after Edop which is located 6 km to the northwest.

While significant oil reserves were identified in stratigraphic traps within Edop field's Intra Qua Iboe (IQI) sands, Asasa encountered only the edges of these reservoirs. As a result, the JV focused its attention on Edop. Its first 3D seismic survey ever was shot over Edop field. By 1994, four wellhead platforms and a production platform with a total capacity of 250,000 b/d of oil were installed.

At the time of its discovery, Asasa's reserves were estimated at 129 million bbl. After additional analysis with 2D seismic data in 1990, they were increased to 143 million bbl. Then in 1992, a new 3D survey was acquired over both Etim and Asasa.

The 3D survey was processed in 1993 and split into two separate seismic projects. Initially, interpretation of the new data focused on additional development in Etim field, which took place from 1994 through May 1996.

However, during interpretation of Etim 3D seismic in the fall of 1994, interesting seismic anomalies were observed in the Asasa area, just at the edge of the data set. The two seismic projects were merged to take a closer look, and significant Asasa potential was identified.

At that point, nearby Edop field's production facilities had excess capacity of about 150,000 b/d, offering a tantalizing opportunity to utilize existing facilities for new production from Asasa.

Appraisal & approval

In October 1994, the idea was first presented to management, and approval was granted to drill an appraisal well in Asasa field.

The first map based on 3D seismic data was created in November 1994. The appraisal well, spudded in December, encountered over 250 ft of net oil in the Intra Qua Iboe and Biafra sands, confirming Asasa's additional potential. As a result, P+P reserve estimates were revised to 170 million bbl.

Within 2 weeks of logging the appraisal well, the Asasa team completed its economic analysis and recommended fabrication of two wellhead platforms and pipelines to tie back to the existing Edop production platform.

Moving ahead rapidly entailed technical and financial risks, due to the short time spent analyzing the field's complex, stratigraphically-trapped reservoirs. But management trusted the Asasa team's technical judgment, believed the incremental uplift was worth the financial risk, and provided complete support.

Not only was the proposal approved, but the team was empowered to "fast-track" the development to get production on line as soon as possible. The JV had just set a new goal to increase average crude production per year from 330,000 b/d to 500,000 b/d within 2 years.

Project planning

For the next 15 months, the Asasa team met regularly to finalize reservoir mapping, prepare the development plan, identify initial well locations, and accelerate ordering and installation of pipelines and two 12-slot wellhead platforms.

The team consisted of geoscientists and reservoir, drilling, operations, and facilities engineers-as well as representatives of several oilfield service companies.

From the beginning, every key decision was driven by three clear business objectives: to increase production, add reserves, and do both as efficiently as possible.

During 1995, the Asasa team proposed a modified batch drilling process to reduce drilling cycle time and lower costs. The plan was to drill and complete 16 wells (eight from each platform) in "batches" of two or three instead of one at a time. The ultimate goal was to bring production on-line even faster than originally projected to meet the aggressive new production targets.

The drilling plan was finalized, and the Asasa A and B platforms were installed by April 1996.

Batch drilling

Rigs moved onto both platforms in May 1996. Drilling commenced first on Asasa A, followed by Asasa B about a week later. In the first drilling phase, six wells were batch drilled-three from each platform (Fig. 2 [7419 bytes]).

First, drive pipe was set for all 16 wells to be drilled during the project. Then surface hole was drilled and casing set in each batch of three. Finally, all three wells were drilled down to the pay section and logged in quick succession. Immediately after batch drilling, the wells were batch completed. The typical well was drilled to more than 9,000 ft MD at over 45° with an S-shaped profile.

To encourage greater efficiency, a healthy competition was set up between the Asasa A and B drilling teams. One team employed an enhanced supplier relationship; the other was "business as usual," providing a dynamic benchmark for evaluation. As a result, a number of new JV drilling records were set, and the initial drilling phase finished two months ahead of schedule and $6 million under budget. The second and third batch drilling phases were completed by December 1996.

Prior to Asasa, the fastest well drilled by the JV took 12 days. More than half of the Asasa wells were drilled in fewer than 11 days. The fastest took only 61/2 days. In fact, cycle time was reduced so dramatically that equipment suppliers struggled to keep pace.

Batch drilling also put pressure on the Asasa geoscience team to load, analyze, and integrate new well information in almost real time. With two rigs running, large amounts of log data came in regularly that required immediate evaluation. Having integrated geological and geophysical applications that shared a common data base allowed the team to make more informed decisions quickly-reducing cycle time and reducing risk.

Integrated software

In early 1996, MPN's manager of technical data management had brought in a suite of Landmark applications for evaluation, including fully integrated 3D seismic interpretation, geological interpretation, petrophysical analysis, and wellbore engineering data management.

He believed that integrated software and a common project data base would enable geoscientists to make better decisions during fast-paced drilling programs. If they could avoid unnecessarily sidetracking even a few wells, the software would pay for itself.

The Asasa project offered a unique opportunity to test the applications with hard data in real time. But the team did not have time to learn new software utilization during such an ambitious project. Landmark agreed to provide a workflow consultant to work side-by-side with team members throughout the batch drilling phase.

The consultant advised them on how to load data into the common data base and keep information flowing quickly through the whole system.

The consultant also helped depth-convert seismic data and integrate 3D seismic sections and wellbore engineering data with geological correlation charts. As a result, the team was able not just to obtain data in real time but to integrate and interpret all of the available information on a daily basis.

Interpretation

The Asasa team's objectives for integrated interpretation while drilling were to optimize well plans rapidly (usually in batches), decide whether to sidetrack certain wells, and determine which zones to perforate and complete on-the-fly.

Even with 3D seismic data, there were only three wells on which to base the velocity interpretation prior to batch drilling. Checkshot surveys were acquired on most of the new wells. But the team never knew exactly what to expect until the drill bit first entered the pay section of each well. In this deepwater geological environment, one well might encounter hundreds of feet of pay, while another well a few hundred meters away might have significantly less pay.

A rather unique aspect of the integrated work flow was that software templates were developed that enabled the team to combine all essential geophysical, geological, petrophysical, and engineering data into a few common displays (Fig. 3 [62988]). Those displays-including seismic sections-were in depth. Seismic lines were no longer interpreted or plotted in two-way travel time, facilitating communication among geoscientists and engineers.

Each day during drilling, updated directional information was loaded into the project data base. Using depth-converted seismic data, a visual comparison was made on screen between the actual well path and the projected well plan. If there was a discrepancy, it was immediately apparent. MWD and other well log curves were transmitted electronically from the rig to the office and loaded into the data base. Along with curve data, RFT measurements, checkshots, casing points, core intervals with notes, perforations, completion intervals, API gravities, and GORs were loaded as well.

As soon as a new log came in, the wells were correlated, sands and shales were interpreted along with the seismic data, and stratigraphic sections were updated. Net sand counts were calculated automatically using geological software, and isopach maps with sand/shale pie charts were generated at each well location. Petrophysical calculated curves were also loaded into the project database.

Having all the data in a single data base enabled the team to make changes rapidly and bring all relevant information into one place.

Integrated paper displays consisting of geologic cross sections with depth-converted seismic backdrops were updated regularly and hung in view of the geoscience workstation (Fig. 4 [9197]). Well log curves, petrophysical curves, RFTs, casing, perfs, and completion intervals were all displayed in true vertical depth with measured depths indicated along the tracks of deviated well bores.

Traditionally, geoscientists and drilling engineers have been at odds with each other when it comes to planning and drilling wells. These new software tools assisted in breaking down these barriers, allowing geoscientists to communicate in terms engineers could easily understand.

For example, before drilling a set of wells, coordinates for the targets were given to the engineers. If they had any problems, the team could negotiate the wellbores by sitting down and looking at all of the data in depth. During drilling, geoscientists could tell exactly where the drill bit was on the seismic section simply by noting its depth. As a result, the drillers were instructed several times to drop angle in order to hit some targets better. Using integrated displays in depth streamlined the decision process.

While drilling the last well in Asasa field, the team encountered a situation that exemplifies the value of integrated technology. The last well was a very long reach well attempting to delineate the extent of the field. It encountered only a gas sand and about 10 ft of low resistivity oil pay. The team had expected thicker reservoir sands.

The options were to sidetrack, plug, or case the well.

To make the best possible decision, well log curves were loaded into the integrated system, and the data were interpreted using both geological and geophysical software. Within 3 hr on a Sunday morning, it was determined that the zone actually might be connected with the rest of the field. The decision was made to case the well and run a DST.

The well tested successfully and after 2 months was producing about 1,000 b/d.

Sidetracking the well would have cost at least an additional week of rig time and several hundred thousand dollars more. Sometimes only a few hours are available to make a significant business decision. With integrated technology, that decision can be made with much greater confidence.

Project results

From May 16 through Dec. 10, 1996, the JV batch- drilled 16 wells from the Asasa A and B platforms in three phases. Two additional long-reach wells to delineate field limits were completed by mid-January 1997.

In just eight months, Asasa field's P+P reserves nearly tripled-from 170 million bbl to about 500 million bbl, with over 1 billion bbl in place (Fig. 5 [13831]). In October-just two years from the original idea and less than five months from start-up-production hit 100,000 b/d.

At this writing the field is producing over 140,000 b/d, accounting for one-quarter of the JV's total crude production (see table). Not only did the JV exceed its production target for 1996, but the Asasa project will pay out by mid-1997.

Asasa's aggressive batch drilling/completion process broke records (Fig. 6 [38797]), provided a string of best practices with benchmarks and spawned similar projects among other drilling teams, including the recently installed Etim C platform.

The two drilling teams shaved $15.2 million off the original AFE (12% of total project costs). Total hole drilled exceeded 151,000 ft at $221/ft (32% below the JV's average), and 769 ft/day (92% more than the JV's average). Prior to Asasa, the fastest well took 12 days. Nine of the 16 Asasa wells took under 11 days to drill; six wells took fewer than nine days. Overall, the teams cut drilling and completion time by 200 days (35% less than AFE). They reduced the spud-to-sales cycle time from to 28 days from 41, adding 4 million bbl of incremental production in 1996.

Earlier this year, the Asasa team turned over the project data set to Mobil's E&P Technical Center in Dallas to facilitate the transfer of integrated technology worldwide and to conduct more detailed analysis for future reservoir management planning.

The success of the Asasa project was not due primarily to technology, although that played a major role. It was due more to early management support, extensive planning, effective daily planning, calculated risk-taking, enhanced teamwork (including contractors, service companies, and suppliers), and total commitment to bottom-line results.

The industry has talked about interdisciplinary teams for years. The Asasa team in Nigeria actually broke down the barriers between disciplines, making this one of Mobil's most profitable projects in recent years.

Acknowledgments

The authors acknowledge the following individuals, whose contributions made the Asasa project a resounding success: Jim Kelly (petrophysicist), Isaiah Okunlola (geophysicist), Gary Tsang (reservoir engineer), Ezekiel Ekworomadu (reservoir engineer), Byron Clancey (operations engineer), Charles Effiong (operations engineer), Taiwo Olushina (operations engineer), Abdul-Lateef Ibit- oye (drilling engineer), Gary Smith (drilling supervisor), James Smithey (drilling supervisor), Jay Cunningham (drilling supervisor), Craig Iversen (drilling supervisor), John Matherne (drilling supervisor), Ed Yount (drill- ing supervisor), Greg Miller (drilling supervisor), Don Monk (drilling supervisor), Chuck Riebe (drilling engineering supervisor), Bill Watson (Asasa A drilling superintendent), Mike Smith (Asasa B drilling superintendent), George Fisher (technical data manager), and Richard Lewis (Schlumberger ESR team leader). Special thanks also to the management of MPN and NNPC and the Nigerian Department of Petroleum Resources for approval to submit the results of this project for publication.

China

Noble Affiliates Inc.'s Energy Development Corp. (China) Inc. unit obtained rights to explore and develop the 117,000 acre Cheng Zi Kou block in Bohai Bay.

The block is adjacent to giant Sheng* oil field and west of EDC's Cheng Dao Xi block acquired earlier this year. EDC will operate both in cooperation with the Sheng* Petroleum Administration Bureau.

The Cheng Zi Kou agreement with China National Petroleum Corp. is subject to approval by the Chinese Ministry of Foreign Trade and Economic Cooperation.

Egypt

Scimitar Hydrocarbons Ltd., Calgary, started talks in Cairo covering pilot and commercial development of Issaran (also called Asran) heavy oil field in the eastern desert just northwest of the Gulf of Suez.

Discovered in 1981, the field has nine wells. Four vertical wells have produced more than 370,000 bbl of oil. They have produced at rates up to 500 b/d/well without thermal stimulation.

The field contains 10.5-18° gravity oil in three shallow, fractured Miocene carbonates, the deepest at 760 m (OGJ, Dec. 16, 1996, p. 24).

Scimitar hopes to use horizontal wells and steam assisted gravity drainage technology to recover several hundred million barrels of oil from the 300 ft thick pay zones at about 2,500 ft TVD. Pilot work could start this fall.

Madagascar

Gulfstream Resources Canada Ltd., Calgary, signed agreements with Omnis and the government that establish terms for a long-running alliance with Omnis to identify and develop oil and gas potential.

The agreements cover exploration, development, transportation, processing, and marketing.

Gulfstream holds an 82% interest in the 26,700 sq km Tsiribihina block in the onshore Morondava basin and an 80% interest in the 5,200 sq km Antonibe offshore concession in the Majunga basin (OGJ, Aug. 1, 1994, p. 54).

The company plans a 300 km seismic program on Tsiribihina this fall to high-grade proved reserves for a multiwell program in spring 1998. It said several wells have been drilled in the target area, one with 2 tcf of estimated gas in place.

Mozambique

Scimitar Hydrocarbons Ltd., Calgary, plans to drill two wildcats during August-October 1997 on the onshore 2.1 million acre Buzi-Divinhe Block (see map, OGJ, Aug, 19, 1996, p. 39).

A Scimitar unit signed a letter of intent that grants JCI Ltd. the right to purchase up to 1.2 tcf of gas during 30 years at a price structured to match the rate of return realized on the iron plant JCI is considering.

Working interests are Scimitar 75% and Leopardus Resources Ltd., Calgary, 25%.

Gulf of Mexico

Kerr-McGee Corp. will use third party platform ownership in developing Garden Banks 65 gas field. The development includes East Cameron Block 373 and Garden Banks blocks 21 and 22.

Leviathan Gas Pipeline Partners LP, Houston, will install and own a four pile production platform for use as a gas processing and pipeline junction facility.

GB65 production is to start in mid-1998 at 60 MMcfd. Working interests are Kerr-McGee 60% and Newfield Exploration Co., Houston, 40%.

Colorado

Nielson & Associates Inc., Cody, Wyo., staked a wildcat between the Laramie and North Park basins.

PI/Dwights says Casper, the Pennsylvanian Tensleep equivalent, at 1,500 ft is the objective at the 1 French Woman, in 15-22n-76w, Larimer County. Ground elevation is 8,555 ft.

Missouri

Western Engineering Inc., Evansville, Ind., and United Petroleum Corp., Knoxville, Tenn., hiked production to 80 b/d of oil at a pilot project in the Belton Unit of Clark-Miller (Knoche) field in Cass County.

The firms drilled three horizontal wells to Pennsylvanian Squirrel sandstone at about 650 ft TVD. Production began Apr. 10, 1997, at 20 b/d.

New Mexico

Mallon Resources Corp., Denver, said successful wells in Quail Ridge field in Lea County have identified a number of new locations that exceeds the company's entire program the past 12 months.

The 1-33 Federal, in 33-19s-34e, flowed 359 b/d of oil from Permian Bone Spring at 9,968 ft. The 4-30 Mescalero Ridge, in 30-19s-34e, flowed 765 Mcfd of gas and 56 b/d of condensate from Pennsylvanian Morrow at 13,227 ft.

Both wells found significant Delaware Cherry Canyon and Brushy Canyon pay zones. The 4-30 well also has pay in Bone Spring and Strawn. Mallon plans to drill the uphole zones.

Texas

Panhandle

Kermit L. Waters, Las Vegas, Nev., staked a Hardeman basin wildcat in Childress County.

The 1 Waters, 4 miles north of Childress, is projected to 8,000 ft or Ordovician Ellenburger. It is 10 miles northwest of Kirkland South Canyon oil field.

Only 13 of 187 wells drilled in the county have been completed as producers, all in Cisco or Canyon, PI reported.

West

Wheeler Operating Corp., Fort Worth, completed a Pennsylvanian Canyon discovery at a Hockley County re-entry.

The 1 Arnwhine-Wilson Unit, 2 miles east of Levelland, pumped 352 b/d of 30° gravity oil with 64.5 Mcfd of gas and 160 b/d of water from perforations at 9,640-52 ft, PI reported. It is 41/2 miles northeast of Canyon production.

East

Amerada Hess Corp. permitted a wildcat in the East Texas Cotton Valley reef play.

The 1 T Bar X Corby, 6 miles northwest of Marquez in Leon County, is projected to 16,500 ft. It is about 1 mile east of Marathon Oil Co.'s Kenwood gas field, PI reported.

Titan Energy Corp., Fort Worth, acquired 650 oil wells on 4,500 acres in Corsicana field in Navarro County from Rife Oil Properties Inc., Fort Worth.

Texas' first oil field, Corsicana is judged by independent engineers to contain significant remaining oil in place in Cretaceous Lower, Middle, and Upper Nacatoch and the Wolfe City member of the Taylor marl at less than 1,000 ft. An oil mining project is envisioned.

Barrow-Shaver Resources Co., Tyler, Tex., has completed 20 wells producing oil from Upper Cretaceous Sub-Clarksville in BSR field of Madison County.

The field 7 miles north of Madisonville has produced more than 322,000 bbl of oil, 422 MMcf of gas, and 18,000 bbl of water from 15 wells during late 1994 through March 1997, PI reported.The first 19 completions averaged 141 b/d on initial test, and the 20th flowed 251 b/d of 39° gravity oil.

WCS Oil & Gas Corp., Dallas, completed a dual lateral Cretaceous Georgetown well 4 miles north of Wheelock in Robertson County, PI noted.

The 1-H Doering-Cloat in Ici field flowed 2,135 b/d of oil with 647 Mcfd of gas on a 1 in. choke with 150 psi FTP from 7,220-11,917 ft and 7,220-12,115 ft.

Wyoming

Redstone Gas Partners LLC, Denver, sought drilling permits for coalbed methane wildcats in the northwestern Powder River basin (see map, OGJ, Mar. 10, 1997, p. 79).

The spots for the 750-800 ft tests to Fort Union coals are in 24- and 25-9s-39e and 29- and 30-9s-40e, PI reported.

The AuthorsKirk H. Van Sickle is a geophysical adviser for Mobil Producing Nigeria in Lagos. He was the Asasa Project leader and lead geoscientist. He has 17 years of experience in exploration and development geophysics with Mobil in the U.S. and Nigeria. He earned a bachelor's degree in geology from the University of Arkansas.

Elaine L. Cash is a staff drilling engineer for Mobil Producing Nigeria in Lagos. She was Asasa Project drilling engineer. Cash has 11 years of experience in drilling and production engineering with Mobil, both in the U.S. and Nigeria. She earned her bachelor's degree in petroleum engineering from Texas A&M University and is a registered professional engineer.

Mike Hugentobler is Landmark's manager of North Sea professional services practice. He provided Asasa Project onsite consulting services. Before joining Landmark, he worked for Amoco Production Co. in exploration and production and completed Amoco's Petrophysics Training. He earned a BS degree in geology from Brigham Young University and a master's degree from Southern Illinois University.

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