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Offshore E&P—Still More To Learn

Offshore, shallow or deep, is a realm unto itself in which technology and economics are entwined and constantly evolving. The technical agenda for the 2006 Offshore Technology Conference (OTC) May 1–4 in Houston promises to deliver the next chapter in offshore E&P. Approximately 40 technical sessions and more than 300 technical presentations are planned.

Seven papers chosen by OTC 2006 program organizers emphasize that the one sure thing is that the pressure is on the industry to maintain a healthy balance between high risk, steep cost, and reasonable reward. The technical papers discussed in this article are listed below.

Recent Findings in Anisotropy Estimation

The authors of paper OTC 17866 estimate parameters of depth-variant vertical transverse isotropy (VTI) from the first-arrival times recorded in a 3D vertical seismic profile (VSP) survey over a deepwater Gulf of Mexico (GOM) project. They use both conventional slowness inversion and a recently developed travel-time extrapolation technique. The authors are not aware of any depth-dependent estimates of anisotropy from VSP data done before their study. Their work confirms that 3D VSP acquisition geometry is ideally suited for estimating in-situ seismic anisotropy; however, the locality of anisotropy measurements is achieved only when local quantities are used. This is not the case when the horizontal slowness components are involved in the inversion process because they are influenced by lateral velocity variations in the entire overburden. “Correcting the horizontal slownesses for lateral velocity heterogeneity requires knowing the seismic velocity model with accuracy hardly attainable in practice,” the paper states.

Fig.1—First-arrival times (in s) picked for geophone at depth 19,028 ft.

A VSP survey was shot in a spiral pattern, with waveforms recorded by 28 geophones placed in 100-ft increments at depths ranging from 17,528 to 20,228 ft. The first-break times were picked from the data. The authors apply both the conventional slowness and novel travel-time extrapolation techniques and obtain comparable estimates of anisotropy. The travel-time extrapolation method, however, better illustrates the accuracy of knowing the lateral velocity variations needed to achieve the locality of anisotropy estimates. “One subsurface feature—a salt body—profoundly influences our ability to estimate anisotropy from the VSP data,” say the authors. “Its presence causes a decrease of the first-break times clearly seen in the northern portion of the survey. The salt outline is easily identified in the travel-time data (Fig. 1).” This case study reveals the problem with deriving anisotropy from the slowness surfaces; the presence of salt produces slowness distortions that are impossible to fit with any anisotropic model, forcing the authors to rely only on the data recorded outside the salt. Realistic constraints of parameters are discussed. “Our most interesting finding was the negative sign of the anellipticity coefficient η,” the authors say. “It remains to be understood whether the negative sign of η bears lithologic or any other significance.”

Kizomba: Development to Startup

The Kizomba A and B projects in Angola, named for a popular Angolan dance, are sweet music to ExxonMobil, BP, Eni, and Statoil. As of December 2005, 19 exploration wells have been drilled on Angola Block 15, resulting in a world-class 90% success rate and 17 discoveries. Ten appraisal wells also have been drilled to confirm several of the discoveries, and all were successful in extending the original discoveries. Recoverable reserves in Block 15 are estimated to exceed 4.5 billion bbl of oil. An entire technical session will be devoted to these projects (OTC 17915, 17917, 17918, 17919, 17939, 17941, and 17955).

Paper OTC 17915 addresses project-management aspects of Kizomba A and B and also the Xikomba project, highlighting unique aspects and challenges of these developments. “The ‘Design One, Build Multiple’ approach taken in these developments has set new industry standards for project execution,” say the authors.

In August 1994, ExxonMobil and its Coventurers acquired the rights to explore offshore Angola Block 15, located 370 km northwest of Luanda and 145 km west of Soyo. Sonangol is concessionaire of the block, which encompasses an area of 4200 km2 in water depths from 200 m in the east to more than 1600 m in the west. Development planning efforts began shortly after the first discoveries in 1998–99 and were centered around two large hubs, which became known as Kizomba A and B. Kizomba A (Fig. 2) eventually encompasses the Hungo and Chocalho reservoirs (later finds), and Kizomba B (Fig. 3) eventually encompasses the Kissanje and Dikanza reservoirs.

Fig. 2—Kizomba A field development concept.       Fig. 3—Kizomba B field development concept.

Another discovery, Xikomba, was located a sufficient distance from the initial discoveries and warranted a standalone development concept. The Xikomba development plan required nine subsea wells—four production, four water injection, and one gas injection.

Plans took place and were finalized concurrently on Kizomba A and B and Xikomba. The Kizomba A and B developments each consists of a surface-wellhead platform, subsea wells, and a new-build, spread-moored floating production, storage, and offloading (FPSO) vessel. Each FPSO can handle 250,000 BOPD, inject 420,000 bbl of water, and handle 275 MMcf of gas. The Xikomba development includes an FPSO capable of processing 90,000 BOPD, handling 50,000 bbl of water and 95 MMcf of gas.

According to Boles et al., reservoir knowledge gained through initial drilling and the use of new technology, such as intelligent wells, has reduced the Kizomba A program to 54 wells and the B program to 46 wells.

This paper details project execution, including contracting strategy, organizational plan, management systems, development of in-country operations support and associated infrastructure, integrated project schedules and costs, safety, quality, installation, commissioning, and startup. The authors outline the four lump-sum bid packages that were prepared for Kizomba A and included options to provide equipment for Kizomba B as well. “The project team members were gradually and efficiently transitioned from Kizomba A to B, which greatly enhanced the capture of lessons learned,” said the authors.

Both Kizomba A and B projects maintained good cost control, primarily through tight change control and effective use of proven project-management systems, according to the authors. With the startup of Kizomba B in 2005, the initial stages of development of significant resources in Block 15 was concluded, and combined production from the three developments now exceeds 550,000 BOPD.

Key Strategies—Paper OTC 17918 concentrates on two key strategies for executing these flagship, large-scale-capital west Africa deepwater projects: Design One, Build Multiple and the Early Production System (EPS). The speed with which the Kizomba B project was brought on line set industry records for construction and production ramp-up. According to Waters et al., this fast-track development would not have been possible without the early management decision to create a single design for Block 15 offshore platforms, production vessels, and subsea systems and to use that design for multiple projects. The authors elaborate on key project conditions that led to successful implementation of the “Design One, Build Multiple” strategy and offer examples from the Kizomba projects. They also discuss principles of the EPS strategy and its ideal application in the Xikomba field.

Innovative Enablers—The Angola Block 15 drill team had a primary goal of delivering the optimum number of high-performing, long-life wells to meet the early production and injection requirements, and the goals have been met on all projects to date, with desired wells being delivered either on schedule or ahead of plan. Paper OTC 17955 identifies and describes in detail the innovations and outcomes that enabled delivery of best-in-class results. Williams and Wilson report that 32 specific drilling and completion cost-reduction initiatives have been identified, implemented, and tracked on a well-by-well basis. One of these innovations was the use of the Heave Compensated Landing System to install horizontal subsea trees from the back of a work boat and remove this activity from the drilling rig’s critical path. Examples of invented equipment and operational practices used on the Kizomba and Xikomba projects enabled wells to be gravel-packed in a nonaqueous fluid with the Esso-invented Alternate Path Technology. To date, all of the gravel-pack screens have been successfully run to total depth, and gravel placement has been excellent.

Four additional papers will be presented in the Kizomba technical session. OTC 17919 addresses the challenges associated with close-mooring of a surface wellhead platform and an FPSO. Aspects of installing the subsea tieback equipment for both Kizomba A and B are detailed in OTC 17941. Methods used to achieve world-class safety performance on these projects are covered in OTC 17917, while OTC 17939 highlights the accomplishments of establishing the onshore support base for these developments.

Safety and Stability of Fixed Steel Platforms

                                  Fig. 4—Environmental impact.

The design of offshore structures has evolved over the past 50 years from an area of frontier exposure to a more mature practice. Paper OTC 18333 offers historical background on how industry structural codes and margins have evolved and focuses on design and assessment aspects of fixed steel platforms. Correlations are made to the floating facilities and the design points and margins inherent within these codes. According to the paper author, recent experience from Hurricane Andrew to Hurricane Katrina has proved invaluable in observing the performance of offshore platforms in various-category storms. Observed behavior of these platforms provides a basis for qualitative assessment of the performance of the facilities relative to the underlying design premises, design codes, and the robustness of the codes themselves (Fig. 4).

“While much of the offshore structural design still parallels land practice, the uniqueness of the wind, wave, and current environment with difficulty in accurately predicting the likelihood of these forces has led to misunderstandings,” said Wisch.

The paper illustrates that the developers of the offshore design practice have kept the design margin strategy that served the land-based practice and effectively incorporated it into offshore design to allow for a factor of 4 to 8 in recurrence interval from design to failure. Examining the relationship of design levels and expected/observed failure levels and the ratio between them, the author concludes that this margin has proved valuable in establishing a relatively simple elastic-component design process while providing sufficient reserve to balance risk. “When a facility is designed within the assumptions and parameters for which the code has been developed, global structural performance well beyond the design point of 100 years can be expected,” said Wisch.

In 1964, approximately 15 years into the industry process of modifying land-platform design practice into an offshore practice, Hurricane Hilda blew across the oil patch and damaged and/or destroyed a number of platforms. The author gives a historical overview of how, following Hilda, 64 leaders from industry and academia met for the first time for 2 days to assess issues and practices and hurricane prediction. Discussion is offered regarding design points, failure points, reasoning behind design margins, value of margins and elastic-component design, hazard curves, and floating systems.

Flow Assurance—How Confident Are We?

Paper OTC 18381 author McMullen, who will deliver the keynote address for the sessions on Flow Assurance, presents his position on the state of flow-assurance technology to set the stage for all session presentations and to stimulate debate. Expertise in flow assurance remains highly valued within our industry, according to McMullen. The reason: Subsea technology continues to be challenged beyond that which has been proved. Flow assurance still has a profound effect on field-development architecture; it is a key consideration in whether to develop a wet or dry tree.

He points out that many new systems are in place around the world and operating successfully, and some of the largest in the world will go on line. “We now know that many of them have been conservatively designed, and were we to recreate them today, costs could potentially be reduced. We may have built in too much conservatism into these systems and produced suboptimal developments.”

Confidence in flow assurance has vastly improved. Historically, multiphase-flow technology had to be developed rapidly to support system design in arctic, hilly-terrain, and deepwater environments. There remains little more to be done in this area, according to McMullen. Now it is imperative to understand where future development costs may be reduced.

“Future deepwater multiphase systems will need to work with predictable, but significantly higher, levels of risk than we see today,” he said. “The challenge is therefore not only about confidence building, but how the technical community can keep pushing the envelope in a prudent fashion with an eye toward rapid and cheap intervention.”

“Our design problems have become even greater, and the cost of solving them has increased significantly,” remarked McMullen. At 1500–3000-m depths, seabed temperatures in the range of 1–4°C have heightened the wax and hydrate problem. On the production-chemistry front, while headway has been made in kinetic-inhibitor development, deepwater subcooling requirements still cannot be met. The field implementation of antiagglomerant technology reached only the area of black-oil systems. We need to see significant reduction in chemical costs, combined with a broader range in treatment capability. We still face stringent qualification studies for every new prospect—we need to build greater confidence in chemical performance and a low-cost test protocol.

“Wax deposition remains an area of concern,” said McMullen. “There is so much still to be learned, and additional concerns. Accurate deposition models continue to elude us, but important work continues in this area. Meanwhile, we work with field experience as our guide that wax deposition can and does result in lost production and costly intervention. Chemical inhibition only slows and does not eliminate wax deposition, and therefore does not meet performance needs. Though cold flow systems that control hydrate formation behavior appear to be possible, wax deposition must be dealt with as well and may be the biggest challenge in managing noninsulated systems.”

Critical subsea processing also remains on the drawing board. A particular challenge in this area is water/oil separation in the well or at the deepwater wellhead as a design alternative to reduce hydrate-inhibitor usage and to manage flowline and riser hydraulics. While temperature and pressure challenges will continue to exist, the overall temperatures are not likely to get any lower. Rather, the industry probably will face challenges associated with less attractive reservoirs and enhanced-recovery process issues.

Mica—Deepwater Flow Assurance

With flow-assurance plans under way for ultradeep fields and the cost of subsea tiebacks directly linked to flow-assurance considerations, it is important to understand and ensure that the proper weight is given to the right flow-assurance challenges. Paper OTC 18384 author Ballard evaluates the current long-distance tiebacks on the GOM Mica development, giving comparison of design vs. operation. In operation for more than 4 years, Mica is the longest tieback in the GOM, with wells in 4,350 ft of water being tied back via two 29-mile flowlines (one for gas and one for oil) to a major facility (Pompano). New equipment built for the Mica wells to tie in at Pompano includes a high-pressure separator, intermediate-pressure separator, low-pressure separator, turbine-driven centrifugal compressor, a glycol dehydration system, and a turbine-driven generator.

Ballard outlines perceived challenges vs. operational history on this development in the areas of paraffin, corrosion, sand/erosion, hydrates, and slugging. In addition to revealing the strategies taken on Mica in each of these areas, the author cites conditions surrounding, and actions taken during, a 2004 hydrate-plug incident in the gas flowline (Fig. 5). According to Ballard, hydrate issues in the oil flowline have been nonexistent over the past 4 years, most likely because of the low water cut of at most 1%.

Fig. 5—Events that led to gas-flowline hydrate plug in 2004.

He also points out major lessons derived from Mica, one being that, with flowlines as long as these, the impact of operational adjustments to the system takes a significant amount of time to manifest itself. According to the author, for this reason, the startup of the wells and flowlines needs to be slow to enable operations to properly monitor the wells.

A second lesson is the difference between controlling the wells with the subsea choke vs. the topside choke. “Operating staff must understand all assumptions associated with both operating philosophies,” said Ballard. “A prime example of this is under what conditions the methanol dosage rates are valid; flowline pressure is higher when using the topside choke as opposed to the subsea choke, affecting the optimal treatment ratio.”

A third major lesson is that it is possible to flow gas, oil, and water in an uninsulated flowline with underinhibited fluids. “This particular point could lead future subsea flowline design by allowing engineers to focus more on the operating strategies, as opposed to designing it to be ‘bulletproof,’ ” the author said.

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