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More than 8,000 professionals expected in San Antonio, Texas, 24–27 September for the 2006 SPE Annual Technical Conference and Exhibition (ATCE) will get a comprehensive look into the future. What outlook is emerging? What are the causes and effects?

Technical presentations will foretell the future of drilling and completions; projects, facilities, and construction; production and operations; reservoir description and dynamics; management and information; and health, safety, and environment. The following six presentations on imminent industry developments have been selected as some of the best papers and most representative of the industry future that is already taking shape.

Elements of Well Integrity

“At 0400 hours each morning, a computer program automatically starts and scans all pressure, well-test, and other data, and generates a ‘Well Integrity Diagnostic Report,’ ” say the authors of paper SPE 102524. Managers accountable for particular areas, lead operators, and other responsible individuals are kept informed of well status through another report generated each morning. This “Area Management Report” includes sections listing wells with pressure greater than the maximum allowable working pressure, for example, or wells needing safety valves. It also provides Key Performance Indicators such as “Put on Production” times for new wells and water-injection targets.

Cradle-to-grave well-integrity management (WIM) may be complex, but implementation of WIM initiatives are being proved attainable by BP at Prudhoe Bay, Alaska. The paper’s authors discuss how a WIM system at Prudhoe Bay has been evolving since field startup in 1977 (Fig. 1).

Fig. 1—Well integrity is a factor during all phases of a well’s life,
including design, drilling, completion, operation, service, and abandonment.

Because some wells have a lifetime of 100 years that entails sidetracks and a final abandonment that is expected to last forever, integrity management can be a daunting task. It can also present potential conflicts with production delivery contracts because of resources being diverted to well mechanical evaluations and wells being shut in. Also, interventions associated with mechanical anomalies that do not affect production may receive a lower priority and lead to backlogs of wells with anomalies.

Fig. 2—Primary (blue) and secondary (red)
well-barrier systems in a natural-flow well.

BP manages this integrity-management task in Alaska using a WIM system consisting of seven components—accountability and responsibility, well-operating procedures, well-intervention procedures, a tubing-and-casing-integrity program (Fig. 2), wellhead and tree maintenance, safety-valve maintenance, and knowledge of standards.

The focus of this paper is on the well-operations and -interventions phases. The authors review the rationale behind implementation of the WIM system in Prudhoe Bay, pointing out that engineering aspects of well integrity are receiving increasing attention; the issue of sustained casing pressure is also shaping current well-integrity practices and lessons learned.

The authors review well integrity as defined in the NORSOK Standard D-010 (developed by the Norwegian petroleum industry) with its effective summary of the facets of “application of technical, operational, and organizational solutions to reduce risk of uncontrolled release of formation fluids throughout the life cycle of a well.”

According to the authors, the rigorous conditions in Prudhoe Bay offered an excellent opportunity to institute a WIM program that is clearly not just a paper exercise. The WIM system daily addresses BP’s 1,330 wells on the North Slope of Alaska. The field includes 416 gas lift, 591 natural flow, and 323 injector wells. Daily monitoring and reporting combine BP’s needs with those of the primary state regulatory agency, the Alaska Oil and Gas Conservation Commission; address local events; and chronicle implemented solutions.

Monitoring for Clean CO2 Storage

The key enabler of planned large-scale implementation of geological CO2 storage is monitoring technology. The accelerated pace of deployment of CO2 Capture and Storage (CCS) necessitates that industry and government select cost-effective monitoring protocols and speak to one of the most important purposes of monitoring, one that is most relevant in the international context of climate change mitigation, according to paper SPE 102833 author Benson of the Lawrence Berkeley Natl. Laboratory. “For example, site operators, environmental regulators, and the public want to be assured that CO2 sequestration is safe,” Benson said. “Mineral right and surface right owners want to be assured that CO2 is not migrating beyond site boundaries. Policy makers, carbon credit traders, and investors want to be assured that CO2 is not returning to the atmosphere. Reservoir engineers want information to calibrate and validate simulation models of plume migration and predict long-term containment.”

Touching on the industry’s experience with the three existing geological sequestration projects—Sleipner, Weyburn, and In Salah, each of which uses a different combination of monitoring techniques—the author cites these and smaller-scale pilot test sites and theoretical studies as a source of confidence in the industry’s capacity for the geologic reservoir form of CO2 storage. In addition to focusing on the paths for implementation and types of monitoring under consideration, Benson reveals the basis for selecting among monitoring options and how methodology will impact inventory verification for accounting of greenhouse gas emissions in the U.S. and for carbon credit trading.

The toolbox of potential monitoring methods is large. This paper specifically covers cost-effective monitoring approaches for onshore geologic storage reservoirs, addressing leakage that can take place in the reservoir itself and in shallow saline formations that contain second accumulations of dissolved CO2 in groundwater, in vadose zone gas, and in terrestrial ecosystems, in addition to addressing the issue of direct emission of CO2 into the atmosphere (Fig. 3). For offshore storage reservoirs, the deeper components of the system are the same as for their onshore counterparts. Dissolution into seawater, transport with the water column, and discharge at the sea/air interface present special challenges in the area of monitoring approaches for offshore.

Fig. 3—Schematic showing the components of the surface
and how they may be used for CO2 monitoring.

The author sheds light on issues that arise in the context of CCS and carbon credit trading, including but not limited to project boundaries, permanence, and monitoring. Specific issues include accounting and responsibility for emissions to the atmosphere or seabed, responsibility for monitoring during and after the crediting period, methodology for site selection, monitoring methods and periodicity, and dealing with unexpected accidents. The issues of permanence are addressed in this paper.

“Maintaining flexibility in the implementation approach is important,” Benson said. “For example, some sites are ideally suited for detecting minor amounts of CO2 migration out of the geological storage reservoir into the overlying strata. Both seismic monitoring to detect small second accumulations and pressure monitoring to detect migration up wells or faults could be sufficient to conclude that emissions are negligible. At other sites, such as those without secondary seals, a direct surface-based emissions monitoring program may be more appropriate.”

Treating the geological storage reservoir as an emission source has a distinct advantage for inventory verification purposes, she said. Emissions are easier to measure than underground storage inventories. Quantifying in-situ inventory would be difficult because as CO2 is injected into a geological storage reservoir, some fraction of it remains as a separate phase, some dissolves into or mixes with the in-situ formation fluids (oil or water), and some is converted to minerals. Benson notes that the major question becomes, “How are emissions from the geological storage reservoir determined, and with what level of detection and precision?”

A hypothetical storage project is presented as an example of how a geologic storage reservoir should be monitored through the use of defined detection limits and as an example of whether the approach is defensible with regard to the effectiveness of CCS as a greenhouse gas mitigation technique.

Experience in Megaproject Management

Five megaprojects executed within the past 10 years by Saudi Aramco have drawn industry attention for swift resolution of technical and logistical issues, optimizing project scope, and attaining full control of quality and schedule. Two of these projects received the Project Management Inst. Project of the Year award, and one was honored at the 2005 Intl. Petroleum Technology Conference. Megaprojects are defined within Saudi Aramco as projects or programs that exceed U.S. $1 billion in value. SPE 103038 authors John Palmer et al. disclose Saudi Aramco’s proven internal processes for project implementation on five more such megaprojects to be completed in the next few years.

“Saudi Aramco has chosen to publish this paper to share successful processes in an environment where successful megaproject outcomes have been the exception rather than the norm, in the hopes that others can learn from our experience,” said the authors. “The Saudi Aramco motto is ‘Energy to the World.’ Effective execution of megaprojects is one of the key ingredients in meeting this commitment, and sharing our success may enable others to do the same.”

“On time and on budget” constraints continue to challenge even the most seasoned organizations. The authors detail how the Ras Tanura Refinery Upgrade Program, the Shaybah Project, the Hawiyah and Haradh gas plants, and the Qatif and Abu Safah field developments were planned and brought to fruition (Fig. 4). Such megaprojects were the order of the day early in Saudi Aramco history, and the company experienced a resurgence of megaprojects again beginning in the early 1990s. This trend continues with new projects, including the Hawiyah natural-gas-to-liquids recovery plant (Fig. 5); the Khursaniyah, Khurais, and Manifa oilfield developments; and the Shaybah field expansion.

Fig. 4—Locations of several Saudi Aramco mega-projects.

Fig. 5—The Hawiyah gas plant processes 1.6 Bcf/D of non-associated sour gas
from the high-pressure Khuff and Jauf gas reservoirs in the Ghawar field.

“Saudi Aramco facilities tend to be very large compared to similar facilities worldwide, with the average gas/oil separation plants at 300,000 B/D to process oil, water, and gas from wells averaging 5–10,000 B/D each,” say the authors. “Pipelines averaging 42 to 60 in. transport the oil to terminals with a shipping capacity up to 8 million B/D.”

In-place initiatives, as well as initiatives for further improvement, are presented complete with supporting background information. Ongoing factors contributing to success include a megaproject operating structure that addresses integrated team continuity, executive sponsorship, and formalized best practices adapted from the Construction Industry Inst. in addition to extensive benchmarking, internal project-execution workshops, target setting, and performance indicators using a balanced scorecard.

The authors discuss how Saudi Aramco accomplishes freezing the project scope following the Project Proposal stage, how best practices (including constructability, value engineering, and lessons learned implemented during design, procurement, and construction) are defined and implemented, as well as other means that are used to achieve schedule compression.

The authors trace the learning curve on the completed projects, including the prominent Shaybah project, built in one of the harshest environments on the planet. The project called for a new 640-km pipeline to Abqaiq plants, reinjection of waste water and gas to maintain reservoir pressure, total self-sufficiency with cogeneration, a Boeing 737-capable airport, residential and industrial facilities, and a 400-km road through the desert. Updates are also offered on the scope of the five current megaprojects.

Confidence in Estimating Hydrocarbon Volumes

A type-curve approach, underpinned by simplified equivalence charts, can allow petrophysical evaluations to be screened and, thereby, can reduce the risk of underestimating hydrocarbon saturation. SPE Paper 103075 presents evidence that type curves can be used in this way with minimal input data (Figs. 6a and 6b). While type charts are not intended to displace traditional petrophysical practices, according to the author, they do allow individual reservoirs to be examined from a broader perspective. When used in this new application, type curves yield information about reservoir behavior within a generic frame of reference.

Fig. 6a—Electrical type chart for fully water-saturated conditions at 25°C. A is the Archie
region; B is the non-Archie region; C is the severely non-Archie region. The critical (dashed)
curve subdivides regions B and C according to data-acquisition protocol.

Fig. 6b—Electrical type chart for partially water-saturated conditions at 25°C. Data point Y
lies in the non-Archie subregion B1 to the left of the critical curve. This location determines
the optimum approach to core and log analysis for the corresponding reservoir.

“Overall, in applications to problematic reservoirs, the type-curve approach has delivered higher values of hydrocarbon-filled porosity than were reported previously,” said Paul F. Worthington, a senior technical manager with Gaffney, Cline & Assocs. “This is because reservoirs that defy textbook character are usually evaluated conservatively. Another benefit, and a particular strength, is that the type-curve approach to the evaluation of hydrocarbon saturation is set totally within the realm of electrical measurements and is not distorted by the introduction of other physical properties such as fractional shale volume. However, to apply the curves in a hydrocarbon zone, one needs an estimate of irreducible water saturation. That is why the type curves are intended for application to log data away from those key intervals that are used to set up and calibrate the method.”

Seven case histories, selected because of the varied nonconformance of the subject reservoirs with textbook character, are used to demonstrate how the application of the type curves can provide quality assurance in evaluating water saturation and how pre-existing data from other reservoirs can be examined as potential analogs. The example reservoirs are the Azeri-Chirag-Guneshli field offshore Azerbaijan, a major reservoir system on the northwest shelf of Australia, the Cauvery basin offshore southeastern India, the Meruap field in Sumatra, the volcanic tuff Teradomari reservoir in northern Japan, stacked sandstone reservoirs from Argentina, and the Malay basin offshore eastern peninsular Malaysia.

In the Meruap field, the best estimate of hydrocarbon saturation was more than 30 saturation units higher than was reported previously. In another instance, the difference was 25 units. These are extreme cases, but they do demonstrate the potential degree of uncertainty.

“Type curves use very basic concepts that have been available for more than 30 years,” said Worthington. “To date, I have not seen any core data that do not conform to the curves within the limits of measurement uncertainty. The type-curve approach affords an opportunity to place petrophysical evaluation within a generic framework for quality-assurance purposes.”

The author reiterates the objective of type curves—to allow electrical data to be plotted on generalized charts for purposes of comparison. Data overlays of the three reservoir classifications (Archie, non-Archie, and severely non-Archie) can lead to an early identification of appropriate methods for the petrophysical evaluation of water saturation in the field under investigation and ultimately to an assessment of uncertainty.

Also presented is a set of equivalence charts constructed using basic petrophysical properties. The equivalence charts provide an indication of whether or not the type curves are needed to support reservoir evaluation. Where the curves turn out to be necessary, the charts provide an immediate assessment of the degree of departure from Archie conditions. Generic interpretive workflows that avoid use of specific shaly-sand models are offered to aid in the petrophysical interpretation of low-salinity and shaly reservoirs. This is done by allowing the input log data to drive the quantification of porosity and saturation exponents (which conventional practices may not deliver reliably for these problematic reservoirs).

Improved Drilling-Fluid Characterization

Use of a Dynamic High-Angle Sag Tester (DHAST) reduced the possibility of dynamic and static settling (sag) of barite particles on a Gulf of Mexico (GOM) well and prevented an unnecessary treatment to the mud system in another GOM well. According to the authors of paper SPE 103088, the new testing apparatus greatly improves the precision of sag measurements over previous techniques and more closely simulates downhole conditions. Requiring only a 50-mL sample for analysis, the tool takes measurements at prescribed shear rates and elevated temperatures and pressures to 350°F and 10,000 psi.

“Most sag characterization has been done at or near ambient conditions,” said author Murphy. “Since drilling-fluid properties are sensitive to temperature and pressure, these are fundamental parameters that should be considered for investigation of any sag problem. Direct sag measurements can be taken under elevated conditions, and multiple testing can take place from a relatively small sample size.”

Sag can be defined as the phenomenon of a variation in mud density seen during circulation. Such a condition results in costly issues of lost circulation, sticking, or even complete loss of a wellbore. If settling is prolonged, the upper portion of the wellbore can lose mud density, lessening hydrostatic pressure in the hole, and a kick of formation fluid then can enter the well. The settlement rate can determine the margin between success and failure. “Better sag control helps to prevent unplanned variations in the equivalent circulating density of the system,” said Murphy. Drilling challenges continue to increase, with sag measurements becoming especially important in extended-reach wells.

Development of the prototype device first involved tests, lasting from 6 to more than 24 hours, of both oil-based and water-based field muds using an atmospheric apparatus. Interestingly, there was a lack of correlation observed between the fluid’s bulk rheology and its settling rate. This inability to confidently predict settling rates from rheology measurements emphasized the importance of accurate, direct measurements of settling rates under downhole conditions. Because the first apparatus offered insight into dynamic settling, but had too many limitations, development of a better apparatus began with a number of specific design goals.

The authors describe each component of the new device: sample cell, pressurization chamber, pressurization, control, and calibration. Testing procedures are also cited. Settling rates (Fig. 7) are analyzed by use of an algorithm that is still under development. Interpretation of test conclusions is based on previous experience and models.

Fig. 7—Summary for settling-rate results for three fluids.

According to the authors, there is no one settling rate that indicates that a fluid is a good fluid. Another important finding is that “the DHAST appears to measure a fundamental property of the sample. Dynamic settling rates are independent of the testing angle (Fig. 8).”

Fig. 8—Vertical vs. 45° settling for an oil-based drilling fluid.

Steerable Motors Still in the Running

The reality of the industry’s use of steerable motors vs. rotary-steerable systems (RSSs) in drilling is the subject of paper SPE 104268. According to author Warren, “A decade after field testing the first modern RSS, steerable motors still command more than 80% of the directional-drilling market.” Historical points regarding the evolution of steerable motors, such as the use of this technology guided with measurement while drilling (MWD), enabled the industry to drill complex well trajectories. In addition to tracking the performance improvements of positive-displacement motors, the benefits and limitations of these systems are presented. Early prototypes of RSSs are discussed, along with pointing out the specific improvements to RSSs that have made efficient drilling of challenging wells (such as horizontals) possible. RSS tools now account for more than 15% of the directional footage drilled (Fig. 9).

Fig. 9—The footage drilled with rotary-steerable tools has
steadily increased for the last 6 years.

According to the author, it is not simply a case of one method/technology vs. another. Both technologies have an appropriate place in the industry. A critical key to understanding the industry’s categorization and use of both steerables and RSSs is a tiered marketing approach and the fact that just because a well can be drilled using a certain system does not mean that the system is the most cost-effective way to drill it. Performance and cost are key factors in the decision of which technology to use. Reliability is a particularly important issue. “Lower reliability translates into higher operational cost for the operator and higher maintenance cost for the service provider,” said Warren.

The author also refers to a well-established product-development cycle in which products move from the high-end performance-based market to a price-driven commodity market. This process begins as the highest-tier market needs are satisfied and the product providers begin to move into the next-lower-tier market.

Warren notes that “RSSs have replaced the steerable motors in the highest market tier (deep water) and are well on their way to replacing them in the next tier . . . . As the technology matures, this process will continue until a cost-effective solution is provided for land wells . . . a cycle that may be relatively long.” Such a market shift occurs when a technology matures, shifting older technology to the lower-tier markets, and is replaced by the newest technology in the upper-tier markets. A distinction between point-the-bit and push-the-bit technology is made as it relates to marketing tiers.

Steerable motors that are guided by MWD systems are capable of drilling most of the wells that are currently being drilled, including 3D designer wells. The author notes that the industry has not abandoned work aimed at improving steerable-motor performance. New high-performance power sections are extending the operational envelope of steerable motors. Other improvements include providing better stabilization at the bit (Fig. 10). “In the hands of a skilled directional driller,” said Warren, “these systems can be used to drill most wellbore geometries consisting of a planar well plan, including relatively long horizontals.”

Fig. 10—Technology to improve the performance of positive-displacement motors has steadily improved.

While cost continues to be an issue with the use of RSS technology, a poll conducted by the Intl. Assn. of Directional Drillers showed that 69% of respondents believed that more than 40% of the current wells could benefit from the use of RSSs, indicating that the potential RSS market is much larger than the current market and that the primary growth potential is in lower-cost wells.

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