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Collaborating Authors
Drillstem/well testing
Abstract Cambay is one of the oldest basins in India producing hydrocarbons since 1960's. It stretches almost 400 kilometers from south of Rajasthan to south of Gujarat in the western part of India and covering 53,000 sq. Km of total area. Cambay basin is contributing almost one-third of India's total onshore oil production. Raising production from Cambay basin is a considerable challenge as major producing fields are all Brownfield's. Hydraulic Fracturing (HF) is in use since 1980's to stimulate and enhance production from average to poor quality sands of Cambay basin. HF leads to better production results and has helped in enhancing production from this region for a long time. HF success ratio in stimulating these reservoirs dwindled significantly in the last decade due to continuous exploitation and decrease in saturation and reservoir pressures in the area. Enhancing fracture effectiveness & conductivity and reducing pressure drop within fracture was key to overcome this challenge and take the production to the next level. Maximizing conductivity of proppant pack has its own inherent limitations and this led to the application of channel fracturing for the first time in India in the Cambay basin. Channel fracturing results in decoupling fracture conductivity from proppant pack conductivity and results in infinite fracture conductivity, longer effective fracture half-lengths & reduction in pressure drop in the fracture. Creating stable fracture channels is highly dependent on rock mechanical properties and first hand evaluation of this decides applicability of this technology in a particular field/sand. This paper discusses the production results of wells treated with open channel fracturing compared to production results of offset wells stimulated by Conventional fracturing technology. Then it sheds light on basic requirement and key factors to be able to decide applicability of this technology in a particular field/sand. In the end applicability of this novel technology in all the major fields of Cambay basin will be discussed with the overall scope of redevelopment of all the major brown-fields of India.
- Asia > India > Rajasthan (1.00)
- Asia > India > Gujarat (1.00)
- North America > United States > Wyoming > Campbell County (0.44)
- Geology > Geological Subdiscipline > Geomechanics (0.88)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
The Use of Real-Time Downhole Pressure and Distributed Temperature Surveying in Quantifying the Skin Evolution and Zone Coverage in Horizontal Well Stimulation
Balto, Abdulelah A. (Saudi Aramco) | Qahtani, Hassan B. (Saudi Aramco) | Kilany, Khaled A (Saudi Aramco) | Baez, Fernando (Schlumberger) | Elsherif, Tamer (Schlumberger)
ABSTRACT Fiber optic enabled coiled tubing (FOECT) has been commonly used in qualitatively evaluating reservoir matrix chemical treatment in real time during the past couple of years. During this period, attempts of transforming qualitative evaluations to quantitative ones were made. The quantitative evaluation is based on two simultaneous criterions. The first one is a downhole pressure diagnostic plot (pressure transient analysis) created instantinuously using real-time acquired data by the downhole gauges. The second is an estimate of the zonal coverage based on the resulting temperature profile plot before, during and after a pumping treatment. Pressure transient analysis gives the skin as a direct output, while the cooling down/warming up DTS profiles identifies where the treatment fluids went in the formation, hence identifying the damaged zones. It is strongly recommended to combine well testing analysis techniques with zone coverage evaluation in highly deviated and horizontal completed wells in both clastic and non-clastic rocks. Basically, deriving the skin from the injectivity test (pretreatment) and the skin from the post flush (post-treatment) provides an evaluation matrix treatment effectiveness. A comparison between formation damage "skin" before and after the treatment was performed on the spot, revealing positive results of nearly uniform distribution of treatment fluids, and skin value reduction across the 3400 ft horizontal section. Following the innovative procedures executed in well-A, different techniques were proposed, providing time and cost savings; raising the operational excellence expectations levels higher than expected for an offshore environment. The application of FOECT technology helped to minimize uncertainties during treatmentevaluation, and enhanced treatment distribution and placement. In addition to establishing more accurate and reliable Nodal Analysis and production forecast models.
- North America > United States (0.28)
- Asia > Middle East > Saudi Arabia (0.28)
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 148833, ’Methodologies, Solutions, and Lessons Learned From Heavy- Oil Well Testing With an ESP, Offshore UK in the Bentley Field, Block 9/3b,’ by Barny Brennan, SPE, Charles Lucas-Clements, and Steve Kew, SPE, Xcite Energy Resources; Yakov Shumakov, Lawrence Camilleri, SPE, Obinna Akuanyionwu, SPE, and Ahmet Tunoglu, SPE, Schlumberger; and Steve Hayhurst, SPE, and John Simpson, ADTI, prepared for the 2011 Canadian Unconventional Resources Conference, Calgary, 15-17 November. The paper has not been peer reviewed. Production from heavy-oil fields in the UK continental shelf (UKCS) has become possible over the past 10 years. Despite substantial reserves in the UKCS of crudes with gravitiy of 20°API and lower, most of the activity has been exploration and appraisal drilling. The main reason for restricted activity has been high uncertainty of reservoir and fluid properties. A method was developed to find the most-suitable technology for testing these heavy-oil wells by use of an electrical submersible pump (ESP). Introduction Most UKCS production has been light oil, 30°API and lighter. The UK Department of Trade and Industry estimates 9.2 billion bbl of heavy oil in place in the UKCS. Many of the UKCS heavy-oil fields were discovered in the 1970s, but were considered uneconomical. Although considerable quantities of these UKCS heavy-oil resources with gravity lower than 20°API exist, the uncertainties in reservoir and fluid properties have con-fined activities mostly to exploration and appraisal testing. Inherent operational complexities also limit the use of conventional appraisal well-testing techniques. The Bentley field contains 10 to 12°API oil (620-cp in-situ oil viscosity) in the Dornoch sandstone reservoir. The Bentley fluid is much heavier and more viscous than crudes at any field currently producing in the North Sea. Discovered in 1977 in a water depth of 371 ft, the field is 100 miles east of the Shetland Islands on the edge of the heavy-oil belt in the northern North Sea. The average reservoir depth is 3,700 ft. Since discovery of the field, several well tests have been performed in attempts to produce Bentley crude to the surface. However, technical issues with downhole-equipment reliability and the application of traditional well-testing techniques in the heavy-oil formation yielded unsuccessful tests with no flow to surface. Vertical Well 9/3b-5 was drilled in 2007 and tested in January 2008, flowing the first Bentley crude to the surface. The results of the test provided vital reservoir information and lessons learned for future operation planning. In 2010, the operator drilled a horizontal well into the upper Dornoch sand-stone to gather additional data through coring and logging. A short well-testing program was used to collect representative downhole pressure/volume/temperature (PVT) samples to validate flow at commercial rates. A drillstem-test (DST) string and new operational procedures based on the lessons learned from the previous well tests were used.
- Europe > United Kingdom > North Sea > Northern North Sea (0.76)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.25)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.55)
- Europe > United Kingdom > North Sea > Northern North Sea > Viking Graben > P1078 > Block 9/3b > Bentley Field > Dornoch Formation (0.99)
- North America > Canada > Alberta > Bentley Field > Anadarko 11C St. Paul 11-15-58-7 Well (0.98)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Technology Focus The value of information has a ubiquitous and sometimes pervasive role in modern well testing. From exploration to field management to surveillance, well-test practitioners deal with a wide array of measurements (e.g., pressure, flow rates, temperature, and fluid analysis) that, more often than not, encompass large amounts of data. This is particularly true for long-term-production-data analysis of established fields, and one can argue the same for any current pressure-transient analysis that also has benefited from improved and more-robust data-acquisition available today. Likewise, dynamic information through downhole testing equipment can be acquired in real time—wirelessly and at sampling frequencies that were not possible only a decade ago. Yet what seems to be a relative abundance of data often is challenged by the complex environments in which we operate and by our need to assess its value against associated costs and business risks. One way to look at this is under the premise that, while “perfect” information is beneficial to have, it also is costly to acquire and economically inefficient. Is there a unique answer in our choice of type curves, material balance, or specialized graphs? Should we account for multiphase flow or rock compaction? More importantly, what is the value of the next-best substitute for the information we require? And can this substitute information still allow us to meet our testing objectives? Herein lies the delicate balance between our choices of risk and uncertainty, which brings us to the message of this feature: We should not look for data-rich, but information-rich, content that meets our testing needs. The papers selected for this feature describe exciting advances and opportunities in well testing. They also show that the proper use of advanced techniques can lead to maximizing the value of the information at hand, even in hostile and unconventional situations. Recommended additional reading at OnePetro: www.onepetro.org. SPE 143592 Assessment of Rate-Dependent Skin Factors in Gas-Condensate and Volatile-Oil Wells by A.C. Gringarten, SPE, Imperial College London, et al. SPE 146450 3D Multiphase Streamline-Based Method for Interpretation of Formation-Tester Measurements Acquired in Vertical and Deviated Wells by Hamid Hadibeik, SPE, University of Texas at Austin, et al. SPE 142818 Application of IFOT in Tight Gas as a Reservoir-Surveillance Technique by E. Pinto, BP plc, et al.
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 147506, ’Pressure-Transient and Production-Data Analysis of a Horizontal Well in an Unconsolidated Formation in Frade, Brazil,’ by Yan Pan, SPE, Russ Ewy, SPE, Don Ringe, SPE, Medhat M. Kamal, SPE, Ralph Affinito, SPE, and Oluwole Sotunde, SPE, Chevron, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed. Frade Asset is a medium-heavy-oil field in the northern Campos basin, approximately 75 miles offshore Rio de Janeiro in 3,500-ft water depth. The structure is a low-relief anticline with two main fault blocks consisting of four stacked unconsolidated reservoirs. The field produces from nine horizontal oil wells with three vertical water-injection wells to maintain reservoir pressure. Continuous well monitoring and reservoir characterization are key to cost-efficient development in this deepwater subsea field. Introduction The development strategy for the field includes horizontal production wells and deviated injection wells to maintain reservoir pressure. The asset-management team realized the challenges of this particular field and made the decision to install permanent downhole gauges in every production and injection well drilled, with a reservoir-surveillance plan in place to monitor well and reservoir performance. Active reservoir surveillance enabled engineers to make sound and quick operating decisions, such as shutting in wells, changing chokes, or planning well interventions on the basis of dynamic data collected continuously at wells. It also provided real-time information for improved reservoir characterization, model forecasts, and optimized development plans. Because data stream in continuously, the cycle from data collection to updating reservoir models to forecasting field performance to optimizing development could be shortened. Example Well: Producer 2 Well Producer 2 is in the upthrown fault block, as shown in Fig. 1, and had an original reservoir pressure of 3,079 psia and a reservoir temperature of 110°F. The net pay thickness is approximately 42 m, and the horizontal well was drilled 30 m above the sealing bottom of the reservoir. The well trajectory was parallel to the fault to the southwest and to the axial fairway edge to the northeast. The well was completed with an openhole gravel pack, and the total completion length was 507 m. The permanent downhole gauge was installed above the top of the gravel-pack completion.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.54)
- Geology > Structural Geology > Fault (0.45)
- Information Technology > Architecture > Real Time Systems (0.70)
- Information Technology > Data Science (0.62)