Offset Wells Research Articles

逸泥対策用・混合ファイバー

The losses have been general issues and challenges for all wells, which are loss occurs before running casing and cement the liner, uncertainness about the number and depth of the loss zones, a long open hole but no temperature log and no caliper log when getting loss. To meet these challenges, an innovative blend of fibers is designed to cure losses specially caused by the presence of natural fractures (it is not designed for induced fractures). This blend fiber contains two very different types of fibers. One is relatively thick and stiff, and the other is thin and significantly more flexible. In general, the thick and stiff fiber acts as an anchor and also contributes to reinforce the fiber network. The thin and flexible fibers entangle with the stiff fibers also have the tendency to invade the loss zone while remain entangle with the fiber net, thus helps to secure and stabilize the immobilized plugs containing fibers and solids must be suspended properly by the viscous base fluid. To secure losses, the blend fibers are mixed into the pill at the fieled and made the reinforced composite mat. It comprises the optimized solid package and the base viscous fluid besides the engineered two fibers. The fiber plugging mechanism of this pill works on four steps, which are “Disperse”, “Bridge”, “Plug” and “Sustain”. The pill contained blend fibers is designed to enter the well information with the software, then, the pill formation and placement guidelines are generated by the software. The loss has been cured by the pill based on the experimental results of offset wells in the past, on the other hand, this blend fibers with software is trying to propose more engineering solutions for losses. This paper will introduce the innovative blend of fibers.

Concurrent in-situ measurement of flow capacity, gas content and saturation

A new core-less testing capability has been developed to provide concurrent measurements of coal seam flow capacity and gas content at in-situ conditions. The fluid-based measurement principles are intended to overcome time constraints, accuracy limitations, and cost implications of discrete measurements attributed to traditional ex-situ measurements on core samples. Details of measurement principles, associated enabling technologies, and generic test procedures have been disclosed in a previous publication. In 2012 a number of field trials were conducted with this new service for both coal mine operators and CSG operators. This peer-reviewed paper will detail pre-job planning, well site execution, and data analysis for one of these trials, which involved testing several seams across two wells, and will illustrate comparison with data acquired using conventional testing techniques from offset wells. This peer-reviewed paper will also highlight key learnings and overall performance, and explain how the learned lessons can be applied to improve testing efficacy and data quality.

Pressure-Sink Mitigation for Horizontal Completions in the Haynesville Shale

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 159089, ’Horizontal Pressure-Sink-Mitigation Completion Design: A Case Study in the Haynesville Shale,’ by Robert C. Martinez, SPE, Josh Rosinski, SPE, and Doug Dreher, SPE, Exco Resources, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8-10 October. The paper has not been peer reviewed. Pressure sinks caused by production from an initial well can impair future completion effectiveness unless steps are taken to mitigate the effects. Pressure sinks exist in an area that was stimulated previously or has a reduced pore pressure, which then creates a path of least resistance for a subsequent nearby stimulation. Pressure-sink-mitigation (PSM) techniques are vital for successful Haynesville shale development. PSM techniques applied to Haynesville shale wells represent a potential breakthrough on how to mitigate the effects of pressure sinks effectively and increase the ultimate gas recovery of the unit. Introduction The Haynesville shale-gas play covers the east Texas/north Louisiana border area (Fig. 1). Hydraulic-fracture stimulation is critical to produce natural gas from the nanodarcy-permeability rock. Initial designs used a hybrid treatment (i.e., conventional job) that included a slick water pad followed by low concentrations of 100-mesh sand spaced with slick water sweeps. Fracture modeling showed that these hybrid treatments created very long fracture half-lengths. Fig. 2 shows how wells producing as far as 1 mile in an east-northeast/west-southwest orientation from an ongoing fracture treatment often would exhibit a pressure response during the fracture treatment of the offset well. This well interaction was the first indication that a hybrid slickwater treatment could be influenced by pressure sinks. Early in the development program, 80-acre offset wells were drilled to evaluate infill-well performance. A conventional completion design and a PSM design (PSM 1) were used on the off-set wells, and performance was reduced significantly. This reduced performance was not limited to 80-acre offset wells. When designing around pressure sinks, production from an existing well within a 1-mile radius could affect performance significantly, and could risk several wells in a development plan. Subsequent stimulations had a similar effect on offsets during and after the stimulation. It became apparent that different completion designs would be needed.

Characterizing seismic-scale faults pre- and post-drilling; Lewisian Basement, West of Shetlands, UK

Abstract Three exploration wells drilled in the West of Shetlands targeted crystalline Lewisian Basement as the primary reservoir. The objective of these wells was to demonstrate the presence of movable oil in basement and the viability of fault zones within the Lewisian Basement as an exploration target. Lewisian Basement reservoir properties were defined pre-drill through a combination of fieldwork, offset well data, global basement analogues and detailed 3D seismic interpretation. Dip, azimuth and similarity attributes were analysed within the 3D seismic volume in order to delineate the fault network, complimenting manual fault interpretation. Once the fault network had been defined, two fault zones were chosen as a reservoir target for an inclined basement well, based on their length and location within the reservoir. After drilling over a kilometre of basement across three wells, significant understanding has been gained of the basement reservoir. The comprehensive suites of log data obtained from the wells have allowed some leading edge techniques to be used to bridge the gap between wellbore data and seismic data, with fault zones identified from log data tying to fault zones that had been interpreted using seismic data. The well results have been used to feed back into the predicted fault model to increase the number of mapped faults and to constrain rock properties including lithology and fracture frequency. This paper summarizes the above process and provides specific details regarding the seismic characterization of the fault network.

Casing While Drilling (CwD): A New Approach To Drilling Fiqa Formation in the Sultanate of Oman—A Success Story

SummaryHighly reactive Fiqa shale used to compel well engineers in the Sultanate of Oman to plan drilling phase of surface and intermediate sections primarily based on time exposure to aqueous drilling fluid water-based mud (WBM). The new approach of drilling the time-dependent Fiqa formation using casing-while-drilling (CwD) allows well engineers to plan prospective top/intermediate wellbore sections differently by enhancing the overall drilling performance. This reduces the risk of setting casing strings at unplanned depths, getting pipe stuck, or reaming continuously when drilling with conventional drillstring. The technical feasibility study, risk assessment, planning, execution, and the lessons learned during the process of drilling two top-section pilot projects are described in this document. The CwD team compares the drilling performance of several offset wells and suggests actions to improve the CwD technology in Oman.Two 17½ - and 22-in. surface sections were drilled successfully with large-diameter casing strings and reached 754- and 894-m measured depths, respectively. The implementation of the CwD concept reduced the overall drill/case phase time up to 40%, in comparison with the average using conventional drilling in those fields. Exposure time of Fiqa to aqueous environment was reduced by eliminating conditioning trips and nonproductive-time (NPT) associated with wellbore instability. Drilling both sections with non-retrievable 17½×13⅜-in. and 22×18⅝ -in. CwD systems did not require modification of well design or rig. The optimization of this technology will support its implementation as the conventional drilling approach in some fields in Oman.

Cemented-Liner- vs. Openhole-Packer- Completed Tight Gas Horizontal Wells

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 152185, ’A Direct Comparison of Hydraulic-Fracture Geometry and Well Performance Between Cemented-Liner- and Openhole-Packer-Completed Horizontal Wells in a Tight Gas Reservoir,’ by Murray Reynolds, SPE, Susan Thomson, and Faezeh Peyman, SPE, TAQA North Ltd., and Allan Hung, David Quirk, SPE, and Shaoyuan Chen, Trican Well Service, prepared for the 2012 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, 6-8 February. The paper has not been peer reviewed. With the introduction of multiple-fractured horizontal-well(MFHW) technologies and with a much better definition of the geology, a large unconventional-resource play has developed in the Glauconitic formation in central Alberta, Canada, which could contain in excess of 5 Tcf of gas in place plus associated natural-gas liquid. Microseismic technology was used in a pilot project that was designed to test the completion effectiveness of a cased-and-cemented liner vs. an openhole-packer system in this tight gas reservoir. Introduction Several operators are developing this liquid-rich tight gas play by use of MFHW technologies. While most of the horizontal wells used openhole-packer systems with ball-and-sleeve fracture-isolation technology, the completion effectiveness of this technique was uncertain in this formation. A large vertical-well population within the area presented an opportunity to use downhole-microseismic techniques for direct measurement of the hydraulic-fracture growth from two offset horizontal wells. Two vertical microseismic-observation wells were located between two proposed horizontal wells, with a mid-point-separation distance of approximately 600 m. Each horizontal well would have approximately 1200-m horizontal exposure in the reservoir and would be completed with eight large hydraulic-fracture treatments (approximate fracture spacing of 170 m along the horizontal well). One horizontal well would be equipped with the open-hole ball-and-sleeve completion system, while the other would be equipped with a fully cemented liner in the horizontal section. The latter well would use ported collars at the points of fracture origination, and these would be shifted open by use of coiled tubing. Background Depths in the Westerose area are approximately 1840 m, increasing to 3450 m in the Deanne field. The pore-pressure gradient varies with location and depth, from slightly under-pressured in the northeast (8.5 kPa/m) to significantly overpressured in the southwest (16.1 kPa/m). Total gross zone thickness varies between 15 and 25 m, with porosities ranging from 6 to 15%. The water saturation is believed to be sub-irreducible, ranging from 25 to 30%, and no significant formation water is produced anywhere in the trend. This project has a series of regional coals that cap the Glauconitic sands. The coals vary in thickness from approximately 0.5 to 5 m, are areally extensive, and are good markers for geological mapping and correlations.

Managed-Pressure Drilling: Beyond the Conventional Limit in a Deepwater HP/HT Well

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 142312, ’Managed-Pressure Drilling Enables Drilling Beyond the Conventional Limit in a Deepwater HP/HT Well,’ by F. Kernche, D. Hannegan, SPE, E. Sammat, and M. Arnone, SPE, Weatherford, prepared for the 2011 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 6-8 September. The paper has not been peer reviewed. Managed-pressure drilling (MPD) was used successfully on an offshore high-pressure/high-temperature (HP/HT) well. Wells in this field and other offset wells in the area had faced many problems including inadequate mud management resulting from depleted or overpressured zones, influxes, mud losses, and differential sticking. This well was drilled with a proprietary MPD system that is a closed-loop method of monitoring and controlling flow and pressure. Introduction MPD uses a closed and pressurized drilling-fluid (mud) circulating system that facilitates drilling with precise management of the wellbore-pressure profile. The primary objective of MPD is to optimize drilling processes by decreasing nonproductive time (NPT), mitigating drilling hazards, and enabling the drilling of otherwise technically or economically undrillable highly complex prospects. Because MPD addresses NPT, the technology is of greatest potential benefit to expensive offshore-drilling programs. Although MPD was been practiced safely and efficiently from all types of offshore rigs, yielding the desired results, it still is considered a relatively new technology to many offshore drillers. The uptake in offshore MPD applications is, in part, because drilling is taking place in greater water depths, through depleted zones or reservoirs, and into narrow or relatively unknown equivalent-mud-weight (EMW) drilling windows. Technical Justification The application of MPD technology can optimize the drilling process by decreasing NPT and mitigating drilling hazards associated with conventional drilling techniques. Most importantly, the MPD system reduces drilling costs and limits drilling-cost uncertainty by: Avoiding conventional-drilling NPT problems, such as lost circulation, shale instability, kicks, nuisance-gas zones, and differential sticking. Increasing the rate of penetration, increasing bit life, and decreasing trip frequency. Enabling access to potential assets/reservoirs previously believed to be undrillable by improving health, safety, and environmental (HSE) conditions. MPD System The MPD system used in this specific application consisted of a proprietary control algorithm to identify influxes and losses on a real-time basis and a choke at surface to apply backpressure to maintain well control. The system allows making drilling decisions on the basis of actual pressure and flow data rather than by use of predicted downhole parameters based on hydraulic models, and it provides real-time monitoring of the well-bore parameters while drilling.

Modeling of CBM production, CO2 injection, and tracer movement at a field CO2 sequestration site

Sequestration of carbon dioxide in unmineable coal seams is a potential technology mainly because of the potential for simultaneous enhanced coalbed methane production (ECBM). Several pilot tests have been performed around the globe leading to mixed results. Numerous modeling efforts have been carried out successfully to model methane production and carbon dioxide (CO{sub 2}) injection. Sensitivity analyses and history matching along with several optimization tools were used to estimate reservoir properties and to investigate reservoir performance. Geological and geophysical techniques have also been used to characterize field sequestration sites and to inspect reservoir heterogeneity. The fate and movement of injected CO{sub 2} can be determined by using several monitoring techniques. Monitoring of perfluorocarbon (PFC) tracers is one of these monitoring technologies. As a part of this monitoring technique, a small fraction of a traceable fluid is added to the injection wellhead along with the CO{sub 2} stream at different times to monitor the timing and location of the breakthrough in nearby monitoring wells or offset production wells. A reservoir modeling study was performed to simulate a pilot sequestration site located in the San Juan coal basin of northern New Mexico. Several unknown reservoir properties at the field site were estimatedmore » by modeling the coal seam as a dual porosity formation and by history matching the methane production and CO{sub 2} injection. In addition to reservoir modeling of methane production and CO{sub 2} injection, tracer injection was modeled. Tracers serve as a surrogate for determining potential leakage of CO{sub 2}. The tracer was modeled as a non-reactive gas and was injected into the reservoir as a mixture along with CO{sub 2}. Geologic and geometric details of the field site, numerical modeling details of methane production, CO{sub 2} injection, and tracer injection are presented in this paper. Moreover, the numerical predictions of the tracer arrival times were compared with the measured field data. Results show that tracer modeling is useful in investigating movement of injected CO{sub 2} into the coal seam at the field site. Also, such new modeling techniques can be utilized to determine potential leakage pathways, and to investigate reservoir anisotropy and heterogeneity.« less

Interpreting Microseismic Measurements: Practical Guide

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 144067, ’A Practical Guide To Interpreting Microseismic Measurements,’ by C. Cipolla, SPE, S. Maxwell, SPE, M. Mack, SPE, and R. Downie, Schlumberger, prepared for the 2011 SPE North American Unconventional Gas Conference and Exhibition, The Woodlands, Texas, 14-16 June. The paper has not been peer reviewed. Thousands of hydraulic-fracture treatments have been monitored in the past 10 years with microseismic mapping, providing measurements that show a surprising degree of diversity in event patterns. Interpretation of the microseismic data to determine the geometry and complexity of hydraulic fractures continues to focus on visualization of event patterns and on qualitative estimates of the stimulated volume, which has led to wide variations and inconsistencies. Comparing the energy input during a hydraulic-fracture treatment with the resultant energy released by microseismic events demonstrates that the seismic deformation is a very small portion of the total deformation. Introduction Hydraulic-fracture microseismic monitoring (MSM) has increased our understanding of fracture propagation, especially in unconventional reservoirs. MSM, which is a straightforward application of earthquake-seismology principles, consists of the detection, location, and further analysis of extremely small seismic events induced by the fracturing process. Typically, multiple-receiver arrays are positioned over a 300- to 1,000-ft vertical interval in a single nearby offset well. The microseismic events usually are not detectable as discrete events at the surface, but only from other wellbores within approximately 3,000 ft of the fracture-treatment well. Typically, microseisms are represented adequately by a double-couple source, which implies shear slippage that releases stress over some area. In competent rocks, shear slippages occur on pre-existing planes of weakness as a result of the changes in stress and pore pressure induced by the fracturing process. When fracture growth is relatively planar, these changes in stress and pore pressure usually result in a narrow band of microseisms that clearly defines the azimuth and geometry of the hydraulic fracture. However, complex fracture behavior is often interpreted from microseismic data, as evidenced by very intricate event patterns with width/length aspect ratios greater than 0.5. MSM data have revealed a large variation in hydraulic-fracture growth, from relatively simple planar fractures to very complex fracture networks. Understanding fracture growth and the degree and nature of hydraulic-fracture complexity is essential to selecting the appropriate stimulation design and completion strategy.

Reservoir-Navigation System and Drilling Technology Maximize Productivity and Drilling Performance in the Granite Wash, US Midcontinent

Summary The Granite Wash unconventional gas and oil play of the US midcontinent has a multitrillion-cubic-feet-equivalent upside potential. The condensates and natural-gas liquids associated with this gas play make it one of the most-prolific and fastest-growing unconventional fields in North America. However, efficient extraction of hydrocarbons from the Granite Wash play poses drilling and geological challenges. The Granite Wash deposit has significant lateral variation, with extremely abrasive thinly bedded sandstones. Geological complexity of this field requires precise placement and navigation of the wellbore in real time to overcome the variable characteristics of the reservoir. To overcome these challenges, logging-while-drilling (LWD) technology was used in conjunction with geosteering. An azimuthal gamma ray image was used to determine formation bed dip and stratigraphic complexity within the reservoir. Multiple-propagation resistivity measurements were used to correlate position within the reservoir and indicate formation porosity. The LWD data was transmitted in real time by means of satellite to a remote reservoir-navigation center where the reservoir-navigation engineer incorporated the real-time data into the geological model. This strategy has been implemented to drill with excellent results, as compared with the offset wells. The initial production rate obtained was 19.4 MMcfe/D (cfe = cubic foot equivalent). The well was completed 10 days ahead of schedule, resulting in significant cost savings. With the successful implementation of real-time reservoir-navigation and drilling technology, the operator accelerated their drilling program. The results are significant organic production growth, improved drilling performance, precise placement of the wellbore, and significant reduction in rotating hours at lower drilling and production costs.

Intelligent Production Modeling Using Full Field Pattern Recognition

Summary Production-data analysis has been applied extensively to predicting future production performance and field recovery. These applications operate mostly on a single-well basis. This paper presents a new approach to production-data analysis using artificial-intelligence (AI) techniques in which production history is used to build a fieldwide performance-prediction model. In this work, AI and data-driven modeling are used to predict future production of both synthetic- (for validation purposes) and real-field cases. In the approach presented in this article, production history is paired with field geological information to build data sets containing the spatio-temporal dependencies among different wells. These dependencies are addressed by compiling information from closest offset wells (COWs) that includes their geological and reservoir characteristics (spatial data) as well as their production history (temporal data). Once the data set is assembled, a series of neural networks are trained using a back-propagation algorithm. These networks are then fused together to form the intelligent time-successive production-modeling (ITSPM) system. This technique uses only the widely available measured data such as well logs and production history of existing wells to predict future performance of the existing wells and production performance of the new (infill) wells. To demonstrate the applicability of this method, a synthetic oil reservoir is modeled using a commercial simulator. Production and well-log data are extracted into an all-inclusive data set. Several neural networks are trained and validated to predict different stages of the production. The ITSPM method is used to estimate the production profile for nine new wells in the reservoir. Furthermore, ITSPM is also applied to two giant oil fields in the Middle East. The first one has more than 200 wells and 40 years of production history. ITSPM's production predictions of the four newest wells in this reservoir are compared with their actual production. The second real field has hundreds of wells producing from multiple layers. The field has undergone waterflooding for almost its whole life. This case also shows the capabilities of this technique in more-complex scenarios and especially multiphase systems.

CO2 Injection Performance in the Fruitland Coal Fairway, San Juan Basin: Results of a Field Pilot

Summary The Pump Canyon CO2-enhanced coalbed methane (ECBM)/ sequestration demonstration in New Mexico has the primary objective of demonstrating the feasibility of CO2 sequestration in deep, unmineable coal seams through a small-scale geologic sequestration pilot. This project is not the first of its kind; several small- or large-scale pilots were already conducted previously in the United States [Allison Unit (Reeves et al. 2003) in the San Juan, Appalachian, and Warrior basins] as well as internationally [the Recopol (Reeves and Oudinot 2002) project in Poland, and the Yubari project in Japan, Canada, and Australia]. Additional pilots are currently under way. At the project site, a new CO2-injection well was drilled within an existing pattern of coalbed-methane-production wells. Primarily operated by ConocoPhillips, these wells produce from the Late Cretaceous Fruitland coals. CO2 injection into these coal seams was initiated in late July 2008 and ceased in August 2009. A variety of monitoring, verification, and accounting (MVA) methods were employed to track the movement of the CO2 in order to determine the occurrence of leakage. Within the injection well, MVA methods included continuous measurement of injection volumes, pressures, and temperatures. The offset production wells sampled gas-production rates, pressures, and gas composition through CO2 sensors, tracers in the injected CO2, time-lapse vertical seismic profiling, and surface tiltmeter arrays. A detailed study of the overlying Kirtland shale was also conducted to investigate the integrity of this primary caprock. This information was used to develop a detailed geologic characterization and reservoir model that has been used to further understand the behavior of this reservoir. The CO2-injection pilot has ended with no significant CO2 buildup occurring in the offset production wells. However, a small but steady increase in CO2 and N2 at two of the offset wells may have been an indication of imminent breakthrough. More recent gas samples are, however, showing a decrease in CO2 and N2 content at those wells. This paper describes the project, covering the regulatory process and injection-well construction, the different techniques used to monitor for CO2 leakage, and the results of the modeling work.

Successful Short-Radius Re-Entry Well in Deep-Gas Drilling in Saudi Arabia

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 139855, ’The First Successful Short-Radius Re-Entry Well in Deep-Gas Drilling in Saudi Arabia,’ by Shaker Al-Khamees, SPE, and Hope Okwa, SPE, Saudi Aramco, and Jaywant Verma, SPE, and Sukesh Ganda, SPE, Schlumberger, prepared for the 2011 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 1-3 March. The paper has not been peer reviewed. Successful short-radius sidetracking in a deep gas area in Saudi Arabia is presented. Well ANDR-XYZ was sidetracked from vertical at 12,242 ft and built inclination to 90°, with maximum dogleg severity (DLS) recorded as 39°/100 ft. Thereafter, a 2,400-ft-long lateral was drilled in the Khuff-B reservoir. The sidetracking and lateral were drilled because of deteriorating production. The time required for this work was 53 days vs. the planned 60 days. The short-radius sidetrack was one of three options studied and resulted in saving 45 rig days compared with the other options. The well also extended the frontier of drilling and workover options and enabled opportunities to re-enter several other wells in deep gas areas in Saudi Arabia. Introduction Most deep gas wells in Saudi Arabia are drilled in the southern Ghawar field. The Late Permian Khuff-B and Khuff-C stacked carbonate reservoirs are the main gas-producing zones at depths of 11,500- to 12,500-ft true vertical depth. Two types of casing designs are used in these deep gas wells: “K1” and “K2.” In the conventional K2 profile, 133/8-in. casing is set from the surface to 30 ft into the base of Jilh dolomite formation. A 12-in. section is drilled into the Khuff-C carbonate, and 95/8-in. casing is set. Thereafter, 83/8-in. hole is drilled across Khuff or pre-Khuff reservoir. In a typical K1 design, in place of the 133/8-in. casing, 95/8-in. casing is set 30 ft into the base of the Jilh dolomite formation. An 83/8-in. section is drilled into the Khuff-C carbonate, and a 7-in. liner is run. After setting the 7-in. liner, 57/8-in. hole is drilled to the target formation. Occasionally while drilling these wells, higher pressures are encountered in the base of the Jilh formation. Therefore, the K2 design is preferred over the K1 design because it provides the opportunity to set an additional casing string. At planning stages, off-set wells are studied to finalize casing design. Because drilling a slimmer hole is faster and less costly, the K1 design is preferred when there is no history of high pressure in offset wells. While planning workover operations on Well ANDR-XYZ, various options were studied from the perspectives of cost, time, and technical feasibility. The short-radius-sidetrack technically was the only economically acceptable approach. The full-length paper details the conventional long-radius drilling approach, drilling options, and planning and execution of the first successful short-radius well in deep-gas drilling in Saudi Arabia. The objective of the Well ANDR-XYZ L1 re-entry was to sidetrack from the original vertical well in the Khuff-B formation and drill a 57/8-in. lateral targeting the Khuff-B reservoir.

Drilling Highly Depleted Formations With Engineered-Particle Nonaqueous Fluids: South China Sea

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 139932, ’Drilling Highly Depleted Formations With Engineered- Particle Nonaqueous Fluids: South China Sea,’ by Michael R. Niznik, SPE, Adela Lawrence, SPE, and Sabine C. Zeilinger, SPE, ExxonMobil, prepared for the 2011 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 1-3 March. The paper has not been peer reviewed. A new engineered-particle nonaqueous-fluid (EP-NAF) system was used in the Malay basin of the South China Sea to drill through highly depleted sands at elevated densities. The fluid contains sized particles to bridge and prop open fractures as they occur during actual drilling operations. Formation integrity is gained immediately and does not require additional critical-path rig time. Background and Well-Design Overview The Malay basin in the South China Sea contains multiple oil and gas accumulations, some of which have been on production for several decades. Many of these mature fields have economically recoverable quantities of hydrocarbons but are challenging because depleted zones are adjacent to formations prone to wellbore instability. A four-well infill development program was planned in one of these mature fields. The field is 200 km offshore in 70 m of water. Several platforms were installed to develop the field, which has been producing for more than 20 years. Typically, tender-assisted platform rigs are used in this field. Well-Design Challenges and Planning All proposed wells would be side-tracked from existing donor wellbores. A variety of casing sizes was used in the donors, and exact cement tops were not known. The exact sidetrack point was engineered to take into account collision avoidance of offset wells, cement behind casing, formations in which to sidetrack, and dogleg requirements to meet geology and reservoir objectives. The target reservoir was the Group-J sands that lie below the Group-I reservoir, which was completed and put on production more than 20 years earlier. The pore pressure of the Group-I reservoir in the area where the proposed wells would penetrate was determined to be depleted to a 3.7-lbm/gal gradient. The target Group-J sands also were slightly depleted to a 6.8-lbm/gal gradient because of production in adjacent fault blocks. The targeted Group-J reservoir has lower-permeability sands compared with the Group-I reservoir above it. Horizontal wells were planned to intersect additional reservoir footage and to maximize productivity and reserves recovery. The Group-J sands are highly consolidated, and modeling, along with offset-well analysis, determined that sand control would not be required. The wells could be completed open hole with predrilled liners, which minimized completion complexity and cost.

Perdido Startup: Flow Assurance and Subsea Artificial Lift

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 21716, ’Perdido Startup: Flow Assurance and Subsea Artificial Lift Performance,’ by H.S. Littell, J.W. Jessup, and W.W. Schoppa, Shell International E&P Inc., and M.R. Seay and T.D. Coulon, Shell E&P Company, originally prepared for the 2011 Offshore Technology Conference, Houston, 2-5 May. The paper has not been peer reviewed. The Perdido regional host is in the ultradeepwater Gulf of Mexico (GOM) and produces from two Lower Tertiary horizons in multiple drill centers—some directly under the host spar, and others offset up to 7 miles and in water depths between 7,800 and 9,600 ft. The commissioning and early-production phases of the development provided opportunities to validate Perdido subsea hydraulic models and operational methods that were considerably different from the typical approach used by major oil companies in deep water. Introduction The Perdido project encompasses the Great White, Tobago, and Silvertip fields and is 250 miles south of Galveston, Texas, in Alaminos Canyon 857, only 6 miles from the Mexico maritime border. The fields all are being developed with subsea wells tied back to the host, which has full processing capabilities and exports gas and oil by pipeline. In Fig. 1, the spar is shown as a hub with three flowlines from offset drill centers back to the manifold system underneath the host. All of the production flowlines lie completely on the seafloor; there are no flowline risers to the spar. The manifolds under the host connect the offset wells and the local producing wells to subsea separation and artificial-lift systems using electrical submersible pumps (ESPs). The host nameplate capacity is 100,000 BOPD, 40,000 BWPD, and 200 MMscf/D, with seawater-injection capability of 80,000 BWPD. In an effort to understand fluid behavior and risks, and to design for operational flexibility, extensive fluid sampling, analysis, and property evaluations were conducted during the exploration and appraisal phase. The Great White, Silvertip, and Tobago fields initially are being developed in two oil-bearing horizons that are (relatively) low temperature and low pressure, while exhibiting distinct fluid properties. Upper Wilcox fluids are fairly typical of light GOM oils, while Oligocene fluids are a heavily biodegraded, heavy, viscous oil. Hydrate management presents a significant challenge for the deepwater environment, and hydrates are the primary flow-assurance solids risk for Perdido. Reservoir temperatures are low, gas/oil-ratio (GOR) values are potentially high, and significant expansion cooling in risers as a result of the large pressure drop is a dangerous reality. The hydrate-formation region is especially large for the Upper Wilcox fluid, with a hydrate-dissociation pressure of 160 psig at 40°F, accompanied by particularly aggressive hydrate-formation kinetics. Both fluids demonstrated solid-hydrate-plug formation in laboratory-test cells, even at lower pressures and moderate subcooling. The project leveraged the effect of subsea separation, which presents a beneficial shift of the hydrate curve up to 10 to 20°F for the liquid stream because of degassing, as well as elimination of the extreme gas- expansion cooling effect that would be experienced in a naturally flowing riser.

New Technologies Enhance Efficiency of Horizontal, Multistage Fracturing

Technology Update Significant differences in completion philosophy are emerging within our industry. Even companies that practice a factory mentality (one size/method fits all) are beginning to see that the “sledgehammer approach” to hydraulic fracturing may not be the most effective in draining horizontal wells in resource plays. For several years, we have seen massive increases in fluid volume, pumping rate, total proppant volume, and pumping time to increase recovery. We have seen through microseismic as well as fracturing into offset wells, that we are able to create massive and extremely long hydraulic fractures. Yet, when effective fracture length is calculated, the results are extremely disappointing. It only makes sense that “more is better.” However, after years of steadily increasing job size, stage number, perforating strategy, proppant volume, and lateral length, the only one that stands out as consistently improving recoveries is that more stages are required to effectively drain microdarcy permeability rock (Rankin et al., 2010). What We Have Learned Building an understanding of shale gas, unconventional gas, tight carbonate reservoirs, and more recently the renewed emphasis on oil and high-liquid gas formations has not been easy. Perhaps this is because of the extremely rapid pace of development and the acceptable economics of many projects in North America and throughout the world. Also, the diversity of applications for horizontal, multistage fracturing has made it more difficult to pin down best practices. As a massive body of data develops, a number of things have become clear. First, when equivalent stage numbers and proppant volumes are considered, open hole generally seems to outperform cased hole by 25% to 70% in production (Fig. 1, Edwards et al., 2010; Snyder and Seale, 2010). Second, the number of stages required to effectively drain microdarcy permeability rock is extremely high. Just a few years ago, performing 20 stages seemed too high to consider. Current stage numbers are often double that. Third, today’s common plug and perf practices—even at high densities—may not be sufficient to drain shale gas or tight oil, even after 15 years of depletion time (Quirk, 2010). Reservoir modeling indicates that evenly spaced fractures would effectively drain today’s reservoirs in North America. The actual production data, however, indicates otherwise.

The Performance of Mud Motors With Two Different Bent Housings

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 125858, ’The Performance of Mud Motors With Two Different Bent Housing on Drilling a Lateral Section of Horizontal Wells in North Dakota,’ by Andy Syahputra, SPE, Bill Blaschke, and Jerry Hudson, SPE, Halliburton, originally prepared for the 2009 SPE/IADC Middle East Drilling Technology Conference and Exhibition, Manama, Bahrain, 26-28 October. The paper has not been peer reviewed. Drilling across two sections in a horizontal well in the Middle Bakken formation of North Dakota offers challenges and opportunities for improved well-construction performance. The wells in this area were drilled with three different hole sections after setting the 16-in. conductor at 60 ft. The lesson learned on three offset wells in this area found that a bend setting of 1.15° has contributed to reduce tortuous well paths, controlled dogleg severity, and stayed in a very tight target interval while drilling the lateral section of 10,000 ft along the hole. Introduction Many operators are finding success drilling horizontal wells to develop the Middle Bakken in the Williston basin, which is relatively stable tectonically as compared with other intracratonic sections. The Bakken formation comprises the lower, upper, and middle members. The middle member is the target of the current development and typically consists of silty sand-stone and very-fine-grained sandstone, which is very calcareous and slightly dolomitic in the zones with the best oil and gas shows. The full-length paper focuses on drilling and the performance of mud motors with two different bent housings on three different wells in North Dakota. Discussion The bent housing tilts the axis of the bit relative to the axis of the hole. Significant bit side force is achieved for a relatively small bit offset. This allows the bit to build inclination and/or change the hole direction when the rotary-table topdrive is locked and to drill straight ahead when the drillstring is being rotated. The number of round trips thus is reduced dramatically, provided that the correct bit [polycrystalline-diamond-compact (PDC) bit of six-bladed aggressive designs with durable cutting structure] and bottomhole assembly (BHA) are chosen. The BHA is provided with vibration tools with sufficient weight to be run to the shoe and drill to section total depth (TD) in slide or rotating mode of drilling. The surface-adjustable bent housing allows an incremental adjustment of the bend in the motor from 0 to approximately 3°. This changes the magnitude of the side force generated at the bit while slide drilling and, as such, the achievable build and turn rates. As the bent-housing offset angle is increased, bit side force increases and it becomes more difficult to slide. In the rotary mode, it becomes more difficult to rotate.

Support vector regression for porosity prediction in a heterogeneous reservoir: A comparative study

In wells with limited log and core data, porosity, a fundamental and essential property to characterize reservoirs, is challenging to estimate by conventional statistical methods from offset well log and core data in heterogeneous formations. Beyond simple regression, neural networks have been used to develop more accurate porosity correlations. Unfortunately, neural network-based correlations have limited generalization ability and global correlations for a field are usually less accurate compared to local correlations for a sub-region of the reservoir. In this paper, support vector machines are explored as an intelligent technique to correlate porosity to well log data. Recently, support vector regression (SVR), based on the statistical learning theory, have been proposed as a new intelligence technique for both prediction and classification tasks. The underlying formulation of support vector machines embodies the structural risk minimization (SRM) principle which has been shown to be superior to the traditional empirical risk minimization (ERM) principle employed by conventional neural networks and classical statistical methods. This new formulation uses margin-based loss functions to control model complexity independently of the dimensionality of the input space, and kernel functions to project the estimation problem to a higher dimensional space, which enables the solution of more complex nonlinear problem optimization methods to exist for a globally optimal solution. SRM minimizes an upper bound on the expected risk using a margin-based loss function ( ε-insensitivity loss function for regression) in contrast to ERM which minimizes the error on the training data. Unlike classical learning methods, SRM, indexed by margin-based loss function, can also control model complexity independent of dimensionality. The SRM inductive principle is designed for statistical estimation with finite data where the ERM inductive principle provides the optimal solution (the empirical risk approaches the expected risk) only for asymptotic (large sample data). The SRM principle matches model complexity to the available data through controlling the tradeoff between complexity of the model and quality of fitting the data. It is this difference which equips support vector machines (SVM) with a greater ability to generalize beyond the training data. Here, a SVR-based porosity prediction model is developed for a heterogeneous sandstone reservoir. The SVR method has been compared to multilayer perceptron, General Regression Neural Networks, and Radial Basis Function Neural Networks. The results reveal that the SVR method exhibits superior accuracy and robustness with respect to these neural network methods especially with respect to accuracy when generalizing to previously unseen porosity data.

Bit Selection Optimization Using Artificial Intelligence Systems

Optimizing bit selection is one of the main challenges in drilling operations. Bit selection is based on the recorded performance of similar bits from offset wells. There are too many parameters intervening in drilling bit selection. Therefore, developing a logical relationship between them to assist in proper bit selection is extremely necessary and complicated though. In such a case, artificial neural networks (ANNs) have proven to be helpful in recognizing the complex relationship between variables. In this new approach, two models are developed with high proficiency using ANNs. The first model provides appropriate drilling bit selection based on the desired rate of penetration (ROP) to be obtained by applying specific drilling parameters. The second model uses proper drilling parameters obtained from an optimizing procedure to select the drilling bit that provides the maximum achievable rate of penetration. Genetic algorithms (GAs), as a class of optimizing methods for complex functions, are applied to help bit optimization and its related drilling parameters. With the given data sets, these new models predicted successfully the bit types and the optimum drilling parameters. The correlation coefficients for the predicted bit types and optimum drilling parameters in testing the obtained networks are 0.96 and 0.86, respectively. MATLAB software was used to perform ANN and GA solutions.

MEOR Success in Southern Saskatchewan

Summary A microbial enhanced-oil-recovery (MEOR) process was successfully applied in a mature waterflooded reservoir in Saskatchewan, Canada. A nutrient solution, which was designed specifically for this reservoir to stimulate indigenous microbes to grow, multiply, and help to release oil, was tested and piloted. A significant decrease in water cut and increase in oil production have been realized through the selective stimulation of bacteria using nutrient injection. The field is a mature waterflood averaging more than 95% water cut. To combat the increasing water-cut issue, an in-situ microbial response analysis (ISMRA) was performed on a typical high-water-cut producer in the area. The test well was treated with a nutrient solution and then was shut in for a number of days to allow indigenous microbes to grow and multiply. Upon return to production, the well produced at an average of 200% more oil with a 10% decrease in water cut for a year. Pretreatment rates averaged 1.2 m3/d of oil (8 BOPD) and post-ISMRA treatment daily production peaked at 4.1 m3/d of oil (26 BOPD). The ISMRA provides a direct support of laboratory studies and frequently increases oil production. As a result of the successful ISMRA, a pilot project was initiated and the nutrients were applied in three batch treatments on an injector with three offset production wells. Three weeks after the first batch treatment, a water-cut decrease was seen at one of the offset producers. This well's oil production gradually increased from 1.4 to more than 8 m3/d (9 to 50 B/D). Oil production in another producer doubled from 1.5 to more than 3.0 m3/d (9 to 19 B/D). Subsequent treatments were tried on marginally economic wells and on a reactivated idle producer. The average decrease in water cut in these wells was more than 10%. On the idle well, oil production increased from 0.5 m3/d (3 B/D) pretreatment to an average of 3.0 m3/d (19 B/D) post-treatment. Throughout the world, there remains a huge target for enhanced-oil-recovery (EOR) processes to target (Bryant 1991). This successful MEOR application will have a tremendous impact on ultimate recovery in many of these reservoirs not only through an increase in production, but a decrease in operating costs through associated reduction in lifting costs with less water production.