Multilateral Completion Research Articles

Impact of well completion types on oil drainage area in reservoirs

Well completion design plays a crucial role in oil production and reservoir management. This study examines the influence of various well completion types on the oil drainage area within reservoirs, with the goal of enhancing our understanding of how completion methods affect hydrocarbon recovery. Using advanced reservoir engineering techniques and simulations, this research investigates the dynamic interaction between well completion and the accessibility of oil resources. The study provides a comprehensive analysis of different well completion types, including open-hole completions, cased-hole completions, and multilateral completions, and evaluates their collective impact on the drainage area. It also explores the interplay between well completion strategies and reservoir properties, such as permeability, lithology, and fluid characteristics. The findings of this study reveal that the choice of well completion type can significantly influence the drainage area by affecting the flow paths and reservoir contact. Different completion methods can extend or limit the reach of hydrocarbon recovery, impacting oil production rates. The research underscores the importance of optimizing well completion design to maximize reservoir performance. Furthermore, the study addresses operational considerations related to well completion, including equipment selection, production optimization, and workover requirements. It offers insights into the economic and operational implications of different well completion strategies, providing valuable guidance for reservoir management. The outcomes of this research contribute to a deeper understanding of how well completion types impact the oil drainage area in reservoirs. This knowledge is valuable for reservoir engineers, operators, and industry professionals involved in oil production, assisting them in making informed decisions to optimize oil recovery, reservoir performance, and well completion strategies.

Study Reviews Multilateral Installation Improvements on the North West Shelf

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 32910,“A Decade of Multilateral Technology Installation Improvements Down Under,” by Stefano Cappiello and Adam Pasicznyk, SPE, Halliburton. The paper has not been peer reviewed. Copyright 2023 Offshore Technology Conference. _ Multilaterals wells on the North West Shelf of Australia have been installed for over a decade. An overview of the well architecture, technology evolution, reliability, and efficiency of these operations is presented in the complete paper. The study is focused on subsea multilateral campaigns, where multiple global and regional first installations took place in mature fields. Introduction Multilateral developments in Australia mainly have been completed off subsea installations, with fewer performed from jack-up rigs. These multilateral completions mostly have been installed with the junction located in the producing reservoir sands. Technology Advancement of Multilaterals (TAML) Level 5 completions have successfully been deployed. The authors classify related systems as follows, with the most attention paid in the synopsis to the final two classes: - Generation One (Field A) - Generation Two (Field B) - Generation Three (Field C) - Generation Four (Field A) General Multilateral Well Design Because of sand production within the reservoir, these applications typically require a TAML Level 5 completion system. These systems deliver hydraulic and mechanical isolation at the junction through the completion. The junction is isolated above and below by production packers and by swell packers in the lateral. The junctions typically are installed horizontally within the reservoir. The original general requirements to construct Level 5 multilateral junctions included the following: - Ability to construct a Level 5 Junction in the 9⅝-in. casing or liner - Ability to run a landing profile or coupling as part of the 9⅝-in. production casing or liner - Ability to run and orient a premilled window at depth - Drill-out 8½-in. openhole section into the mainbore and into the lateral - Junction installed within the reservoir at high angle - Window milling to be performed in one trip - Lateral completion to be installed in one trip - Compressive strength rating capable of running screen sections over 2 km As the operators began to adopt multilateral technology in Australia, the following requirements were incrementally added: - Ability to deliver a Level 5 multilateral system in an existing well - Ability to deliver a trilateral well - Improve efficiency and reduce installation time

Main stages of multi-hole well completion technology in PJSC TATNEFT implementation and ways of their improvement

As the main document in the development of multilateral well completion technology, a business plan is adopted, where technical problems are considered, due to the characteristics of the development object and the level of technology perfection. As an element of the technology, the technology of multilateral completion of wells under the conditions of equilibrium drilling and drilling using a flexible tubing string (coiled tubing) is considered. Keywords: multilateral well completion; horizontal well; development object; technical and economic effect; production characteristics; knowledge map; multidisciplinary team.

Completion, development and prospects of multilateral wells

The paper reviews the completion and development of multilateral horizontal wells. Brief data on location schemes of multilateral horizontal wells and completion levels is presented as well. At the same time, the paper analyzes the significance of drilling multilateral horizontal wells in the modern experience of oil and gas production, and their first implementation on the shore of South Caspian in the well No 19 of Garbi Absheron field.

Multilateral Offshore Well Completed With Multistage Proppant Fracturing

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 194324, “The World’s First Offshore Multilateral Well Completed With Multistage Proppant Fracturing: A Case Study From Offshore Black Sea,” by Andrew Tomlins, OMV; Joel Conrad, SPE, Packers Plus; and Bogdan Bocaneala, OPECS, prepared for the 2019 SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, 5–7 February. The paper has not been peer reviewed. The complete paper discusses the successful execution of the first offshore multilateral well completed for multistage high-pressure proppant stimulation, according to the authors, in the Black Sea offshore Romania. The authors discuss the drivers that led the operator to trial a multilateral well; the selection, planning, and final completion solution; and the lessons learned. Field Background Lebada Vest, located 95 km offshore northeast of the city of Constanţa, is the largest offshore Romanian oil field currently in production. It was discovered in 1984 and has been in production since 1993, and thus now faces the challenges and strong investment requirements associated with a mature field. Hydraulic fracturing has been used in the field’s low-permeability-formation wells since 1992, mainly in vertical or slanted wells. Completion Challenge With only one platform slot left and a significant undrained area of the reservoir, the operator had to maximize hydrocarbon recovery through a single well which, because of pressure to increase daily production, had to be finalized in 1 year. Building on field experience gained since 2008 in multistage proppant stimulation, a detailed screening and evaluation of multilateral completion technologies was performed. The focus was on developing a concept that would minimize risks during execution while meeting cost and lead-time objectives, which necessitated customizing the chosen Technology Advancement for Multilaterals (TAML) Level 3 completion design and installation methodology. To maximize rig-time efficiency, the well was executed in two phases: Drilling and lower completion installation of both branches with a drilling rig Stimulation and upper completion installation with the platform’s workover rig With six stages in each lateral, the high-pressure stimulation was executed by a converted supply vessel in four sailings, necessary to reload materials. To meet the delivery schedule, ensure simplicity, and leverage operator experience, the completion was undertaken with no dedicated multilateral hardware. Instead, the operator used standard, multistage, stimulation openhole completion equipment and appropriately engineered bent joints to exit the main bore. With initial production rates higher than anticipated, the well proved considerably more economical than drilling two horizontal wells with equivalent reservoir coverage. The success of this well serves as a proof of concept and provides increased confidence in delivering reliable, cost-effective, multilateral wells, even under tight time constraints and in areas or with operators with no history of multilateral completions. Identifying Multilateral Completion Requirements The operator’s field-development team investigated single, dual, and trilateral well-design feasibility against agreed design criteria. The principal objective was to maximize the chance of success through an appropriately risk-minimized design using standard, field-proven tools and techniques. Completion-design criteria were carried from the previous (single-lateral wells) field-development campaign in terms of production objectives, intervention capabilities, and logistics. The complete paper discusses the effect of general well design, junction, stimulation, intervention, rig strategy, and logistics and experience on the completion requirements.

Ultrasonic Imaging Technology Evaluates a Lateral-Entry Module

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 189947, “Using Ultrasonic Imaging Technology To Evaluate a Lateral-Entry Module,” by Marianne Solberg, Archer; Michael Sullivan and Steve G. Drake, ConocoPhillips; Tarjei Rommetveit and Duncan Troup, SPE, Archer; and Joel Johns, SPE, Quintana Energy Services, prepared for the 2018 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 27–28 March. The paper has not been peer reviewed. Several attempts to enter the upper lateral of a multilateral well operated by a major oil company in Alaska had been unsuccessful. In May 2017, an ultrasonic imaging technique based on medical ultrasound imaging was used to inspect the lateral-entry modules (LEMs). This paper presents the data collected by an ultrasound downhole scanner, demonstrating a novel method for diagnosing multilateral wells. Background The West Sak field is a viscous-oil deposit within the Kuparuk River Unit on the Alaskan North Slope. The reservoir was deposited in a lower shoreface to inner-shelf marine environment and consists of highly unconsolidated sandstones that have a gross thickness of approximately 500 ft and an average net thickness of 90 ft. The reservoir consists of three major producing intervals, the West Sak D, B, and A sands. Since original development in 1997, West Sak has been an active waterflood site. As technology improved and additional studies were completed, field development transitioned from a sand- exclusion strategy to a sand-management strategy. Completion strategy shifted to both producers and injectors with multilateral horizontal slotted liners. These multilateral completions have higher productivities than vertical wells but are subject to producing sand, and, over time, matrix-bypass events (MBEs) have been noted. These events occur when the rapid breakthrough of offset water injection through nonmatrix flow causes the affected producer’s water cut to jump instantly to 100%. Once an MBE occurs, the affected injector is shut in and the affected producer is left on-line to dewater. Eventually, the oil production returns, but, because of the lack of waterflood support, oil-production rates rarely return to those seen before the MBE. Problem Outline An MBE occurred between a West Sak multilateral injector and producer well pair. The standard diagnostic process of locating the MBE began. An injection profile log (IPROF) of the main bore in the injector determined that the MBE occurred in the D-sand (upper) lateral. An IPROF of the D-sand lateral was attempted using coiled tubing (CT) but was unable to exit the lateral junction. To gain lateral access, several different CT bottomhole assemblies were used and cleaning of the junction was attempted. These attempts were unsuccessful. The decision was made to run a downhole video to investigate the D-sand lateral junction better. Evaluation of the video data indicated that a portion of the LEM may have shifted, covering the upper section of the lateral window. This slight shift in downhole equipment may have been the only issue impeding CT from entering the lateral. Analyzing the data led to the idea of creating a specialized whipstock to allow CT to mill the obstruction to provide access to the lateral.

Research on Whipstock Packer Oriented Perforating Technology

Multilateral well drilling and completion technology reduces well development cost and increases effectively the benefit and productivity of oil & gas well, which is widely used and expanded in recent years at home and abroad. Whipstock packer oriented perforating technology, a critical step in multilateral well drilling and completion, is for perforating whipstock packer and communicating lower branch wellbore. This technology meets the higher requirement of orientation and accuracy of penetration, perforator being able to perforate whipstock packer but not perforate outer casing of whipstock, and also meets complicated operation process.

Intelligent-Well Completion in the Troll Field Enables Feed-Through Zonal Isolation

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 160060, ’First Intelligent-Well Completion in the Troll Field Enables Feed- Through Zonal Isolation: A Case History,’ by Bjorn Olav Dahle, Statoil, and Peter E. Smith, Geir Gjelstad, and Kristian Solhaug, Halliburton, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8-10 October. The paper has not been peer reviewed. Statoil, operating the Troll field in the Norwegian sector of the North Sea, wished to run a deep sidetrack from the main bore in a multilateral well that would exit through the liner in the reservoir. Several zonal-isolation methods had been evaluated, but on the basis of previous experience Statoil decided to use swellable-packer technology. Testing revealed that this type of completion would exceed the necessary requirements. The installation was performed from a semisubmersible rig ahead of plan. Introduction The Troll field lies approximately 65 km west of Kollsnes, near Bergen, Norway. Although the field historically has produced large amounts of oil, it is now primarily a gas producer and contains approximately 40% of the total gas reserves on the Norwegian continental shelf. The gas reservoirs, which are 1400 m below sea level, are expected to produce for at least another 70 years. The massive Troll A platform produces gas, while Troll B, a floating process and accommodation platform with a concrete hull, and Troll C, a floating process and accommodation platform with a steel hull, produce from thin oil-bearing layers in the Troll West reservoir. The thin oil layer is between 22 and 26 m thick in the Troll West oil province and is between 11 and 13 m thick in the Troll West gas province. In order to recover oil from the thin layer, it has been necessary to develop advanced drilling and production technology. All of the more than 110 production wells to be drilled are horizontal wells. This process requires two-phase drilling. The first phase drills down to the reservoir, 1600 m beneath the sea bottom, and then the second phase drills to 3200 m in a horizontal direction through the reservoir. Twenty-eight of the wells are multilaterals that have two or three horizontal laterals. The well in question faced several challenges normally not seen in Troll multilateral completions, including standalone-screen completion with zonal isolation, well paths with doglegs and a completion total depth (TD) of more than 6000 m, top completion with zonal isolation and zonal control for four zones, and the need for dual pressure and temperature monitoring for all oil zones.

Technology Focus: Mature Fields and Well Revitalization (January 2013)

Technology Focus Revitalization of mature fields holds the promise of lengthening the economic life of an asset years into the future. It has been demonstrated that significant value can be found in extensively produced mature fields. The characteristics of successful projects typically begin with a coherent exploration and production strategy that integrates elements of technology, personnel, and process. This collective approach not only allows the operators to combat the declining production levels but also brings new opportunities and adds value to the mature fields. The number of key enabling technologies in the revitalization toolbox is growing. For instance, new advances have been made in reservoir characterization, reservoir simulation, downhole monitoring and surveillance, multilateral drilling and completion, and production-enhancement techniques. However, each mature field has unique characteristics and often presents distinctly different challenges. It takes a concerted effort to integrate the right process, the right technology, and the right team to reduce risks and successfully execute a plan to revitalize an aging field. The availability and proper interpretation of existing data or ability to obtain quality data also reduces risks. Data management can be a key factor in the successful evaluation to revitalize a mature field. Economic constraints may limit actual data collection, thus concerted efforts must be made to leverage prior experience and knowledge. The development of new fields may undermine efforts to improve the recovery factor of mature fields. Nevertheless, revitalization projects are being implemented continuously worldwide, partly because the risks involved could be lower than those for developing new fields. Furthermore, the upside of preserving the use of existing infrastructure for revitalization purposes can be especially appealing. It is also worth mentioning that many of the same approaches and techniques can be shared between projects of exploration and revitalization. Papers selected for this month’s feature provide useful information on strategic planning, multidiscipline approaches, and use of enabling technology. All are useful for investigating potential solutions, narrowing down options, minimizing risks, and executing field-development plans. These papers and cited references also validate and confirm the continuous worldwide focus on improving hydrocarbon recovery from mature fields. There is much that can be learned by reviewing the lessons learned in the selected papers. Recommended additional reading at OnePetro: www.onepetro.org. SPE/IADC 151193 Near Field Developments With an Upgraded Brownfield Platform Rig: Sharing the Learning From a Three-Well Extended Reach Drilling Program by Miguel O. Mota, ExxonMobil, et al. SPE/IADC 151202 Regeneration of First-Generation Subsea Fields: The Challenges of New Wells in Old Infrastructure by Sean Stright, ExxonMobil, et al. SPE 145567 Reassessment of Reservoir Dynamic Behavior To Assist the Fourth Drilling Campaign in Mature, Geologically Complex North Sea Field by I. Valko, Total, et al.

Single-Trip TAML Level-4 Multilateral Junction Reduces Well Costs in Norwegian Sea Subsea Well - Case History

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 123935, ’New Single-Trip, TAML Level-4, Multilateral-Junction Technology Reduces Well Costs in Norwegian Sea Subsea Well - A Case History,’ by Olle Balstad, Statoil, and Mark Glaser, SPE, and Tage Heng, Weatherford, prepared for the 2009 SPE Offshore Europe Oil & Gas Conference & Exhibition, Aberdeen, 8-11 September. Installation of a single-trip Technology Advancement for Multilaterals (TAML) Level-4 multilateral (ML) junction was completed in a subsea gas-injection well. The well was drilled to support oil production from the Tilje and Ile formations in the Smørbukk Sør field in the Norwegian Sea, approximately 193 km offshore in 300-m water depth. After injecting for 10 years, the well will be converted to a gas producer from the same formations. Introduction The åsgard license is a subsea development incorporating three fields, Smørbukk, Smørbukk Sør, and Midgard. This area of the Norwegian Sea experiences very unpredictable and extreme weather conditions. Winds can change from dead calm to full gale in a period of less than 1 hour, and the accompanying sea conditions present major challenges to both equipment and personnel. Prospect development is well advanced, with only a few slots remaining in the subsea templates for new-well development. New wells are more cost effective if an ML approach is used that maximizes the number of drainage points in the reservoirs. The Smørbukk Sør field has four templates—three for production wells and one for injection, with only one available slot (R-3). Studies of injection patterns and requirements concluded that additional injection was required into both the Ile and Tilje formations to optimize production patterns. Another complication was that both zones would require sand control. An ML well was planned with the objectives of providing the needed gas injection and subsequent conversion to a gas producer after 10 years. To achieve these goals, a TAML Level-4 ML completion was planned. Injection into the well would be controlled by the use of a newly developed downhole-instrumentation and -control system, and as a result, it was deemed that no subsequent access to the main bore would be required after completion. The decision was made to construct the ML junction with a single-trip hollow-whipstock system that can withstand high temperatures (static downhole temperature anticipated to be 140°C) and can reduce the number of trips into the well in the hostile operating environment prevailing in the area. A single-trip hollow-whipstock design was chosen for installation in the Smørbukk Sør R-3 well. Drilling and Completion The drilling and completion of Well R-3 were performed from a semisubmersible rig. The well was drilled and cased without incident. Main-Bore Completion. A detailed procedure was written to communicate all stages of the completion process clearly including risk analysis, contingencies, comprehensive pretesting of assemblies, and other details to provide a smooth transition between phases, a seamless operation, and clear quality, health, safety, and environmental guidelines. Following a thorough cleanout of the main bore to TD and the running of the requisite logs, the main bore was completed with a 5½-in.-sand-screen section. Because of the required total length of the section, the decision was made to run the sand screen in two sections because the need to reach the correct depth with the top liner hanger was critical.

Inflow-Control Devices for Reducing Water Production

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 124154, ’Practical Consideration of an Inflow Control Device Application for Reducing Water Production,’ by Liang-Biao Ouyang, SPE, Chevron Energy Technology Company, originally prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October. Inflow-control devices (ICDs) have been developed to improve well performance and enhance reservoir management by mitigating undesired water and/or gas breakthroughs that often occur as a result of a variety of factors, including reservoir-permeability heterogeneity, heel/toe effects, and different reservoir pressures in different regions penetrated by a well. Success of an ICD completion relies heavily on appropriate completion design. The full-length paper identifies several key issues that should be addressed in designing an ICD completion and discusses their effects on performance of a well equipped with ICDs. Introduction Despite their superiority in production and recovery to conventional wells by maximizing reservoir contact, horizontal and multilateral completions are more prone to water and/or gas coning toward the heel of the well as a result of frictional pressure drop from toe to heel and/or breakthrough anywhere in the well because of permeability variation along the well and proximity of water traps. ICDs, a choking device installed as part of sandface completion hardware, were proposed in the early 1990s as a solution to the difficulties particularly associated with horizontal and multilateral wells. An ICD completion offers a number of potential unique benefits: Optimize production Delay water progress Minimize /eliminate annular flow and thus reduce the risk of sand production behind screen and subsequent plugging or erosion “hot spots” Mitigate the nonuniform production profile across the horizontal hole, especially in highly heterogeneous and fractured reservoirs that may result in premature water production, bypassed oil, and lower ultimate recovery Improve well cleanup and reduce the effect of formation damage caused by drilling of the well For sandstone, the application of ICDs should reduce the effect of heel/toe effects and high-permeability intervals, defer water/gas breakthrough, and improve well cleanup and sweep efficiency. For carbonate, the application of ICDs should help to control inflow from high-permeability intervals and limit production from each compartment based on lateral offset from gas/oil and oil/water contact to prevent premature gas and/or water breakthrough. ICDs have gained increasing popularity and increasingly are being applied to a wide range of reservoir types.

Techbits: Horizontal, Multilateral Well Advances Addressed in Malaysia

Techbits Horizontal and multilateral wells took center stage at an SPE Applied Technology Workshop (ATW) held earlier this year in Penang, Malaysia. The workshop, titled "Maximizing the Value of Horizontal and Multilateral Wells: New Challenges, Technologies, and Approaches," gathered 70 participants from around the world for discussions aimed at addressing new applications of multilateral and horizontal well technologies. The ATW included sessions reviewing lessons learned in drilling horizontal and multilateral wells, as well as the new technology offerings that promise to maximize oil and gas production from them. The specific range of topics included field-development planning, reservoir evaluation, the use of intelligent technology for efficiency gains, drilling and completion issues, and stimulation. The ATW's opening session provided an overview of the development history of horizontal and multilateral wells within Saudi Aramco. Current well practices are built upon learnings from past experiences in the areas of reservoir characterization, well placement, well-structure optimization, and intelligent completions to yield maximum production benefit. The opening session also encouraged attendees to focus on tackling the challenges of applying this technology in today's energy and economic environment. Technology Overview The industry organization Technical Advancement of Multilaterals (TAML) opened the technology overview session with a review of its programs designed to promote global development and utilization of multilateral technology within the industry through open dialog and information exchange. Apache Corporation next provided an operator's perspective of development strategies in planning horizontal and multilateral wells. Emphasis was placed on ways to maximize hydrocarbon recovery while also keeping costs to a minimum. Investment and asset development were analyzed through the entire asset lifecycle, from discovery to decommissioning. An operator considering a horizontal or multilateral completion solution must carefully evaluate the suitability of the design concept for each asset, from both a cost-effectiveness and safety/risk point of view. Drilling and Completion While discussing specific drilling- and completion-related issues, attendees agreed that a thorough understanding of how a particular drilling or completion design scheme may impact other disciplines is vital. For example, during the development plan for a multilateral well it is important to consider the geology and condition of the reservoir, as well as future plans for production, stimulation, and intervention. Field examples from both an operator (OMV New Zealand) and a service provider (Baker Oil Tools) illustrated the importance of having a multidisciplinary team work together to consider the various factors in their drilling and completion design, which are not limited to:Debris managementDepth control and orientationContingency plans and risk assessmentIntervention and plug/abandonmentSend control screen, openhole gravel pack or cased-hole fracture pack

Downhole Well Connections By Use of Rotating-Magnetic- Ranging-Service and Single-Wire-Guidance Tool

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 119420, "Rotating-Magnetic- Ranging Service and Single-Wire- Guidance Tool Facilitates in Efficient Downhole Well Connections," by Ray T. Oskarsen, SPE, and John W. Wright, SPE, John Wright Company, and Donal Fitterer, Dave Winter, Anthony Nekut, and Jed Sheckler, Vector Magnetics, originally prepared for the 2009 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 17-19 March. The paper has not been peer reviewed. Downhole connections between multiple wellbores have applications in many operations such as extended-reach drilling (ERD), multilateral completions, subsurface pipelines, and downhole fluid separation. A research-and-development project was undertaken to develop and validate an electromagnetic-ranging concept for enabling cost-efficient downhole connections. After extensive testing that found the ranging technology suitable, an existing offshore well jacket was identified as a good candidate for field validation of the concept. Introduction Determining the distance and direction to adjacent wellbores is a critical task when drilling relief wells or preventing wellbore collisions. Because of the cumulative and systematic errors inherent in measurement-while-drilling (MWD) or gyroscopic tools, the measured survey coordinates of a wellbore will have increasing uncertainty with depth, which is referred to as the "cone of uncertainty." For example, for a vertical well drilled using a surveying tool with an error cone of 1.5 m/1000 m, the radius of uncertainty at a true vertical depth (TVD) of 10 000 m is 15 m. Hence, for blowout intervention, to steer a relief well accurately to a deep intersection by relying only on the survey data of the target well is practically impossible. Instead, the homing-in process must be accomplished by a downhole ranging technique. Although some unique ranging technologies currently are being researched, the most common methods are passive-magnetic and active-electromagnetic ranging, which both depend on steel, such as casing or drillstring, in the target well. During the last decade, feasibility studies, field trials, and implementation of downhole ranging technology have been performed for additional applications. The full-length paper contains examples of applications for downhole well connections and describes the single-wire-guidance (SWG) and rotating-magnetic-ranging-service (RMRS) technology developed and tested for these types of applications. Well-Connection History Downhole well intersections are common for relief wells and have been per-formed regularly for decades as a last-resort well-intervention method when other surface-kill efforts have failed. The original purpose of a relief well was to relieve pressure on a blowing formation by drilling a vertical well and producing the formation at high rates. In 1933, a directionally drilled relief well intersected the flowing reservoir below the surface location of a cratered blow-out in Conroe, Texas, marking the first milestone in relief-well development.

Challenges, Lessons Learned, and Successful Implementations of Multilateral Completion Technology Offshore Abu Dhabi

Summary Zakum Development Company (ZADCO), with the support from shareholders and the cooperation of Abu Dhabi Marine Operating Company (ADMA-OPCO), successfully completed the final design of the multilateral completion (MLC) system for Reservoirs A and B through the Multilateral Tie Back System (MLTBS) project. Well T-2 in the Upper Zakum field was recompleted as dual lateral/dual producer using a re-entry drilling system (RDS) Version 2 and a dual bore deflector (DBD) oriented and set on a latch coupling in the 7-in. liner hanger assembly. According to Technology Advancement Multilateral (TAML) level specification, the final MLC is categorized as TAML Level-4 E-2-PN-D/4-TR-SEP (Level-4, existing well application, two junction, producer with natural lift, dual completion, tubing reentry, separated flow). The multilateral liner hanger (MLLH) system (i.e., accommodating a latch coupling in 7-in. liner hanger assembly to have a certain access to the upper lateral) was the first successful application of that kind in the world. The teamwork and integrated approach for the trial planning and implementation, as well as lessons learned from a predesign trial (TAML Level-4 E-2-PN-D-TR-SEP using straddle assembly) for Well T-1 completed in 2000, have led to reaching the final goal of the MLC in Well T-2, which provides ZADCO with the following reservoir benefits: -Independent coiled tubing access to the upper (Reservoir A) and lower laterals (Reservoir B) through a dual completion to perform effective stimulation and reservoir monitoring.-Full bore access to each lateral immediately after pulling out the completion, which is an additional feature to the predesign of an MLC for Well T-1.-Allow selective water shutoff to cope with water breakthrough into the upper-cased lateral.-Possibility of extending well life by drilling a secondary lateral through a window joint installed in the upper-cased lateral. Moreover, another MLC trial, installed in the quadrant multilateral well RL-2 in 2005, has been successfully implemented by using mechanically selective through tubing re-entry equipment. This success was largely because of the lessons learned from a similar MLC design implemented in well RL-1 in 2001. These successful trial implementations proved the MLC system is applicable for any new/re-entry wells in ZADCO reservoirs, which provides new methods of reservoir management, and creates new completion strategies for ZADCO field development. This paper covers the MLC strategies, lessons learned through the successes and failures and the additional challenges planned for the future of the MLTBS project.

Multilateral Horizontal Well Improves Oil Recovery in a Mature Field in Libya

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 112125, "Multi Lateral Horizontal Well Application for Improving the Oil Recovery of a Mature Field, Intisar N. Field, Concession 103 - Libya," by M.M. Gharsalla and M.B. Elghmari, Zueitina Oil Company, originally prepared for the 2008 SPE North Africa Technical Conference and Ex hib ition, Marrakech, Morocco, 12-14 March. The paper has not been peer reviewed. The full-length paper examines the performance of a multilateral completion in a mature thin carbonate reservoir. The initial field development with two vertical wells resulted in a poor recovery of only 9% of the original oil in place. A reservoir-simulation study in 2003 indicated that drilling vertical wells in a very thin reservoir of poor quality was not cost-effective and recommended drilling horizontal wells. The stabilized oil-production rate of the multilateral horizontal well was approximately three times higher than that of the vertical well. Introduction Intisar N field is in Concession 103 in Libya approximately 360 km south of Benghazi in the prolific Sirte basin. The field was discovered in 1968 by drilling Well N1 to a total depth of 10,318 ft in the Lower Sabil. The Intisar N field comprises two separate carbonate reservoirs, the Upper Sabil (Zelten) at a depth of 9,230 ft and Lower Sabil (Heira) at 9,820 ft, approximately 600 ft apart. Fig. 1 shows a map of formation tops of the Upper Sabil and Lower Sabil formations. Both reservoir structures are composed of two anticlinal saddles believed to be separated by a fault. The field is relatively small in size, with initial oil in place of 19.0 million STB of which 14.4 million STB is contained in the Zelten (Upper Sabil) reservoir and 4.6 million STB in the Heira (Lower Sabil) reservoir. Stratigraphy and Trapping Mechanism The general stratigraphy and structure in the Concession 103 area has been controlled by the shelf edge in Upper Paleocene times between the Marsa Brega Trough and the Gialo/Amal high. Reefal bioherms developed on this shelf edge through the Upper Paleocene, after which there was a transgression or subsidence in the very late Paleocene resulting in the deposition of the Kheir marls and shale. During the Eocene, there was predominantly shelf carbonate deposition, with the grain size determined by provenance and water depth. Locally, the sedimentation has been influenced by drape over the reef, resulting in locally shallow water depths in the immediate area of the reef, resulting in rather gentle homoclines providing up to 50 to 70 ft of closures. The oil accumulations at Concession 103N in the Zelten and Heira reservoirs are trapped by the homoclines. Petrophysical Properties The reservoir quality varies laterally significantly in both the Upper and Lower Sabil; the quality improves toward the crest and deteriorates toward the flanks. Most parts of the Upper Sabil formation have fair porosity, and good solution porosity is locally present. The oil systems in the Upper and Lower Sabil reservoirs are light and highly undersaturated.

Advanced Noncement Options for Isolating Wellbores

Technology Update Information provided by Ed Wood, Sean Yakeley, Jesse Constantine, and Jody Augustine, Baker Hughes. For today's long horizontal wellbores and multilateral completions, competent zonal isolation is especially critical. But cementing and perforating multiple zones is costly and time consuming, requires specialized equipment and personnel, can cause near-wellbore formation damage, and poses safety and environmental risks. Alternative isolation technologies now can reduce costs and improve well productivity through more effective fracture treatment and better inflow management. Among these new options, reactive-element (RE) technology and other fit-for-purpose packer systems are field-proven solutions for a variety of zonal isolation challenges. Much more of the world's oil and gas can now be recovered economically by exposing to the wellbore long stretches of reservoir that typically contain several pay zones. Without cost-effective zonal isolation, however, the full potential of advanced drilling and completion technology to increase production, ultimate recovery, and profitability cannot be realized. Efficient, practical zonal isolation is also important in solving fluid-loss problems while drilling and in reviving mature wells. With new, noncement isolation methods, it is possible to achieve uniform flow in highly productive wells, perform multiple fracture treatments in carbonate and shale reservoirs, and employ inflow control devices (ICDs) to man-age flow without well intervention. All of these capabilities extend a well's productive life and profitability. Two Key Drivers Isolating well intervals without cement is not a new concept, but recent growth in commercial use has been driven by such challenges as the need to fracture tight gas formations and to regulate flow in high-rate wells. Two means of achieving cementless isolation are the use ofRE packers with swelling-elastomer elements that self-energize in reaction to water and/or hydrocarbonsHydrostatic/mechanical packers, set hydraulically The latter type of packer often is used with an ICD. RE Systems For a fast-growing number of diverse zonal isolation challenges, an RE packer is an efficient, cost-effective alternative to cementing and perforating. RE-packer completions are simple to deploy and require fewer trips, no running tools, and no specially trained personnel on site. RE devices are usable in both oil and gas producers. Elastomeric-polymer sealing elements in the packer react with oil or water to swell and seal off the annulus between liner or casing, and open hole. The water-reactive element consists of particles contained in a nitrile-based polymer that swell by absorbing water. The rubber expands without the particles being physically absorbed in the rubber matrix. Oleophillic polymers in the oil-reactive element absorb hydrocarbons into the matrix. The swelling mechanisms are not reversible, so the element will not shrink if fluids are changed after swelling. Tests show negligible contraction in the elastomer when exposed to natural gas. RE packers are rated for temperatures to 300°F and pressures to 10,000 psi. RE-packer applications include water shutoff and the isolation of cement shoes, lateral junctions, and fractures. A special type of RE packer can be field-installed onto existing tools for added flexibility in deployment. Another RE tool can be used as a debris barrier.

Production Operations: Inflow-Control Devices

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 108700, "Inflow-Control Devices: Application and Value Quantification of a Developing Technology," by F.T. Al-Khelaiwi, SPE, and D.R. Davies, SPE, Heriot-Watt U., prepared for the 2007 SPE International Oil Conference and Exhibition in Mexico, Veracruz, Mexico, 27–30 June. The paper has not been peer reviewed. Horizontal and multilateral completions are a proven, superior development option in many reservoir situations. However, they are susceptible to coning toward the heel of the well despite their maximizing of reservoir contact. This is a result of frictional pressure drop and/or permeability variations along the well. Annular flow, leading to severe erosion and screen plugging, is another challenge. Inflow-control devices (ICDs) were proposed as a solution to these difficulties in the early 1990s. ICDs have gained popularity recently and are being applied to a wider range of field types. Their ability to control the well inflow profile has been confirmed by a variety of field monitoring techniques. Introduction ICDs are a new sandface completion technology specifically developed to help balance the inflow contribution along horizontal wellbores. Extensive flow-loop testing and subsequent field experience have proved the potential of ICDs to extend well life by extending the plateau period, minimizing water and gas coning, minimizing annular flow, and increasing recovery. Historical Development Norsk Hydro introduced the ICD technology in the early 1990s to enhance the performance of horizontal wells in the Troll field, a giant gas field on the Norwegian shelf of the North Sea. The field contains a thin oil column (4 to 27 m thick) overlain by a large gas cap and underlain by an aquifer. The field was developed originally as a gas field in the "thin-oil-column" part of the field because the production of such a thin oil column was deemed nonviable with conventional wells. Two horizontal wells then were drilled, and long-term well tests were conducted to determine the ability of such wells to drain the oil economically. The wells were completed with large-diameter prepacked slotted liners to reduce the effect of frictional pressure losses along the wellbores. The long-term-test results indicated that a significant oil-production potential existed. The initial flow rate of the first well was four times that expected from a vertical well. The well productivity index was very high, at approximately 6000 std m3/d/bar, which is 5 to 10 times higher than that expected from a vertical well. This also meant that a small pressure drop of only 0.5 to 1.0 bar is sufficient drawdown pressure to produce the well at a target rate of 3000 to 5000 std m3/d. A new field-development plan was put in place that used horizontal wells. However, production logging of the first test well indicated that 75% of the contribution was coming from the first half of the horizontal section. This is indicative of the significant effect frictional pressure losses can have on the performance of horizontal wells once this frictional pressure drop is of the order of magnitude of the drawdown.

Technology Integration in the Caspian

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 106858, "Technology Integration in the Caspian," by Ian Pannett and David Hodgson, BP plc, prepared for the 2007 SPE Digital Energy Conference and Exhibition, Houston, 11–12 April. BP's Azerbaijan Strategic Performance Unit (ASPU) was developed to meet key challenges of operating within the Caspian region and to maximize business value. Key challenges include complex depletion plans; unconsolidated reservoirs; a difficult-to-drill overburden; and an integrated development, gathering, and export system. To meet these challenges, advanced seismic, intelligent completions, zonal-flow monitoring and control, and field of the future (FOF) technologies collectively address the business challenges. Introduction Integration is key for the Azerbaijan strategy, specifically the technology strategy. The assets and reservoirs are integrated in a variety of ways and designed to operate in an integrated way. This integration is essential to maximize reservoir recovery. As the strategy developed, increased integration could create additional opportunities for performance improvements. Azerbaijan Assets As shown in Fig. 1, the BP-operated assets center on development of two very large hydrocarbon reservoirs in the Caspian [the Azeri, Chirag, and Guneshli (ACG) oil fields and the Shah Deniz (SD) gas development], although it is fully expected that other assets will be added. In addition, BP operates two major pipelines through which these hydrocarbons are exported—the Baku-Tbilisi-Ceyhan (BTC) and the South Caucasus Pipeline (SCP), which originate at the Sangachal terminal, south of Baku. These pipelines are designed to take ACG and SD reserves to market with capacity to take oil and gas from other fields and operators. A fully redundant data network is in place linking all facilities with a high-bandwidth optical-fiber "ring-main" backed up by satellite data systems. Fig. 2 summarizes the ACG full-field development. Technology Plan The 5-year technology plan integrates all functional and asset-based activities across business areas supporting the ASPU. The strategy includes leadership in a few key areas, efficient deployment of technology in other areas, bias toward rapid application of proven technology, and healthy progression of options in selecting available technologies. This strategy has helped to focus and prioritize technologies. The technology plan was developed in conjunction with field-depletion plans. The technology plan also was designed to improve ultimate recovery. The current ACG-development plans recover approximately two-thirds of the potential. Obtaining maximum value requires sophisticated reservoir management and application of advanced technologies such as multilateral completions and other enhanced-oil-recovery technologies.

Overview: Intelligent Fields Technology (August 2007)

Intelligent Fields Implementation: Why Is It Taking So Long? We have been talking about intelligent fields or digital oilfield matters for some time, and while a significant number of papers have been written on the subject, mainstream application of the technology is patchy. Given the benefits from making better use of our data, why is it that the broad application of the digital oil field has not yet happened? Having been involved over the last 5 years or so, I see five inhibitors.Not enough focus on people and process—It is too easy to see the digital oil field as a new software product. In reality, how data is used in various processes, how workflows could change, and how people interact with data are fundamental to achieving the benefits of the digital oil field.Seeing the digital oil field as a single product—In reality, digital oil field is all about integration: integration of existing software, integration of data sources, and integration of data. This integration requires clarity of the architecture, the data flows, and the output requirements.Aiming for a fully linked integrated model before addressing fundamentals—It is key to start with appropriate instrumentation, data collection, surface control and data acquisition systems, and data conditioning to achieve early benefits from effective visualization and simple analysis. More-complex linking of integrated asset models should wait for "Phase 2."Lack of scalability—Often, assets develop solutions to address the immediate local business need without giving due consideration to being able to scale the solution to other assets. I fully support business-unit-led developments, but a corporate guide is required to ensure that they fit with the overall strategy.Difficulty in sustaining momentum—Enthusiasm, commitment, and resources at build stage can fall away if a key individual moves. Even a fully implemented system can be difficult to sustain if it is not applied consistently across assets. Being aware of these traps and working to address them provides significant opportunity for wider mainstream application of digital oilfield technology over the next few years. Like you, I look forward to it. Intelligent Fields Technology additional reading available at the SPE eLibrary: www.spe.org SPE 104161 "Advanced Production Monitoring" by Martijn Hooimeijer, Shell Global Solutions, et al. SPE 104227 "Smart-Well Completion Utilizes Natural Reservoir Energy To Produce High-Water-Cut and Low-Productivity-Index Well in Abqaiq Field" by Nashi M. Al-Otaibi, SPE, Saudi Aramco, et al. SPE 105374 "A Novel Approach of Detecting Water-Influx Time in Multizone and Multilateral Completions Using Real-Time Downhole Pressure Data," by G.H. Aggrey, Heriot-Watt University, et al. SPE 105618 "Smart Wells: Experiences and Best Practices at Haradh Increment-III, Ghawar Field," by Ibrahim H. Al-Arnaout, Saudi Aramco, et al.

Well-Intervention Challenges To Service Wells That Can Be Drilled

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 100172, "Well-Intervention Challenges To Service Wells That 'Can Be Drilled'," by C.G. Blount, SPE, and M.B. Mooney, SPE, ConocoPhillips; F.R. Behenna, SPE, CTES LP; and R.K. Stephens, SPE, and R.D. Smith, BP, prepared for the 2006 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 4-5 April. Drilling rigs continually are setting new records in measured-depth (MD) vs. true-vertical-depth (TVD) ratios, horizontal-section lengths, and delivering operationally complex completions. Common well-intervention technologies may have difficulty fulfilling the intervention needs of the wells that can be and are being drilled and completed. The full-length paper presents an overview of available well-intervention technology, outlines limitations of each technology, and offers case histories from challenging interventions performed in Alaska. Introduction Advances in drilling technology have enabled operators to drill complex wells ranging from long step-out wells to multilateral completions with horizontal laterals that may extend more than 7,000 ft. These advances in drilling technology have allowed operators to reach distant offshore targets from onshore facilities such as those used in Wytch Farm and Sakhalin Island and to drain large areas from small, environmentally conscious pads such as those in Alpine, West Sak, and other Alaska North Slope fields. The engineering and new technology used in drilling and completing these complex wells are impressive. However, when the rig moves off, the production department is left with wells that cannot be serviced with "conventional" service tools and techniques. Shortcomings in servicing these unconventional wells have driven numerous intervention-technology advances including pumpdown equipment, electric-line tractors, extended-reach tools and techniques for coiled-tubing (CT) applications, CT tractors, and use of hydraulic workover (HWO) units for accessing the wellbores. Even with the ability to access these complex wells, performing routine jobs such as setting plugs, shifting sleeves, production logging, profile modifications, and fill cleanouts can become orders of magnitude more difficult and costly to perform than similar services in conventional wells. Conveyance Methods Slickline. For slickline working in straight holes, depth limitations vary depending on numerous parameters including material, fluid in the hole, tool weight, and the work to be performed. Modeling of slickline operations in a vertical well suggests that the depth limit is approximately 33,500 to 35,400 ft with a light 100-lbm tool string and limiting hanging weight to 50% of breaking strength. There was no provision for performing work at this depth. Modeling included slickline sizes ranging from 0.092-to 0.125-in. diameter, with the larger diameter achieving only slightly greater depths than the smaller-diameter lines. Use of a 0.25 friction factor suggests that slickline could reach approximately 50,000 ft in a well with a constant 60° inclination. Factors such as material properties, amount of wellbore debris present, and wellbore tortuosity will affect these depths dramatically. Experience in highly deviated wells also indicates that the friction factor most likely will be higher than 0.25.