Monobore Completion Research Articles

Coiled Tubing Program Succeeds in Harsh-Environment Tight Gas Wells

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209032, “Successfully Adapting and Overcoming Challenges for Coiled Tubing Applications in High-Pressure Sour Environments and Horizontal Unconventional Tight Gas Wells in UAE,” by Ole Sorensen, Yang Wu, and Didier Caillon, SPE, TotalEnergies, et al. The paper has not been peer reviewed. During the completion phase of four unconventional wells in the United Arab Emirates, a detailed engineering approach overcame challenges presented by extreme conditions of pressure, temperature, and a sour environment across long horizontal sections to carry out cleanout activities successfully. This operation, the first of its kind in the country for the operator, yielded lessons for design considerations and the execution process and recommendations for coiled tubing (CT) intervention in similar working environments. It also confirmed that 110,000-psi-yield-strength quench-and-tempered (Q&T) CT strings can be deployed safely in a high-pressure sour environment by implementing proper risk-mitigation strategies. Introduction The unconventional gas play (referred to as “A” in the complete paper) featured a reservoir pressure of nearly 13,000 psi and a bottomhole temperature of approximately 325°F. The environment was sour, with 5 mol% of hydrogen sulfide (H2S) and 5% carbon dioxide (CO2). The well’s architecture consisted of a 5½-in. monobore completion with cemented casing and horizontal sections ranging from 5,000 to 8,200 ft. The selected completion methodology was plug-and-perf, including up to 35 fracturing stages in a single well. Overview of CT Intervention Challenges The true vertical depth of the play was 12,600 ft on average, representing a maximum anticipated surface pressure (MASP) of 8,000 psi with the wellbore full of working fluid (8.34-lbm/gal slickwater) and a maximum potential wellhead pressure (MPWHP) of 11,300 psi with the wellbore full of gas. Also, partial pressures of H2S and CO2 exceeded 600 psi at bottomhole conditions, confirming that sour- and corrosive-service programs had to be implemented fully in this project. Convergence of MASP above 7,500 psi, CT dynamic pressure of greater than 11,000 psi, lateral length of up to 8,200 ft, and the sour and corrosive environment required a highly engineered approach on the design and selection of the CT string and configuration of the surface equipment.

Monobore Completion System Provides Low-Cost Completion Option

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 124797, ’Monobore Completion System Provides Low-Cost Completion Option,’ by Don Ingvardsen, SPE, and Jim Kritzler, SPE, Baker Hughes, originally prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October. The paper has not been peer reviewed. Many wells completed today could be classified as short-life or harvest wells. Some of these would not be economically feasible using high-end completion components and methods. Monobore wells can be a solution to this problem. The full-length paper discusses several methods in which monobore well design can save considerable time while lowering the overall completion cost. Introduction When a well has a single produc-tion-tubing size from the pay zone to the surface of the completion, it is categorized as a “monobore” comple-tion. Although there are certain limita-tions to this type of completion, there are many advantages that make it a very attractive alternative to conven-tional completions. Drilling cost and reduced equipment list are the great-est motivators to pursue a monobore well because they directly affect the cost to complete. Most of these wells would not have been feasible if the only option was to complete them in a more traditional manner. However, if there were a system that reduced rig time and decreased the equipment list (e.g., packers and sliding sleeves), while still safely completing the well, these wells would move from the category of unfeasible or marginal to profitable or, in some cases, highly profitable. One of the early methods was simply cementing the completion in the well-bore. Later options include staging the cement process to include equipment that would increase the life of the well and ensure its safe operation. Significant time and effort have been expended to develop a more reliable system for completing these wells and increasing their productivity, making them even more attractive. Specially designed cement-through components, including safety valves and gas lift (GL) equipment, can be credited with mov-ing these monobore completions to the next level. The inclusion of a reli-able safety valve speaks for itself with regard to producing these wells safely, but introducing the GL alternative at the beginning has increased the over-all production significantly. Wells that were estimated to produce 500 to 600 B/D were improved to 1,200 to1,400 B/D. The majority of these completions have been completed in the Gulf of Thailand, but there are other fields in the world that are candidates for this system, and equipment has been mobi-lized to some of those areas.

Dynamic-Underbalance Perforating Overcomes Environmental Challenges

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 108167, "Overcoming Environmental Challenges Using Innovative Approach of Dynamic- Underbalance Perforating," by Dennis Baxter, SPE, Harold McCausland, and Brian Wells, SPE, PetroCanada, and Vinay K. Mishra, SPE, and Larry Behrman, SPE, Schlumberger, prepared for the 2007 Offshore Europe, Aberdeen, 4-7 September. The paper has not been peer reviewed. Wireline-conveyed perforating in conjunction with well flowback evolved as the preferred method for well completions in the Terra Nova field. A consequence of this approach was the need to flare the well at the mobile offshore drilling unit (MODU) to generate the required underbalance. The full-length paper details how a new approach to perforating significantly reduced the environmental risk associated with perforating, while also reducing rig time required for perforating operations without compromising well productivity/injectivity. Introduction Terra Nova is a PetroCanada-operated subsea development off the east coast of Canada. First oil was achieved in January 2002. The field consists of a floating production, storage, and offloading (FPSO) vessel and four associated subsea drill centers connecting three main producing areas. The target reservoir sands are Jurassic and are in the Jeanne d'Arc formation. There are currently 27 wells in the field, including 15 oil producers, 9 water-injection, and 3 gas-injection wells. All wells were drilled and completed from a MODU. A typical well incorporates a 7-in. monobore design to accommodate high flow rates and future intervention requirements. Previous Approach The approach to perforating at Terra Nova evolved over the course of development drilling. As part of the well-planning process, an assessment of perforating alternatives typically was completed for each well to identify opportunities to reduce rig time and flaring requirements. Priorities for perforating included the following.Perforating in an underbalance condition to optimize perforating efficiency.Maintaining a monobore completion through the perforated interval to facilitate future interventions (retrieval of spent guns).Avoiding use of kill pills to prevent near-well damage. In addition, sump availability usually was limited because of overpressure zones and low penetration rates below the reservoir interval. These priorities and limitations typically eliminated the use of tubing-conveyed or stackable gun systems. As a result, use of wireline-conveyed guns, detonated in an underbalance condition, was the typical approach. Underbalance was generated by use of static underbalance for the initial gun run and flowing the well to the MODU for subsequent runs. The wells were flowed to the MODU vs. the FPSO vessel primarily because of concerns regarding the effect of perforating debris on process equipment. To accommodate flowback, the MODU was fitted with a well-test package consisting of the following equipment.High and low stage separators and associated equipment.Dual flare booms with burner heads rated at 2 544 m3/d.Air compressors for oil atomization at burner heads.Zone 1 office.Computerized data-collection network and associated sensors.

Overview: Completions Today (September 2007)

A key aspect to effective completion design is an accurate understanding of the reservoir and bounding formations. Nearly every well completed in a prolific sandstone formation requires sand control, either as a preventive measure or as remediation later in its production life. Formation damage is another problem associated with wells that produce sand unchecked. The possible creation of void spaces behind the casing can leave the casing and any shaly streaks in the reservoir unsupported. The much less permeable shaly streaks that remain can collapse around the slotted or perforated casing, causing severe and irreparable restrictions to production. Most authorities recommend that sand-control techniques be applied immediately upon indication that a formation will produce sand. This practice will allow the highest success rate and the lowest production loss possible after sand control is applied. Laboratory studies have shown that once unconsolidated sand is disturbed, the sand cannot be packed back to its original permeability. Therefore, sand control should be applied before the reservoir rock is seriously disturbed by sand production. Also, operators are opting for advanced sand-control completion technologies in demanding gravel-pack and frac-pack completions. In this environment, the next generation of sand-control completion technologies must be able to handle larger proppant volumes and higher pump rates and place proppant or gravel-pack sand effectively along the sandface completion void free. For most open holes drilled in unconsolidated formations, a gravel pack is the preferred completion option. By filling the annulus between the liner or screen and open hole with specially sized, high-permeability gravel-pack sand, the wellbore is stabilized to control production of formation sand and protect the screen from plugging or erosion. When performed with proper procedures and tools that use the next-generation sand-control completion technologies, gravel-pack and frac-pack completions can be highly productive and long-lasting completions. Finally, the ultimate objective is to create cost-effective technology that builds on proven sand-control technologies and best practices that help operators overcome these serious well-production sand-control challenges successfully. Completions Today additional reading available at the SPE eLibrary: www.spe.org SPE 101987 "Effects of Formation Damage and High-Velocity Flow on the Productivity of Slotted-Liner-Completed Horizontal Wells" by Yula Tang, SPE, Chevron Energy Technology Company, et al. SPE 106757 "Expandable Liner Hanger Resolves Sealing Problems and Improves Integrity in Liner-Completion Scenarios" by James Williford, SPE, Halliburton, et al. SPE 103668 "Case History of One-Trip Monobore Completion System—2 Years of Cement-Through-Monobore Completions in the Gulf of Thailand" by Walt Chapman, Baker Oil Tools SPE 103986 "Improving Performance of the Naturally Fractured Carbonate Reservoirs by Means of Various Stimulation and Completion Techniques" by H. Jahediesfanjani, SPE, University of Oklahoma, et al.

Hibernia Extended-Reach-Drilling and -Completion Record

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 92347, "Hibernia Record Well Breaks Extended-Reach-Drilling and -Completion Envelope," by Carsten C. Elsborg, SPE, Esso Norway, and Adrian K. Power and Paul C. Schuberth, SPE, ExxonMobil Canada, prepared for the 2005 SPE/IADC Drilling Conference, Amsterdam, 23-25 February. In 2002, development began on the northernmost compartment of the Hibernia development project (Block A). To access these reserves, drilling and completing a 31,000-ft measured depth (MD) oil producer was proposed, with a horizontal departure and vertical depth that exceeded the industry extended-reach-drilling (ERD) limits. Successfully drilling this well required the application and extension of available technology. The project required a large monobore completion system. The trajectory required management of weak and unstable intervals across an extended 17,000-ft-MD intermediate section. To meet these challenges, existing local experiences were leveraged, and recognized international expertise was used to supplement existing practices. Introduction The Hibernia development project is in 265 ft of water, 200 miles offshore Newfoundland and Labrador, Canada’s easternmost province, in the Grand Banks region of the Atlantic Ocean. Reservoir access is provided by use of an iceberg-resistant gravity-based-structure (GBS) platform (Fig. 1) with 64 well slots. Two fully equipped and independent drilling rigs service the wells. Drilling was initiated from the structure in 1997. From the beginning, the project was envisioned as an ERD development that would extend the technology and experience limits as the platform matured. The reservoir is a series of thick-layered sandstones separated by intermediate shales. It is subdivided into large compartments or blocks by a series of faults that run bidirectionally across the reservoir (Fig. 2). These faults are highly sealing in nature and, hence, form the independent subreservoirs or fault blocks that make up the larger reserves. In 2002, the operator began accessing Block A, the largest undeveloped reserves block in the project. The block also was the farthest from the platform (approximately 4.5 miles). At the time, several extended-reach wellbores had been drilled to more than 20,000 ft MD. Careful evaluation was made of drilling a subsea-satellite well vs. use of ERD technologies and knowledge gained on similar Hibernia wellbores. The team recommended the ERD option to drill what would become Hibernia B-16 36 (OPA1), the longest well in the world at this true vertical depth (TVD). The reward for success would be significant from a cost-savings perspective if the incremental risks from a drilling and completion standpoint could be mitigated.

Improved Productivity Justifies World Record Underbalanced Perforating Operation

Abstract A Dutch onshore gas well was drilled to a total depth of 5,136 m along hole (3,700 m true vertical depth) with a maximum deviation of 89 degrees. The well was completed with 193.7 mm (7 5/8 in.) 13 ﹪ chrome (Cr13) tubing with a 177.8 mm (7 in.) cemented liner across the reservoir providing fullore access to the pay zone. Due to the very stratified nature of the reservoir, the long-term sustained production depended on achieving vertical connectivity with all the layers. In order to achieve this and maximize productivity, a single run underbalanced perforating operation was required. Due to coiled tubing limitations in this deep, high pressure well, a hydraulic workover unit was selected to deploy and retrieve the guns. A total gross interval of 1,026 m was perforated in one run utilizing 85.725 mm (33/8 in.) deep penetrating guns and thereafter snubbed from the well under live conditions (46 MPa at surface). To date, it is understood that this is the longest section of guns conveyed, fired underbalanced, and deployed out of a live well. This paper addresses the perforating technique selection, the planning and execution process, the major operational learning points, and discusses final productivity results which demonstrate the validity of this technique. Introduction The Anjum reservoir is a Rotliegendes sandstone at a true vertical depth of 3,700 m. Reservoir pressure and temperature are high for onshore Netherlands at 56 MPa and 137 °CDATA[C, respectively. Following discovery of the prospect in 1992 with the Anjum 1 exploration well, Anjum 4 was drilled as the second well in the field. It was designed as a combined appraisal/development well with the objective of providing capacity in the region of six to seven million m3/day. The reservoir is of a highly stratified nature with a number of high permeability features, some of which are on a centimetre scale. The Upper-Slochteren gas-bearing interval is split up into six discrete units, which are correlatable across the whole of the North Netherlands area. The upper three sands dominate in terms of reservoir quality and productivity. There exist two significant and continuous high permeability streaks (HPS) which, if targeted, would provide initial high productivity. However, the longterm sustained production depends on achieving vertical connectivity with all reservoir zones. Therefore, in order to maximize exposure across all intervals, and to provide the maximum connectivity with the individual layers, a sub-horizontal well was designed. A cemented and perforated liner was selected, since it provided the opportunity to effectively bypass near wellbore drilling induced damage. Secondary benefits of this design are that it provides maximum selectivity (water shut off, stimulation etc.) and through the utilization of deep penetrating perforating guns reduces non-Darcy turbulent effects. The well was completed with a 177.8 mm (7 in.) Cr13 liner across the pay zone and a 193.7 mm (7 5/8 in.) Cr 13 monobore completion with a tubing retrievable safety valve to provide maximum wellbore access (Figure 1).

The Use of Slimhole Drilling and Monobore Completions To Reduce Development Costs at the Kuparuk River Field

Summary In 1994, a low-cost development and operating plan for future wells at the Kuparuk River Field was proposed with the goal of reducing well costs 30% by the end of 1996. This paper presents this plan of a slimhole drilling and monobore completion program, a discussion of the critical issues addressed to successfully make the change, and field results from the first 16 wells drilled in 1994 and 1995. A review of historical cost information is included which covers drilling and completing wells using the conventional well designs that had become standard in the field for the previous 10 years. A variety of new slimhole well plans are presented for both production and injection wells together with a discussion of their potential application and cost savings. The paper concludes with a look at future work plans and opportunities for additional cost savings through the use of slimhole wells.

The use of well seismic profiles and LWD to steer a horizontal well

The 9/13a-A53 sub-horizontal well was drilled from the Beryl Alpha platform in order to target bypassed oil reserves and produce low GOR oil. This paper outlines the work of the multi disciplinary team from the planning through to production. The primary producing unit in the Beryl Field is the Middle Jurassic Beryl Formation. In the Central Area of Beryl Alpha, re-injected gas has preferentially moved down structure in the higher permeability upper Beryl Formation sandstones, overriding a substantial volume of oil. Well 9/13a-A53 was designed to target this oil. Innovative data acquisition strategies were employed during the drilling of the well. The approach to the well target necessitated crossing a 150 ft fault and sub-seismic faults/fractures were anticipated within the wellbore. No pilot hole was planned, instead an intermediate look-ahead' well seismic profile (WSP) was run to determine the position of the fault prior to drilling. Real-time logging while drilling (LWD) was incorporated in the drilling assembly to pick stratigraphic markers and react to possible directional drilling changes. This detailed planning resulted in the well being drilled on prognosis. In the well completion, a cemented liner was landed to allow selective perforation, away from potentially gas-conductive fracture zones. A monobore completion was utilized to improve future gas isolation operations and to optimize deliverability. The well came on-line in late 1992 and is currently producing low GOR oil at commercial rates.

Monobore Completions for Slim-Hole Wells

A growing number of operators are looking at monobore and slimhole completion techniques as possible solutions to economic and operational problems. Each technique can enhance the completion, and because the advantages of each concept affect a different phase of well technology, a broad spectrum of operational advantages could be generated is these techniques were merged into a single completion approach. Each philosophy, however, requires specialized equipment to provide its benefits, and attempts to unite the two strategies have created unique challenges for equipment designers. In many cases, these challenges are not really fully understood. This paper overviews several new equipment designs that are ideally suited for monobore completions in slim-hole wells. Also discussed are new servicing methods and how using these options and the newly designed equipment can overcome the difficulties challenging the design of completion equipment for the combined technologies.

Extended Reach and Horizontal Wells Experienced on the Statfjord Field

Statfjord field, the largest producing field in Europe, is located 200 km northwest of Bergen, Norway on the United Kingdom/Norwegian boundary. Statfjord field is being developed with three fully integrated platforms of concrete gravity based on Condeep design. The Statfjord field consists of four reservoirs: Upper Brent, Lower Brent, Dunlin, and Statfjord, which are developed separately. The overall objective for the horizontal and extended reach wells on Statfjord is to maximize the field recovery and accelerate production at a minimal cost. This is done by drilling extended reach wells to the far-away flanks of the field and drilling horizontal wells to drain fault blocks and erosion zones in the Brent reservoir and wedge zones in the Statfjord reservoir. To date, a total of 11 horizontal and extended reach wells have been drilled and completed on Statfjord field. The following have been key factors in drilling the horizontal and extended reach wells: well profile, torque and drag, equipment limitations, hole cleaning, hole stability, mud and cement programs, and surveying. To optimize the well profiles, extensive work has been put into simulating torque, drag, and ECDs. The well profiles are optimized with regards to drilling, completion, and workover, in addition to themore » reservoir targets. The completion is designed to be able to perform all future work through tubing. Factors like zone isolation requirements, well profile, casing program, logging/testing/perforating requirements, and sand production are considered when planning the completion. A 7 in. monobore completion string together with a 7 in. cemented liner is used to meet the completion objective. Several production logging tool, bridge plug, and perforation jobs have been performed on coiled tubing in horizontal wells on Statfjord field. Problems related to hole cleaning, well killing, fishing, and packer setting have been experienced during drilling and completion of the wells.« less