Subsea Field Research Articles

Storing Oil on the Sea Bottom to Improve the Bottom Line

Technology Update The growing desire of offshore operators to speed up subsea field development while reducing costs has fostered many compelling innovations. Among those systems under development to meet this demand, and one with broad applications, is a subsea storage unit (SSU) created by Kongsberg Oil & Gas Technologies. The SSU employs the new concept of a “flexible bag” protected by a dome for oil storage on the seafloor (Fig. 1). Depending on field conditions, the dome can be made of concrete, fiberglass, or steel. The system offers oil companies a safer, more cost-effective method of developing subsea fields in extreme weather zones or in the Arctic where ice floes are prevalent. The SSU is also being qualified for extended well testing (Fig. 2) and early production startup, and it may enhance the economics of fields with insufficient reserves to support full field development. Furthermore, the SSU could be used in place of subsea storage cells, fixed platforms, floating storage units (FSUs), and pipelines. “It is an alternative to existing storage facilities and could also potentially commercialize the development of marginal fields,” said Astrid Rusås Kristoffersen, a subsea systems product and technology manager at Kongsberg. “The [SSU] will increase profitability of marginal fields, because the oil can be stored subsea. And then, using small shuttle tankers for more frequent offloading will precipitate the cash flow and reduce operational costs.” Ideally, two or more SSUs could be used to maximize the allowable output volume that could be uploaded into a tanker. As production increases, SSUs could be added to the cluster. Kongsberg is considering standardizing the dimensions of the SSU to fit different needs, with the largest version on the drawing board being 131 ft (40 m) in diameter with a capacity of 120,000 bbl of oil. Subsea storage technology has been used before in limited applications, but never has the design used a collapsible bag to store the oil. The bag is partly made of a polyester woven yarn that is coated with an impermeable layer on both sides to eliminate the possibility of seawater and oil mixing. Were that to happen, an emulsion layer could form, leading to bacterial growth that could cause corrosive damage inside steel pipe-lines and valves.

Decade of Stimulation Experience in the Deepwater Gulf of Mexico

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 159660, ’A Decade of Deepwater Gulf of Mexico Stimulation Experience,’ by Lee N. Morgenthaler, SPE, and Leigh A. Fry, Shell E&P, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8-10 October. The paper has not been peer reviewed. The deepwater Gulf of Mexico is a technically and economically challenging production environment. High rates and ultimate recoveries are required per well to offset high development costs. Stimulation treatments maintain wells at peak production rates and accelerate reserves recovery. In these complex layered reservoirs, stimulation is necessary to ensure recovery volume. The primary objective of stimulation is to restore impaired well/reservoir connectivity. Successfully identifying the cause and location of impairment is required. Looking back over a decade of experience in this challenging environment yields useful insights as the industry moves into new deepwater provinces. Introduction Shell’s deepwater development began in 1991 with the Tahoe subsea prospect tied back to the Main Pass 252 platform. Development continued with the Auger, Mars, Ram Powell, Ursa, and Brutus tension-leg platforms (TLPs) and many subsea fields that tie back to them (Fig. 1). Most of the reservoirs producing to these structures are geologically young turbidite sands that require sand control. Initially, all of the fields were geopressured significantly above hydrostatic and were significantly undersaturated. The soft compacting sands and aquifer support often provide sufficient energy to achieve adequate recovery by depletion. The hydraulic fractures created in the frac-pack process provided lower skin values with minimal use of acid. The horizontal openhole gravel packs used acid-soluble bridging agents to stabilize the wellbore during gravel packing. The bridging agents were then removed with acid washing. Because most of these sand-control completions were cased-hole gravel packs or cased-hole frac packs, most of this paper refers primarily to the experience with those completion types. As the fields matured, there were more subsea-tieback developments. Stimulation campaigns generally focused on the direct-vertical-access (DVA), or dry-tree, wells of the TLPs. However, stimulation of subsea wells has been highly profitable, and technology has been developed to reduce the subsea-intervention costs to make these interventions more attractive. The complex operations on TLPs introduce challenges when planning and conducting stimulation operations. Logistics coordination and proper management of returning wells to production are critical to realize production gains and to meet environmental-discharge regulations and goals.

World's Longest Electrically Heated Flowline Allows HP/HT Field Tieback to Existing Host

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 161572, ’HP/HT Field Development Tied Back to an Existing Host,’ by Trevor Crowe, Shell, and Jean-Paul Koninx, SPE, and Crispin Slater, A/S Norske Shell, prepared for the 2012 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 11-14 November. The paper has not been peer reviewed. The Linnorm gas/condensate field in the Norwegian Sea is technically challenging. The high-pressure/high-temperature (HP/HT) reservoir contains gas with CO2, H2S, and traces of mercury. Although the gas is relatively lean, the associated condensate has waxy properties. Although there are production facilities within 30 to 70 km, this discovery was initially seen as “stranded” gas because of the absence of an export route with available capacity. The wells and subsea concepts would push the limits of existing technology and require some world-first solutions for what will be the highest-temperature subsea field development on the Norwegian continental shelf with the world’s longest electrically heated flowline. Introduction The Linnorm gas discovery was made during the first half of 2005 in the Haltenbanken area offshore Norway. Well 6406/9-1 found a 180-m net column of lean gas in a gas-down-to situation in three Jurassic reservoir zones, all under HP/HT conditions (180°C, 800 bara). Two reservoir zones were production tested, both with good results. The field was further appraised by Well 6406/9-2 in 2007, successfully determining the gas/water contact in the key reservoirs. Several follow-up exploration wells all proved dry. This meant that the projected hub development for the Halten South area was no longer feasible. The likely way forward for Linnorm then was in the åsgard pipeline became available (currently estimated to occur later than 2020). The project was put on hold in 2007 because Linnorm was not expected to be developed before the 2020s. In summer 2008, an opportunity to accelerate the development of Linnorm was identified by making use of potential ullage in the newly commissioned onshore gas-processing plant at Nyhamna, built to process gas from the giant Shell-operated Ormen Lange field. This would require a new 200-km trunkline, the cost of which made the development commercially marginal. The solution was found by entering a new joint venture, the Norwegian Sea Gas Infrastructure project. The next challenge was to select an option for gas processing. Rather than an expensive new-build platform on Linnorm, the choice was made in mid-2011 for a subsea development with a tieback to the Shell-operated Draugen oil platform. In December 2011, the development concept was confirmed as a two-template, five-well subsea development, with a 55-km directly electrically heated (DEH) flowline tied back to Draugen, and 15 million m3/d of gas-processing capacity installed on Draugen (Fig. 1). Subsurface Uncertainties An extensive wireline formation-sampling program showed that the dis-covered gas is generally fairly dry, with high CO2 content, some H2S, and, on average, 50 Μg/std m3 of mercury. The condensate/gas ratio (CGR) varies per reservoir, with evidence for vertical compartmentalization in up to six different reservoir layers. Reservoir quality is variable, with some very good sands but also large sections with lower-quality tight sandstone. The high variability in reservoir quality across the reservoir leads to a number of specific challenges.

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.

Emerging technology assessment and qualification for subsea fields of the future

Most of the easy subsea oil and gas reserves have been discovered and are being developed. Future subsea developments will therefore need emerging or new technologies for fields that are economically marginal, in deeper waters and with longer offsets. Even existing reserves could benefit from enhanced recovery techniques. The introduction of new or emerging technologies needs careful evaluation and consideration as inherent risks need to be identified, quantified, and addressed. Typical technology interfaces needed to be considered are subsurface drilling and completions, subsea technology, topsides processes and facilities, and installation vessel capabilities.New and emerging technology maturity and gaps can be identified, quantified, and evaluated using recognised international standards such as ISO 20815, DnV RP A203, and API RP 17N. New technologies and the novel combination of existing technologies could become economic enablers, particularly for marginal developments. These enablers need careful evaluation for risk and reward, recognising potential impacts to health, safety and the environment. The following is a list of the typical subsea technologies that can be addressed: Gas compression-a requirement for ultra-long subsea tie backs to shore from remote fields. Water injection-boosts production and deals with waste water rather than treating and overboarding. Boosting and pumping-possible economic enablers. Separation-avoids costly retrieval of fluids and treatment at the surface. Fluids are often re-injected subsea. Sequestration-can be a game changer for environmental reasons. All electric systems. Active heating techniques-such as open and closed direct electrical heating, trace heating, integrated production bundles. Power distribution subsea is also a requirement for many new subsea technologies. This extended abstract examines some of the technologies being developed for future subsea production, assesses their maturity and identifies the technology gaps, and commercialisation necessary to make them economically and technically viable for operators. This extended abstract also takes a glimpse at how the fields of the future may look.

Separation Technology Shrinks To Fit Subsea Development in Deep Water Better

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 23223, ’Compact Separation Technologies and Their Applicability for Subsea Field Development in Deep Water,’ by A. Hannisdal, R. Westra, and M.R. Akdim, SPE, FMC Technologies; A. Bymaster and E. Grave, SPE, ExxonMobil; and D. Teng, Woodside Energy, prepared for the 2012 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed. Deepwater discoveries have driven the development of new compact separation technologies, a core aspect of subsea processing. Compact separators are much smaller than conventional separators and have the potential to significantly reduce capital expenditure for deepwater developments. Unfortunately, reducing the size of separators generally reduces the separation performance and the ability to handle changes in flow rate and composition. Therefore, it is essential to find an acceptable balance between the realized reduction in overall capital expenditure and reduced tolerance to changing conditions. Introduction Value Drivers for Subsea Gas/Liquid Separation. Subsea gas/liquid separation has proved to provide strong business incentives with enabling capabilities, including (1) more-efficient liquid boosting, (2) longer-range gas compression from subsea to onshore, (3) cost-efficient hydrate management, (4) effective riser slug depression, and (5) access to challenging field developments that otherwise would be abandoned or not developed because of their remote location, harsh conditions, longer tie-back requirements, or low reservoir drive. Compact Separation and Available Technologies. The motivation for making compact separators is to improve project economics. Large vessels for deep water are heavy and affect the overall cost of the subsea station. Retrievability of separators is affected by module weight and the availability of installation or intervention ships, which can affect project economics. Reducing the size of separators and their control volume generally reduces the separation performance and the ability to handle changing flows. Even if compact and ultracompact separators minimize the capital expenditure for the subsea station and increase the availability for retrieval, the risk of nonconformance with separation requirements is increased, especially under slugging conditions. Consequently, the risk for loss of revenue because of reduced separation performance is increased compared with that for a large separator. Currently, deepwater subsea separation and boosting applications have been met only by electronic- submersible-pump (ESP)/caisson technology. The caisson is a tall separator that is installed in a dummy well. The system has a tangential inlet to a tall narrow separator that accommodates slugs, provides surge volume for the separated production fluids, and supports the ESP.

Pressure-Transient and Production-Data Analysis of an Unconsolidated Formation

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 147506, ’Pressure-Transient and Production-Data Analysis of a Horizontal Well in an Unconsolidated Formation in Frade, Brazil,’ by Yan Pan, SPE, Russ Ewy, SPE, Don Ringe, SPE, Medhat M. Kamal, SPE, Ralph Affinito, SPE, and Oluwole Sotunde, SPE, Chevron, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed. Frade Asset is a medium-heavy-oil field in the northern Campos basin, approximately 75 miles offshore Rio de Janeiro in 3,500-ft water depth. The structure is a low-relief anticline with two main fault blocks consisting of four stacked unconsolidated reservoirs. The field produces from nine horizontal oil wells with three vertical water-injection wells to maintain reservoir pressure. Continuous well monitoring and reservoir characterization are key to cost-efficient development in this deepwater subsea field. Introduction The development strategy for the field includes horizontal production wells and deviated injection wells to maintain reservoir pressure. The asset-management team realized the challenges of this particular field and made the decision to install permanent downhole gauges in every production and injection well drilled, with a reservoir-surveillance plan in place to monitor well and reservoir performance. Active reservoir surveillance enabled engineers to make sound and quick operating decisions, such as shutting in wells, changing chokes, or planning well interventions on the basis of dynamic data collected continuously at wells. It also provided real-time information for improved reservoir characterization, model forecasts, and optimized development plans. Because data stream in continuously, the cycle from data collection to updating reservoir models to forecasting field performance to optimizing development could be shortened. Example Well: Producer 2 Well Producer 2 is in the upthrown fault block, as shown in Fig. 1, and had an original reservoir pressure of 3,079 psia and a reservoir temperature of 110°F. The net pay thickness is approximately 42 m, and the horizontal well was drilled 30 m above the sealing bottom of the reservoir. The well trajectory was parallel to the fault to the southwest and to the axial fairway edge to the northeast. The well was completed with an openhole gravel pack, and the total completion length was 507 m. The permanent downhole gauge was installed above the top of the gravel-pack completion.

Cathodic Protection Custom Retrofit Ensures Integrity of Subsea Manifold

Technology Update Preventing corrosion on subsea architecture is critical for operators in their effort to maintain an asset’s integrity and extend field life. Failure to do so can lead to unscheduled maintenance, deferred production, and possible punitive costs should environmental damage occur. Cathodic protection (CP) can be a cost-effective means of preventing corrosion and should be considered as part of any long-term integrity management strategy. With accurate datasets, it is possible to predict the most likely future state of a structure’s integrity, which aids in planning preventive measures. When a CP system reaches the end of its design life, a retrofit system is often required to ensure that an asset’s integrity is not compromised. A recent example was a custom retrofit system designed, engineered, and supplied by Stork Technical Services to Marathon Oil for the cathodic protection of its West Brae field subsea manifold in the UK North Sea. The system needed repair and the measures had to be carried out without causing a major disruption to oil and gas production. Developing a CP System A CP system comprises an anticorrosion coating and either sacrificial anodes, the most commonly used subsea, or impressed current anodes with a power unit to drive them. A system is designed to operate for a fixed period, usually between 10 and 30 years. However, the extension of field life and addition of facilities to an asset can compromise the original design by increasing the surface area and members, which may reduce the effectiveness of the anodes installed as part of the original design. The aim of a CP system is to polarize a structure as quickly as possible and maintain the optimum protection for the design life. When depolarization begins, the system has reached the end of its design life. Either a retrofit system is installed or the structure is allowed to operate in an underprotected state. Underprotection may be allowed because installing a new system may overprotect another connected component, and that could create other failure risks with a higher impact. Overprotection and the materials used must be evaluated in the CP system design. Hydrogen blistering, cracking, and embrittlement can occur when a system is overprotected. Susceptibility to such damage depends on the structure and hardness of the metal in question. For example, super duplex steels are the metals most commonly affected by overprotection hazards in subsea oil and gas applications. As the supply of a high current at low voltage is central to CP, a proper consideration of the equipment and its use is essential to ensure that repeatability, historical traceability, and accurate measurement in the range of <10 mV are achieved.

An Ultradeepwater Heavy-Oil Development Offshore Brazil

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 20537, ’Parque das Conchas BC-10 - An Ultra- Deepwater Heavy Oil Development Offshore Brazil,’ by K.H. Stingl, Shell International E&P, and A. Paardekam, SPE Shell Brazil E&P, originally prepared for the 2010 Offshore Technology Conference, Houston, 3-6 May. The paper has not been peer reviewed. Parque das Conchas is an ultradeep-water heavy-oil development in the northern Campos basin offshore Brazil. The project is a joint venture between Shell, Petrobras, and Oil and Natural Gas Corporation of India. The first phase of the project is the development of three independent subsea fields tied back to the centrally located turret-moored floating production, storage, and offloading (FPSO) host facility, the FPSO Espirito Santo. Introduction The Parque das Conchas development grew out of a substantial exploration and appraisal program beginning in 2000 in which 13 wells were drilled and six discoveries were made. The Declaration of Commerciality was signed with the Brazilian National Petroleum Agency in December 2005, and the project was sanctioned in November 2006. The four main reservoirs—Ostra, Abalone, Argonauta B west, and Argonauta O north—were named after shellfish indigenous to the area. Together, they form “Parque das Conchas,” or “Shell Park,” in Portuguese. This is the first project in Brazil taken by Shell from exploration discovery to production. First oil from Phase 1 was achieved on 12 July 2009, just 9 years after discovery. Development Abalone, Ostra, and Argonauta B west are small-to-medium in size and stratigraphically complex, with highly faulted, compartmentalized, unconsolidated sand packages. The reservoir pressures are low, and the oils range from heavy to light, ranging in gravity from 17 to 42°API. A fourth heavy-oil field, Argonauta O north, will be tied back as part of Phase 2 and is planned to be ready for production in 2013. The Argonauta O north field contains 16°API oil and will require waterflood for reservoir-pressure support. The Phase 1 subsea infrastructure consists of 10 producing wells and one gas-injection well connected by 100 km of insulated and uninsulated flowlines ranging in size from 6 to 12 in., 15 flow-line sleds, two production manifolds, two artificial-lift manifolds housing a total of six vertical subsea-separation caissons with 1,500-hp electrical submersible pumps (ESPs), and 25 rigid jumpers, all of which are serviced by approximately 30 km of multicircuit high-voltage electrohydraulic (HVEH) umbilicals connected to the FPSO. The gas is processed on the FPSO, and to avoid flaring and to reduce CO2 emissions, it currently is being injected into a gas-injection well. A dedicated 40-km-long 6-in. uninsulated Parque das Conchas trunkline has been installed from the FPSO and will be tied into the Petrobras Caipixaba gas-export pipeline at the Petrobras BC-60 location scheduled to be operational in 2010. The oil is stored on the FPSO and offloaded to shuttle tankers as required.

Technology Focus: Reservoir Performance and Modeling (September 2010)

Technology Focus Understanding and management of subsurface uncertainties are crucial for successful development of early-phase projects. The development solution, drive mechanism, processing capacities, and number of slots needed all affect the net present value and the capital and operating expenses. Planning and execution of early-phase data acquisition and the effect these data have on late-life economics are a theme that deserves more attention. Concept selection is the most important part of an early-phase development from a subsurface point of view. Because of the high well cost, deepwater projects are sanctioned with few appraisal wells and limited dynamic information. The importance of an overall strategy to manage subsurface uncertainties is described in the paper regarding the development of the greater Plutonio area. Dynamic information, both horizontal and vertical permeability, is always on top of every reservoir engineer’s wish list. Wireline formation testing is a cost-effective way of addressing dynamic information, keeping in mind that an extended well test or a drillstem test is not always feasible for economic or practical purposes. Determination of remaining oil is key to increased oil recovery. A proactive approach to surveillance gives insight into the reservoir and has potential to mitigate unpleasant surprises. The paper describing the proactive well and reservoir management and the paper assessing fluid migration and quantifying remaining-oil saturation are both excellent examples of creating value through systematic reservoir surveillance. Reservoir Performance and Monitoring additional reading available at OnePetro: www.onepetro.org IPTC 13640 • “Successful Reservoir Monitoring With 4D Microgravity at Ras Laffan, State of Qatar” by A.F. AhmadZamri, SPE, RasGas Company, et al. IPTC 13185 • “Reservoir Modeling and Production Evaluation in Shale-Gas Reservoirs” by C.L. Cipolla, SPE, Carbo Ceramics, et al. SPE 127858 • “Perdido: The First Smart Field in the Western Hemisphere” by Robert K. Perrons, SPE, Shell. SPE 128137 • “Integrated-Production-Model Calibration Applied to a Gulf of Mexico Subsea Field” by L. Saputelli, SPE, Hess Corporation, et al.

Subsea-Hardware Installation From an FDPSO

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 20495, ’Subsea-Hardware Installation From an FDPSO,’ by Thomas J. Stensgaard, Murphy West Africa, and Charles E. White and Kevin R. Schiffer, Doris Inc., prepared for the 2010 Offshore Technology Conference, Houston, 3-6 May. The paper has not been peer reviewed. Subsea installation for deepwater-field developments requires specialized vessels to carry out the work. A floating drilling, production, storage, and offloading (FDPSO) vessel positioned directly over the drill center provides an alternative to traditional methods. Unique challenges related to subsea-hardware installation from an FDPSO and the methods developed to overcome those challenges are presented. Introduction The FDPSO is over the wells for direct access (Fig. 1). Therefore, performing subsea-construction and -intervention activities directly from the host becomes possible. The FDPSO provides a large stable platform from which these activities can be accomplished, but it has limited access and maneuverability, and challenges that must be addressed. These challenges were overcome in the Azurite field in the Mer Profonde Sud Block offshore the Republic of Congo. The FDPSO was fitted with a remotely-operated-vehicle (ROV) spread and a crane sized to install heavy hardware. Subsea Scope and Field Architecture The Azurite field subsea architecture was driven primarily by the excursion capability of the FDPSO, which was in turn determined by the mooring system, flexible-production-riser limitations, and water depth. All production and injection wells were required to be within a 45-m radius, enabling access by the drilling rig on the FDPSO. This close well spacing supported either a template development or a tight cluster of wells in a radial array around a subsea manifold. The cluster configuration was chosen, with wells surrounding a combined production/water-injection manifold as shown in Fig. 2. The multiphase pumps and a subsea distribution unit (SDU) were placed nearby but outside of the drilling circle to permit intervention activities from the FDPSO if problems arose. FDPSO vs. Subsea-Construction Vessel Several functional requirements must be provided for nearly all subsea-installation campaigns and include the following. Transportation of equipment to the offshore worksite Lifting capacity offshore Means to lower equipment to and land equipment on the seafloor Underwater control and intervention Subsea-positioning capability Typically, a subsea-construction vessel equipped for these functions is used. However, these vessels are expensive and have limited windows of availability. With the FDPSO, with the host directly over the drill center, an alternative to traditional subsea installation was studied. The FDPSO provides an inherently stable work platform from which to perform installation operations.

Managing Formation-Damage Risk From Scale-Inhibitor Squeeze Treatments in Deepwater, Subsea Fields in the Campos Basin

Summary This paper describes field experience and lessons learned from bullhead-deployed scale-control operations in a deepwater subsea development in the Campos basin, Brazil; specifically, this paper is about deploying such treatments from the floating production, storage, and offloading (FPSO) host, along the production flow-lines, and into four low-water-cut, horizontal, subsea wells completed with sand control. The relatively small number of high-cost, highly productive wells, coupled with a very high barium sulfate (BaSO4) scaling tendency upon breakthrough of injection water, meant that not only was effective downhole scale management critical to achieve high hydrocarbon recovery, but that even wells at low water cuts were deemed to be at sufficient risk to require squeeze application. Initial bullheaded scale treatments comprised three "hybrid" treatments: a mutual-solvent preflush, a water-based main flush, and a diesel overflush. As water-production rates rose, so did the treatment volumes required. To improve the logistics of these treatments and to mitigate issues that arise from poor injectivity of diesel in these wells, core studies were conducted to investigate the option of changing the overflush fluid from marine diesel to injection-quality seawater. This change also introduced the possibility of forming a gas-hydrate plug during shut-in, but this was managed by use of a thermodynamic hydrate inhibitor and by replacing the flowline contents to flashed crude during the shut-in period. Both the operational aspects and the response of the wells to the modified treatments will be compared with those previously deployed in terms of, in particular, the injectivity of the wells during treatment and well-treatment cleanup rates and productivity afterward. The core studies also highlighted a formation-damage mechanism caused by incompatibility between the mutual solvent and the produced oil; this required modification of the treatment.

BP's Subsea Developments

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 113652, "BP's Subsea Developments: Past Successes and Future Challenges," by Fikry Botros, Cornelia Noel, SPE, David Brookes, SPE, and Robert Perry, BP plc, originally prepared for the 2008 SPE Indian Oil and Gas Technical Conference and Exhibition, Mumbai, India, 4-6 March. The paper has not been peer reviewed. The full-length paper presents an overview of BP's many milestones in subsea projects over the years. The next wave of deepwater and subsea projects will require the development of reservoirs with compound issues. Some of these reservoirs are in remote regions with few offshore host facilities and ecologically sensitive environments. Introduction Currently, BP has approximately 180 subsea wells worldwide, producing approximately 127 190 m3 of oil and gas. This number of wells is expected to double over the next 5 years as the company continues to explore and develop difficult reservoirs in deeper and more-remote hydrocarbon basins. The first subsea wells in the mid-1970s were in the Arabian Gulf. In the 1990s, harsh-environment field developments based on floating production, storage, and offloading (FPSO) vessels were completed in deepwater West of Shetland. Since then, BP has developed and operated subsea fields worldwide with ever-increasing water depths and distances to production hubs. These hubs range from fixed platforms to floating deepwater vessels, tension-leg platforms, FPSOs, semisubmersibles, and spars. Most notable is the series of very large and complex developments in the Gulf of Mexico (GOM), Angola, and Norway. The water depths for the GOM developments exceed 2500 m and in some cases have high-pressure/high-temperature (HP/HT) reservoir conditions of 1000 bar and 130°C, respectively. Off the coast of West Africa, the development of the Greater Plutonio field has been completed successfully by use of an FPSO host, with follow-on plans to develop four additional subsea developments, three of which will be in ultradeepwater Block 31 (2500-m water depth) using modular FPSOs. In Norway, the Skarv harsh-environment FPSO-based subsea development is under development currently. In addition, there are plans to develop a large number of subsea tieback projects to existing facilities, including the record-breaking 72-km Taurt gas development in Egypt and the King-development subsea boosting project in the GOM. Early Developments (1970–1999) North Sea. The five-well Buchan subsea development, started in 1981, is tied back through tensioned-steel vertical risers to a pentagon-style floating rig. In 1988, the two-well Seillean subsea development was the first to produce by means of tensioned risers tied back to a dynamically positioned floating production, storage, and trans port vessel (the forerunner of extended-test and early-production systems). The Magnus field, in 186 m of water, started in 1981, used multiplexed electrohydraulic control systems. The Don field, a 17-km host offset, and the Andrew field with the then-novel 6-km pipeline-bundle tieback concept, followed. The Machar field was completed in 1996 and included the longest black-oil single-leg tieback, approximately 35 km. It also boasted the first subsea pig launcher and subsea metering system.

Scale Inhibitor Squeeze Treatments Deployed From an FPSO in a Deepwater, Subsea Fields in the Campos Basin

Summary This paper describes field experience and lessons learned from scale control operations in a deepwater subsea development in the Campos Basin, Brazil; specifically, from bullheading scale-inhibitor squeezes from the FPSO host, along the production flowlines, into four low-watercut, horizontal subsea wells, completed with sand control. The relatively small number of high-cost, highly productive wells, coupled with a very high barium-sulfate scaling tendency upon breakthrough of injection water, meant that not only was effective scale management critical to achieve high hydrocarbon recovery, but even wells at low water cuts were deemed to be at sufficient risk to require squeeze application. Use of conventional, water based squeezes have been known to cause significant damage to productivity in low-watercut wells, including those showing a fines-migration tendency, as was the case here. Hence, on the basis of risk mitigation, supported by an extensive program of laboratory testing, it was decided that for the initial treatments, only the mainflush would be water based, with a mutual-solvent preflush and marine-diesel overflush. Other key challenges associated with treating from the host included the remote location of the wells, the potential to form hydrates, the cleanliness of the lines along which the treatment would pass, the achievement of effective placement over a long producing interval, as well as the need to deploy the chemical package via a support vessel adjacent to the FPSO. All had to be managed because of the high cost and low availability of a deepwater rig that could deploy the treatments directly to the subsea wellheads. This paper will explore in detail the issues associated with inhibitor-squeeze deployment in deepwater, subsea fields, many of which are currently being developed in the Campos basin, Gulf of Mexico, and West Africa, and are a good example of best-practice sharing from another oil basin.

Operations Management Extends Field Life of a Long-Distance Subsea Tieback in Ultradeep Water

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18830, "Innovative Operations Management and Flow-Assurance Strategies Extend Field Life and Increase Ultimate Reserves of a Long-Distance Subsea Tieback in Ultradeep Water," by Aditya Singh, SPE, and Kevin Hannaford, Total E&P USA, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May. In 2004, the subsea fields comprising the Canyon Express system were declining and water-production rates were increasing. To halt the fast decline and extend the life of the field, flow-lines were reconfigured to separate the depletion-drive wells from waterdrive wells. A real-time production-management tool for enhanced production planning, monitoring, and trouble-shooting was implemented. Introduction The Canyon Express transportation system consists of two 12-in. flowlines running parallel from Camden Hills through Aconcagua and Kings Peak to Canyon Station platform. The three subsea fields—Camden Hills, Aconcagua, and Kings Peak—are in 6,200 to 7,250 ft of water. The Canyon Express subsea tieback, at 56 miles from Camden Hills to Canyon Station platform, is one of the longest subsea tiebacks in the Gulf of Mexico. Production from the fields is predominantly gas with condensate and produced water. The wells are tied together by means of a daisy-chain arrangement. Fig. 1 shows a Canyon Express schematic. During midlife operations, increasing water production from waterdrive reservoirs (Aconcagua AC1 and AC2, Camden Hills CH1 and CH2, and Kings Peak KP1 and KP2) and declining reservoir pressures of depletion-drive reservoirs (Aconcagua AC3 and AC4) led to high liquid rates and lower gas rates. The declining depletion-drive wells were restricted by higher water rates and liquid holdup in the flowlines. To optimize production during this period of increasing water rates and declining gas rates, several production options were considered. Detailed flow-assurance analysis was performed for each of the proposed options, and a recommended solution was reached on the basis of clearly identified advantages and disadvantages for each operating scenario. Flow-assurance evaluations were used on a continuous basis for operations planning to optimize and maintain production during this period. Evaluation of Late-Life Options Scenarios of the operating conditions to be studied were defined. Sensitivities on arrival pressures, gas-production rates, and water-production rates were developed from time points in the production forecast for evaluating the possible late-life operating techniques. A matrix of cases to be evaluated was developed.

Integration of 4D seismic data and the dynamic reservoir model reveal new targets in Gannet C

Two sets of 4D seismic data gave major new insights into the structure and dynamic behavior of the Gannet C oil and gas reservoir in the U.K. Central North Sea. The 4D data revealed major extensions of reservoir units previously presumed to be absent or thin over much of the reservoir. Furthermore, in a subsea field with significant uncertainty of production allocation, 4D also proved an invaluable history-matching parameter for the dynamic model. Together, the dynamic model and the 4D data gave rise to the identification of one recompletion opportunity and two infill well opportunities, to produce oil volumes in existing and newly identified reservoir sands. These now have been realized, roughly trebling oil production from the field.

Reservoir Management in a Deepwater Subsea Field—The Schiehallion Experience

Summary The Schiehallion field has experienced many reservoir management challenges since first production in 1998. Dynamic data such as formation pressures, pressure-transient analysis, interference testing, tracer analysis, and 4D seismic need to be interpreted with great care—Schiehallion has examples in which the data have been invaluable and others in which the data are ambiguous or misleading. It is essential to integrate several data types to obtain reliable conclusions. This paper describes some of the highlights and pitfalls experienced in Schiehallion.

Overview: Subsea Technology (August 2006)

Once again, OTC thrived with projects, new technologies, and presentations that met the highest standards and expectations. This year, boosted by the steady increase in oil prices—having surpassed U.S. $70/bbl—attendance reached 59,236, the highest since 1982. Attendees from more than 110 countries were able to exchange their expertise on the development of offshore resources in the fields of drilling, exploration, production, and environmental protection. Subsea technology, more than ever, was a key factor in the huge success of this "Engineering Celebration." As such, it is the focus of the papers selected for this feature, by means of which JPT seeks to present state-of-the-art technology in the quest to find and produce offshore oil and gas. Highlights include the development of two gigantic fields in western Africa and Brazil. These two fields will provide invaluable knowledge on how to use floating production, storage, and offloading vessels in the Gulf of Mexico (GOM), our next technological frontier. Another highlight is the technical challenges and opportunities for subsea processing and boosting. Several companies are investing in these technologies, aiming at applying them in the North Sea, GOM, Brazil, and western Africa. Such technologies, when put together, will be able to tackle the water-production challenge and will allow the production of new heavier-oil discoveries; they also will enable development of long tiebacks for oil and will play an important role in the subsea-to-shore challenge. The efforts of our industry to overcome challenges in the development of subsea fields are well evidenced by the "Spotlight on New Technology Awards" at this year's OTC. From the 13 new technologies recognized with the award, one was for subsea boosting and another for subsea separation. In the near future, most certainly, new- or old-field developments will adopt a combined solution of sub-sea processing and boosting. The benefits seem very clear. Therefore, I am especially pleased to invite you to read this impressive collection of topics for their scope, content, and effect on the industry. I hope you enjoy it. Subsea Technology additional reading available at the SPE eLibrary: www.spe.org SPE 100662 "Scale-Inhibitor Testing for Multiphase Pipelines in a Subsea-to-Shore Development With a Closed MEG-Loop System" by E.N. Halvorsen, Hydro Oil & Energy, et al. Available at the OTC Library: www.otcnet.org OTC 17810 "NDP Review of State of the Art in Riser Monitoring: Lessons Learned and Experiences Gained," by M. Chezhian, Det Norske Veritas, et al. OTC 18318 "Evaluation of Low-Dose Hydrate Inhibitors (LDHI) for a Long-Distance Subsea Tieback in Ultradeep Water," by A. Singh, SPE, Total E&P U.S.A. Inc., et al.

Technology Update: New Options, Improved Economics from Aerogel Insulation

The challenges facing oil and gas operators seeking to develop new fields in hostile environments such as deep and ultradeep water are well documented and continue to increase. One important requirement for operators developing subsea fields is the ability to transport unprocessed hydrocarbons, which are frequently at high pressure and high temperature, over longer distances along the ocean floor. Without sufficient insulation, the hydrocarbons will cool and create hydrates/wax buildup that can eventually clog flowlines at significant cost to operators. Cabot Corp. has developed Nanogel aerogel, a nanoporous insulation product, to address associated economic and efficiency issues. Sometimes called "frozen smoke," aerogels are light insulating solids. Nanogel is a hydrophobic aerogel produced as particles, each of which consists largely of air (≈95%) trapped in nanosized pores that severely inhibit heat transfer through the material. A proprietary manufacturing method imparts mechanical benefits (NanoSprings) to the aerogel particles in addition to characteristics that make them useful for thermal insulation. The aerogel performs across a range of temperatures (from –200 to +250°C) making it applicable in systems ranging from liquefied natural gas (LNG) to high-pressure/high-temperature settings. Four products have been developed for the oil and gas market—the Expansion Pack, Compression Pack, Particle Pack, and Thermal Wrap systems. The first two are pipe-in-pipe products and use half-shells made with Nanogel aerogel particles compressed and packed under vacuum. In field application, a series of half-shells is positioned in a pipe-in-pipe or other assembly and activated (vacuum is breached), resulting in form fitting of compressed particles into a desired shape, either filling the entire annular space (Expansion Pack) or, under higher compression, filling a predetermined portion of the annular space (Compression Pack). Operating Economics There are two ways in which improved economic impact is created during development of subsea fields—by allowing the use of smaller jacket pipes and by enabling the construction of longer tieback lines. In the case of smaller jacket pipes, substituting Nanogel for other insulation forms (such as polyurethane [PU] foam/rock wool) allows operators to reduce the size of outer pipes without compromising system performance (U-value), resulting in:Material savings on pipe steel.The ability to fit more pipe sections on a barge or reel, thereby reducing the number of barge trips.The ability to use smaller lay barges that have lower day rates. For example, to achieve a target U-value of 0.7 W/m2·K with an 8-in. flowline, an outer pipe of approximately 14 in. would be required if the insulation were PU foam. With the Expansion Pack system, the size of the outer pipe could be reduced to approximately 11 in. (Table 1).

Coreflood Studies Examine New Technologies That Minimize Intervention Throughout Well Life Cycle

Summary With the development of more and more subsea fields, the challenge for scale-inhibitor squeeze treatments is to reduce intervention frequency by extending squeeze treatment lifetime while con-comitantly reducing any potential damage in both low water-cut and high water-cut wells. This paper discusses the technical problems and examines new technologies for treatment of such production wells through their life cycle. This paper covers the findings from late 2001 through early 2002. Because even newer technologies have been developed since the writing of this paper, it should be read as the history of technological development. Scale control technology available to control scale formation within the reservoir and near-wellbore area of production wells will be outlined with a focus on the current developing technology to control scale within low water-cut wells. Moreover, this paper shows that the new technical area of emulsion-scale-inhibitor-delivery systems, originally designed to control scale within low water-cut wells, has applications in both low and high water-cut wells. This study assists in developing an understanding of the mechanism of interaction of emulsion-based products—in particular, the impact of the level of water saturation within the core system. In addition, it demonstrates that the emulsion particles are retained in the core matrix during both crude and brine flowback. This paper indicates that the emulsion product offers the potential for extremely long squeeze lifetimes with minimal damage in oil-production wells with rising water cut. It also demonstrates how different technologies have their own place in the life cycle of a production well.