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Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Kuwait International Petroleum Conference and Exhibition held in Kuwait City, Kuwait, 10-12 December 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. A Comprehensive simulation model was used to determine multi contact miscibility and suitable equation of state with CO2 as a separate pseudo component using one of the industry's standard simulation software. Experimental PVT data for bottom hole and separator samples including compositional analysis, differential liberation test, separator tests, constant composition expansion, viscosity measurements and swelling tests for pure CO 2 were used to generate and validate the model. In addition to that, simulation studies were conducted to produce coreflooding and slimtube experimental models, which were compared with the conclusions drawn from experimental results.
Pressure maintenance support in mature fields where permeability heterogeneity is present requires proper distribution of injected water into the respective zones of interest. This process can be extremely challenging, if no method for allocating the proper amount of water into each zone is available. An operator in the South China Sea, who had initiated a water injection project using legacy single-string two-zone completion technologies, found himself in this predicament, since no selective control for pressure maintenance had been considered for the project.
During the past few years, the application of intelligent completion (IC) technology has increased rapidly. This acceptance has been due primarily to its proven capabilities for reservoir monitoring and corresponding optimization of well performance without well interventions. Historically, the majority of IC applications have been in production wells; however, an increasing number of operators have started adopting IC technology for their injector wells.
This paper presents a case study in which IC technology was successfully applied in an offshore field in the South China Sea to provide an efficient water-injection method for optimizing pressure support as well as sweep. The operator selected this technology, as it presented a solution for optimizing the water injection. In addition to eliminating problems experienced with the incapability of the legacy completion technology to monitor water allocation and pressure maintenance for each zone, the IC technology would allow selective well testing for each zone. By evaluating the reservoir properties and characteristics of each zone independently, an intelligent completion would provide another key benefit to the operator, since it would comply with the platform size restrictions for the pumping equipment.
The paper will discuss field objectives, the conceptual design, the design obstacles, and the operational challenges experienced during the job execution.
The increase in offshore activity in harsh weather areas of the world presents a major challenge for those involved in the management and execution of lifting operations. This challenge becomes all the more important when personnel are being transferred by crane. This paper examines some of the new technologies and operational philosophies that promise to help operators meet these new challenges. This includes motion monitoring technology developed in Norway that provides accurate real-time data on vessel responses for mariners, and crane operators, allowing them to increase the safety and extend the limits of lifting operations. Crane operational downtime has a major financial impact on arctic projects. Therefore there is pressure to maintain continuity of lifting operations. This proven technology - the Deck Motion Monitor (DMM) and the Arctic personnel carrier - allows the safe transfer of cargo and personnel for a higher percentage of time and reduces the time spent waiting for an optimal weather window.
Bowen, A.D. (Woods Hole Oceanographic Institution) | Jakuba, M.V. (Woods Hole Oceanographic Institution) | Yoerger, D.R. (Woods Hole Oceanographic Institution) | Whitcomb, L.L. (Johns Hopkins University) | Kinsey, J.C. (Woods Hole Oceanographic Institution) | Mayer, L. (University of New Hampshire) | German, C.R. (Woods Hole Oceanographic Institution)
We describe a new underwater vehicle for under-ice telepresence, NereidUI (Under Ice). This paper discusses potential applications,environmental and logistical constraints, and progress to date. Based on lightdata-only fiber tether technology, Nereid UI will provide operatorswith a capability to teleoperate a ~1000 kg remotely operated vehicle (ROV)under fixed ice at ranges up to 20 km distant from a support ship or otherdeployment site under direct human supervision. When operating from anicebound support vessel, the light fiber technology permits the vehicle toremain stationary on the seafloor or maneuver freely in the water column orunder the ice while its support ship drifts with the sea ice up to 20 kmaway. Nereid UI will facilitate its recovery autonomously in theevent that the tether is severed. Prior experience with the hybrid ROVNereus 11,000 m rated vehicle, along with trade studies and conceptdevelopment devoted to Nereid UI has revealed (1) the light fiberconcept is viable in polar waters; (2) battery operation and the need totransit result in an ROV that occupies a unique trade-space with respect todrag; (3) redundant systems and a focus on reliability are necessary to avoidexpensive losses in productivity or the vehicle itself. The Nereid UIproject is supported by the National Science Foundation and the Woods HoleOceanographic Institution.
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 150079, "Managing Fields Using Intelligent Surveillance, Production Optimization, and Collaboration," by Frans G. Van den Berg, SPE, Andrew Mabian, SPE, Ronald Knoppe, Edwin Van Donkelaar, Frans Terlaan, and Valentin Koldunov, SPE, Shell, and Rufina Lameda, Science Applications International Corporation, prepared for the 2012 SPE Intelligent Energy International, Utrecht, The Netherlands, 27-29 March. The paper has not been peer reviewed.
Asset professionals in Shell use advanced technologies and processes for field management and optimizing production performance. Real-time monitoring of wells and compressors has become the norm, delivering higher uptime and increased production. Wells and facilities with events or deviations (i.e., exceptions) are highlighted, enabling staff to focus on fixing critical wells and facilities. The information is brought together in collaborative work environments (CWEs) with a video connection to streamline communication between field and office, and to expedite decision making.
In general, all of Shell’s new field developments, and redevelopments of existing fields, are equipped with appropriate smart-fields solutions. The elements selected in each field depend on its features and conditions. A screening process is carried out in the early stages of the project to identify requirements and opportunities for implementation. In some cases, application has changed the development concept completely (e.g., field development with smart wells and a remotely controlled platform). In other cases, solutions help improve field management.
Applications were implemented in the West Salym field in western Siberia, Russia. West Salym is the largest of three fields in the Salym Petroleum Development (Fig. 1). Since 2003, approximately 600 wells have been drilled, of which approximately 450 are producers and 150 are water injectors. Field production peaked in 2011 at approximately 180,000 B/D. Production decline would start within 5 years, and production was expected to continue for another 10–15 years. The wells were drilled from drilling pads, each with 16–20 well slots.
Each production well was equipped with an electrical submersible pump (ESP) and a variable drive control. The frequency of the ESPs (and, hence, the pump rate) was optimized weekly for production optimization and ESP-performance optimization and to keep the drawdown on the wells constant and the reservoir pressure above the bubblepoint. Frequent adjustments of the ESP settings were required because the reservoir responded fast to any changes in injection rates.
A two-step analysis can provide the key information needed to design optimal shale completions. The first step is to evaluate reservoir quality, which describes the hydrocarbon potential of a shale. The second step is to evaluate completion quality, which describes stimulation potential. Core analysis provides the basis to help calibrate the results of these two steps. The intersection of good reservoir quality and good completion quality leads to the best chance for success in shale completion. However, a failure to address both reservoir quality and completion quality will jeopardize the achievement of the ultimate goal: optimized production.
A shale reservoir by definition is a hydrocarbon source, reservoir, trap, and seal in a single package. Though similar in outward appearance, no two shales are alike. They are typically complex, heterogeneous rocks with extremely low permeability. Stress anisotropy is commonplace. This calls for the judicious integration of geology, petrophysics, geomechanics, and reservoir engineering to solve the puzzle that will enable the reservoir to yield its prize.
To determine reservoir quality, defined as the hydrocarbon potential of a shale, it is necessary to quantify the amount of hydrocarbon in place and its deliverability to the fracture face. To do this, we must know the organic matter content and type, its thermal maturity, the effective porosity, fluid saturations, matrix permeability, and reservoir pressure.
The hydrocarbon in shale has evolved from thermogenic or biogenic alteration of kerogen, a fossilized organic material that is the source of oil and gas. In addition to providing the hydrocarbon source, kerogen plays a key role in developing reservoir quality in shales. Its degeneration creates pore space that makes up in part for the porosity lost during sedimentary compaction.
Because of its extremely high surface area and affinity for hydrocarbon molecules, this pore space is an excellent storage medium for gas, which becomes adsorbed onto the organic surfaces. In addition, free gas or oil may exist in larger pores, both within kerogen and between mineral grains. Understanding the mix between adsorbed and free hydrocarbons is essential for calculating total hydrocarbon content. Because of the role of kerogen in creating pore space and providing hydrocarbon storage, there is a strong correlation between kerogen content and total porosity, hydrocarbon saturation, and permeability. Therefore, kerogen content, or total organic carbon content (TOC), is an important indicator of overall reservoir quality.
The United Kingdom is attempting to emulate the unconventional gas bonanza that has transformed the United States from having an energy industry that was in its “sunset” era to a nation rich in energy resources. The UK, which sits on significant shale reserves, wants to become part of this game-changing industry, viewing it as an exciting opportunity as it looks to revolutionize the energy landscape for the next generation.
By its very nature, the country has a dense population with a rural and agricultural countryside and, though it boasts a huge offshore infrastructure, lacks onshore support and infrastructure. Add the obstacles of environmental concerns, a need to build awareness, and a cautious political uptake, it could take 2 more decades before investment decisions by industry could turn concern about the value of unconventionals into certainty.
Unconventional gas has a particular production profile and economics; consequently, operators must be able to drill, produce, and build facilities within tight cost parameters, which can be marginal. The underpinning culture and supply chain in the North Sea is not as conducive to that development. Therefore, it is crucial that there is a fundamental shift in the approach toward equipment, infrastructure, service industry support, and onshore and community stakeholder engagement.
Historically, the UK and Europe have engineered large gas deposits offshore and deployed pipeline and transport facilities to handle the delivery of large volumes of conventional high-pressure gas to market. Therefore, the existing base infrastructure presents a costly challenge for unconventional operators seeking entry into the industry. It is also true that where there has been the opportunity to turn gas into electricity by generation, both the generating and distribution network is geared to high-voltage, coal-fired power stations and nuclear electricity generation.
The story now centers on the indigenous supply of natural gas. Five years ago, it looked as though the world might have only 50 to 60 years’ worth of gas. However, by some estimates, shale and other unconventional gas finds have increased that life span to 200 years or more.
The successful exploration, appraisal, and development of UK onshore unconventional resources have the potential to provide a significant contribution to the hydrocarbon component of the nation’s balanced portfolio and strategy.
Despite the technical, environmental, financial, and political challenges, the UK and other European countries, are taking the first tentative steps to establish the development of shale and coalbed methane. Coring activity is now under way in reservoirs to ascertain the presence of gas, geological permeability, and the natural fracture system within the rock, and that presents an encouraging commercial opportunity.
The multiscale finite-volume (MSFV) method is designed to reduce the computational cost of elliptic and parabolic problems with highly heterogeneous anisotropic coefficients. The reduction is achieved by splitting the original global problem into a set of local problems (with approximate local boundary conditions) coupled by a coarse global problem. It has been shown recently that the numerical errors in MSFV results can be reduced systematically with an iterative procedure that provides a conservative velocity field after any iteration step. The iterative MSFV (i-MSFV) method can be obtained with an improved (smoothed) multiscale solution to enhance the localization conditions, with a Krylov subspace method [e.g., the generalized-minimal-residual (GMRES) algorithm] preconditioned by the MSFV system, or with a combination of both. In a multiphase-flow system, a balance between accuracy and computational efficiency should be achieved by finding a minimum number of i-MSFV iterations (on pressure), which is necessary to achieve the desired accuracy in the saturation solution. In this work, we extend the i-MSFV method to sequential implicit simulation of time-dependent problems. To control the error of the coupled saturation/pressure system, we analyze the transport error caused by an approximate velocity field. We then propose an error-control strategy on the basis of the residual of the pressure equation. At the beginning of simulation, the pressure solution is iterated until a specified accuracy is achieved. To minimize the number of iterations in a multiphase-flow problem, the solution at the previous timestep is used to improve the localization assumption at the current timestep. Additional iterations are used only when the residual becomes larger than a specified threshold value. Numerical results show that only a few iterations on average are necessary to improve the MSFV results significantly, even for very challenging problems. Therefore, the proposed adaptive strategy yields efficient and accurate simulation of multiphase flow in heterogeneous porous media.
The Schoonebeek heavy-oil field was first developed by Nederlandse Aardolie Maatschappij B.V. (NAM) in the late 1940s. Because of economics, it was abandoned in 1996. In 2008, the Schoonebeek Redevelopment Project, using a gravity-assistedsteamflood (GASF) design concept, was initiated with 73 wells (44 producers, 25 injectors, and 4 observation wells). Steam injection and cool-down cycles subject a cement sheath to some of the most severe load conditions in the industry. Wellbore thermal modeling predicted that surface and production sections would experience temperatures in excess of 285°C (545°F) and considerable stress across weak formations. A key design requirement was long-term integrity of the cement sheath over an expected 25- to 30-year field life span. Complicating this requirement was the need for lightweight cementing systems, because lost-circulation issues were expected in both hole sections, particularly in the mechanically weak Bentheim sandstone. The long-term integrity challenge was divided into chemical and mechanical elements. Prior research on high-temperature cement performance by the operator provided necessary guidance for this project. Laboratory mechanical and analytical tests were conducted to confirm the high-temperature stability of the chosen design. In addition to using lightweight components, foaming the slurry allowed the density, mechanical, and economic targets to be met. A standardized logistical plan was put in place to allow use of the same base blend for the entire well, adjusted as needed, using liquid additives, and applying the foaming process when necessary. This single-blend approach greatly simplified bulk-handling logistics, allowing use of dedicated bulk-handling equipment. The first well was constructed in January 2009; all 73 wells have been successfully cemented to surface. The steaming process, initiated in May 2011, has progressed with no well integrity issues to date.
At a September luncheon hosted by the SPE Gulf Coast Section’s Project, Facilities, and Construction study group, Wally Georgie of Maxoil Solutions addressed some of the critical factors associated with produced fluid characterization data that are frequently overlooked or misinterpreted. He explained the process from two aspects: the layout of the system and the guts of the various vessels. The terminology used to describe heavy oil is an important point. In his presentation, Georgie referred to oil with less than 23°API (Table 1). The production of heavy oil presents several processing challenges including the need for artificial lift, and difficult handling with respect to flow, separation, emulsions handling, storage, and transportation.