Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Summary 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-assisted-steamflood (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.
- North America > United States (1.00)
- Europe > Netherlands > North Sea > Dutch Sector (0.50)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.35)
- Europe > Netherlands > North Sea > Dutch Sector > Schoonebeek License > Bentheim Sandstone Formation (0.99)
- Europe > Netherlands > North Sea > Dutch Sector > Schoonebeek Field > Bentheim Sandstone Formation (0.99)
- Europe > Netherlands > Coevorden Field > Z3 Carbonate Formation (0.98)
- (6 more...)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
- (7 more...)
Abstract 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.
Increasing Oil Recovery with CO2 Miscible Injection: Thani Reservoir, Abu-Dhabi Giant Off-Shore Oil Field Case Study
Aljarwan, Abdulla (ADMA-OPCO) | Belhaj, Hadi (Petroleum Institute, Abu Dhabi, UAE) | Haroun, Mohamed (Petroleum Institute, Abu Dhabi, UAE) | Ghedan, Shawket G. (Computer Modeling Group, Ltd, Calgary, Canada)
Abstract This paper aims to study the miscibility features of CO2 miscible injection to enhanced oil recovery from Thani-III reservoir. 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 CO2 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. Results of this study have shown comparable results with the lab experimental data in regards to minimum miscibility pressure (MMP) calculation and recovery factor estimation, where the marginal errors between both data sets were no more than 7% at its worst. Results from this study are expected to assist the operator of this field to plan and implement a very attractive enhanced oil recovery program, giving that other factors are well accounted for such as asphaltene deposition, reservoir pressure maintenance, oil saturation, CO2 sequestering and choosing the most appropriate time to maximize the net positive value (NPV) and expected project gain.
- North America > United States > Texas (0.93)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.50)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (22 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- (4 more...)
Nereid UI: A Light-Tethered Remotely Operated Vehicle for Under-Ice Telepresence
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)
Abstract 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. Introduction Polar scientists presently lack access to effective capabilities inice-margin and under-ice environments for examining the submerged features ofice shelves, icebergs, and sea ice as well as the seafloor under iceshelves. Close-up high-resolution inspection and survey operations inthese complex under-ice environments require a tether to provide high-bandwidthtelemetry between the underwater vehicle and its human operators. Long-range light-fiber ROV tether technology, as pioneered on theNereus vehicle (Bowen et al., 2009) for 11,000 m depth operation, provides the high bandwidth (Gigabit Ethernet) link necessary for real-timecontrol under the direction of the shipboard science party, and yet retainsextreme horizontal mobility of the host vehicle. The goal of theNereid UI system is to extend this capability to the Polar Regions, providing scientific access to under-ice and ice-margin environments that ispresently impractical or infeasible and enabling operators to extract maximumbenefit from every minute spent on-site in these harsh and otherwiseinaccessible environments. Funds for the project have been awarded by theNational Science Foundation (NSF) and the Office of Polar Programs (OPP) undera Major Research Instrumentation (MRI) program. Additional cost-share has beenprivately provided by Woods Hole Oceanographic Institution (WHOI).
- Electrical Industrial Apparatus (1.00)
- Energy > Oil & Gas > Upstream (0.94)
- Information Technology > Communications (1.00)
- Information Technology > Artificial Intelligence > Robots (1.00)
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. Introduction 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. Salym Development 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.
- North America > United States (0.71)
- Europe (0.71)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug (0.56)
- Information Technology > Architecture > Real Time Systems (0.75)
- Information Technology > Communications > Collaboration (0.69)
Welcome to the second half of TLE's two-part special section on passive seismic and microseismic. This month, we focus again on monitoring hydraulic fracturing with microseismic with five articles, but also expand beyond “micro” seismicity, to include unintended “induced” seismicity that may occur during injection. Five articles in this special section focus on induced-seismicity topics. In this introduction, we will highlight various issues related to undesired induced seismicity which may be caused by hydraulic fracturing and deep, underground salt water disposal.
- North America > United States > Texas (0.49)
- North America > United States > Oklahoma (0.47)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Oklahoma > Anadarko Basin > Eola Field (0.99)
- North America > United States > Colorado > Raton Basin (0.99)
- (12 more...)
Abstract TOTAL Abu Al Bukhoosh (TABK) has irritated a well sequence with the Perro Negro 2 rig (PN2); a Jackup MODU. The rig contract started early January 2010 and may be extended till end of 2015, based on HSE and technical performances. Since day one, it has been decided to boost the HSE performance with robust Management Leadership, Engineering HSE and ergonomics, and working on the Employees behavior. This well known drilling industry approach has been augmented by TABK decision to surpass general standards. Two additional Safety Officers providing 24 hours HSE coverage were hired by the Rig Contractor. One Rig Site Safety Advisor was mobilized by TABK. Their constant presence provides a close working relationship with the front line workers and Team Leaders. Several audits and ‘’360 Deg’’ HSE initiatives were able to increase the HSE awareness of all. PN2 has no recordable incident since 900 days. Initially, the HSE initiative and audit plans were based on the experience of the Managers offshore and onshore and not really linked to a formal ranking of the risks. New sophisticated tools are being developed in the Oil & Gas Industry to rank risks: For example, TABK HSE and Asset Integrity Departments are working on Technological Risk Assessment and Threat Registers. Multi-yearly mitigation measures and action plans are proposed. The well recognized ‘’likelihood-consequences’’ matrix has been adopted also for rig operations. It allows for highlighting the risks per area and the main population involved, ranks the areas per overall risk, and thus develops an audit/frequency plan related to those risks. With such structured and formalized HSE strategy, risks are well captured, type and frequency of the audits are straight forward, and barriers are implemented for a residual risk ALARP. This paper will explain in greater detail how this was achieved, the challenges that were encountered during the implementation of the tool, and how the Team intends to continue to add value in such a new HSE culture orientation.
Abstract During the past six years, the technology for shale gas/oil developments in North America has seen many improvements and optimizations as the industry experiences a sharp rise in the contribution of hydrocarbons from these resources. More recently, Europe and Australia have joined the US in expanding recoverable hydrocarbons from these unconventional resources, and initial activities are on the rise in Latin America, China, Saudi Arabia and India. Despite such improvements and optimizations, a closer look at the performance reveals that not all wells are producing commercially. In addition, the hydraulic fracture stages are not all contributing within the producing wells. This scenario potentially suggests that it is important to target the field's sweet spots while dealing with shale resources (like most other hydrocarbon-bearing formations). Hence, resource development based on the current concepts of geometric placement of hydraulic fracture stages (e.g., using fixed well/fracture spacing) may not be appropriate to develop such heterogeneous unconventional resource basins. In the discussion we illustrate certain well-defined criteria that can identify the sweet spot locations within a field/basin for the optimal well placement. We further document the vital formation/zone characteristics that define the locations for hydraulic fracture stages and thus move away from the arbitrary geometric placement. The paper will discuss the well-placement optimization process and identify the required combination of proposed special petrophysical, geochemical, and geomechanical investigations (wireline, Logging While Drilling and cores). The hydraulic fracture stage placement analysis as presented, shoulders on the need to understand the existing natural fracture system. This understanding is achieved through geophysical log measurements and comprehensive analysis of the hydraulic fracture development pattern, as well as interaction of hydraulic fractures at each stage with the natural fractures. A naturally fractured reservoir can be drained more efficiently if a complex fracture network can be created by the hydraulic fracture stimulation. This begins by drilling the well in the direction of minimum principle horizontal stress in the area. The paper concludes by presenting examples demonstrating the practical application of some of the specific aspects of the methodology discussed and with a number of specific conclusions. In summary, the three key points to Proper Placement of Wells and Hydraulic Fracture Stages, in order to maximize the net value of an operator's asset are: Begin With a Complete Understanding of the Reservoir Use a Multidiscipline and Integrated Approach Across Each Phase of the Life Cycle Effectively Use Modern Technology
- North America > United States > Texas (1.00)
- Asia > Middle East (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.96)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.94)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (0.68)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (10 more...)
Application of Inflow Control Devices to Maximize Oil Recovery in a Vertical Multilayer Well, South China
Tran, Thanh Binh (ACT-OG) | XiaoPing, Zou (ACT-OG) | Xiang, Tian (ACT-OG) | Soendoro, Feddy Himawan (Schlumberger) | Bolanos, Nelson (Schlumberger) | Fould, Jeremie Cyril (Schlumberger) | Ibrahim, Muhammad Nasir (Schlumberger) | Guo, Zhang Xing (Schlumberger)
Abstract In an offshore oil field in the southern East China Sea, the formations are sandstone and consist of six horizons, with specific flow unit characteristics and different aquifer support strengths. The operator intended to optimize the production with a permanent simple completion, in commingled production. However, the differences in reservoir properties and aquifer support presented a challenge for maximizing the oil recovery and delaying the water cut without resorting to well intervention. Passive inflow control device (ICD) technology was used to balance the influx from the different formations and hence maximize oil recovery while delaying the incremental water production, and production data validated the benefits of the application by showing a water cut of 50%, in contrast to the expected value of 90% (without the ICD completion), with the same estimated amount of cumulative oil production. Such a benefit is accrued by restricting fluid withdrawal from high-conductivity zones or with strong water drive, while providing enhancements to contribution from lower conductivity zones or zones with weaker water drive. This method is not new in itself, but it has not been used before in a permanent completion system where well interventions had not been planned. Multiple production iterations using numerical reservoir modeling of several completion options were performed and showed a 31.3% oil recovery improvement over the base scenario (all zones commingled without flow control devices).
- Asia > China (0.71)
- Europe > Norway > Norwegian Sea (0.25)
- Asia > China > South China Sea > Zhujiangkou Basin (0.99)
- North America > United States > Louisiana > China Field (0.97)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Flow control equipment (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
Abstract Poor supply chain management can set the conditions for failures of catastrophic proportions, both economically and in terms of safety. It has been the root cause of several of the largest disasters in oil and gas history. Many professionals fail to recognize important gaps due to the complexity of the web of supply relationships and the number of critical interfaces that can be misaligned. Professionals from executive offices, HSE, procurement, logistics, operations, and risk management need to take four major steps to ensure a safe supply chain: 1) Establish governance & organization to ensure organizational accountability for governance and management of supply chain risk, by appointing a supply chain czar and engaging crossfunctional stakeholders; 2) Adopt an internationally accepted top-level supply chain risk management framework and articulate first-level principles, including a policy on single sourcing; 3) Universally adopt formal "reinforcing" metrics and measurement systems, including measurement of supply chain risk, Total Cost methodologies, and quantification of the cost of supplier non-compliance; and 4) Extend supply chain strategy and policies to suppliers by scanning for suppliers that excel in HSE, setting supplier expectations and targets, training suppliers, and establishing mechanisms to hold them accountable including periodic audits.
- North America > United States (1.00)
- Europe (1.00)
- Asia > Middle East > UAE (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.68)