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Well Completion
Successful Case Histories of Smart Multilateral Well with Inflow Control Device and Inflow Control Valve for Life-cycle Proactive Reservoir Management in High Mobility Reservoir, Minagish Field West Kuwait
Al-Enezi, Khalaf (Kuwait Oil Company) | Das, Om Prakash (Kuwait Oil Company) | Aslam, Muhammad (Kuwait Oil Company) | Ziyab, Khaled (Kuwait Oil Company) | El-Gezeeri, Taher (Kuwait Oil Company)
Abstract Advanced smart multilateral wells with extended reservoir contact from a single well location have accelerated sustained oil production and increases hydrocarbon recovery from ultra-high water mobility oil-wet Burgan reservoir in Minagish Field West Kuwait. Further the smart multilateral wells have proven to be a great tool for adequate proactive reservoir management and production management without well interventions. The Burgan reservoir has active aquifer, very high permeability sands associated with active faults and contain highly viscous reservoir fluid with downhole viscosity of more than 40cp, enhance water mobility and resulted in premature water breakthrough with increasing water cut trend within few months of production in existing horizontal wells. This has resulted into non-uniform reservoir depletion, by-passed oil regions and low oil recovery. The smart level-4 multilateral wells were successfully designed and implemented in Burgan reservoir by combining the reliable Level-4 junction along with stacked dual lateral completion having customized viscosity independent Inflow Control Device (ICD), customized two Inflow-Control Valves as well as down hole gauges, wide operating range Electrical Submersible Pump (ESP), suitable wellheads, X-MAS tree and Integrated surface panel for real time data monitoring first time in Kuwait. The improved production performance of smart multilateral wells in Burgan reservoir of Minagish Field, West Kuwait have achieved appropriate production management through flow regulations across laterals and adequate reservoir management with the combination of inflow control device as well as inflow control valves along with downhole pressure temperature gauges. Moreover the smart multilateral wells have enhanced sustained oil production, maximizes hydrocarbon recovery at lowered capital and operational expenditure resulted in improved economic performance of reservoir with significant increase in net present value (NPV). The paper covers the successful implementation of smart multilateral wells and its effectiveness in achieving the life-cycle production management as well as proactive reservoir management supported with actual well performance results. Further the paper details about the economic benefits of smart multilateral wells and its contribution in improving the economic performance of Burgan reservoir of Minagish Field, West Kuwait.
- North America > United States > Virginia > Virginia County (1.00)
- North America > United States > Texas > Yoakum County (1.00)
- North America > United States > Texas > Wichita County (1.00)
- Asia > Middle East > Kuwait > Jahra Governorate (1.00)
- Geology > Structural Geology (0.48)
- Geology > Geological Subdiscipline (0.47)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.46)
- Asia > Middle East > Kuwait > Jahra Governorate > Rawdatain Basin > Upper Burgan Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Minagish Field > Marrat Formation > Upper Marrat Formation > Sargelu Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Minagish Field > Marrat Formation > Upper Marrat Formation > Najmah Formation (0.99)
- (20 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion (1.00)
- Reservoir Description and Dynamics (1.00)
ABSTRACT Numerical analysis based on the non-linear dynamics method (AUTODYN) is performed to simulate the cracking processes in rocks containing a single pre-existing flaw. The dynamic analysis considers the interaction of the material with the stress wave, which propagates from the pressure boundary towards the model interior. The numerical results presented are based on the Drucker-Prager strength model along with the cumulative damage failure criterion. The resultant crack types, crack initiation sequences and overall crack pattern are found to vary with loading conditions. Under a relatively low loading rate or a small magnitude of maximum loading pressure, tensile cracks tend to initiate prior to shear cracks. In contrast, under a relatively high loading rate and a large magnitude of maximum loading pressure, shear cracks tend to initiate prior to tensile cracks instead. Besides the loading rate, the maximum magnitude of the loading pressure is also found to influence the crack pattern. When the magnitude of maximum loading pressure is small enough, even if the loading rate is very high, the tensile cracks will initiate first and even no shear crack will initiate. To conclude, the crack pattern caused by quasi-static load can be expected to be very different from the that caused by high speed impact load.
- Well Completion > Hydraulic Fracturing (0.69)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (0.49)
ABSTRACT: The method of stress state estimation is proposed. This method is based on subsequent measurement of circular contour deformations. The mathematical model is created and numerical modeling of circular contour deformations estimation is carried out. The calculations were made for the case with 2 fractures going from the borehole outline with loading by the cover (sleeve). 1. INTRODUCTION At the moment the problem of permeable rock stress state estimation remains up-to-date. The essential purpose of these technologies is creating of short but wide cracks which distribute over the wall packing, appeared around the borehole. In addition the knowledge of stresses which correspond to each inter-layer plays a key role. It''s important for prevention of fracture distribution with the height growth (the fracture blowout) into the gas-cap and into water-saturated beds. For coalmines conditions, where the information about rock stress state over the distance form diggings is necessary, this task is important as the bench coal is often characterized by fracturing and heterogeneous permeability. It''s evident that the basis of methods for stress measurements at such depths (more than 1000m) and with requested localized connection should be the method of measuring hydraulic fracture. Unfortunately the classic hydraulic fracture method doesn''t allow to measure effectively the stress in permeable rocks or rocks with pre-existence fracture because of significant fluid leak off into the rock mass. This leads to the impossibility of instantaneous shut-in pressure determination and significant mistakes in reopening pressure determination. There are multiple modifications of hydraulic fracturing method, so called sleeve fracture, the main idea of which is the use of sleeve for prevention of fluid penetration into the rock mass. These modifications are oriented to creating technologies which allow to measure stresses in permeable rocks and they described in [1,2].
- Asia (0.29)
- North America > United States > California > San Francisco County > San Francisco (0.15)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
Abstract The accuracy and precision of well rates are paramount in reservoir management, well performance surveillance, flow assurance, and any third party processing arrangements. Rate allocation is traditionally based on well rate tests and downtime. This method is usually time-consuming and thus performed relatively infrequently. This could be inadequate for proactive asset management especially with wells that may produce in transient state. This paper discusses methodology to improve well rate allocation quality and save engineering time. In practice, many fields face some or all of the following challenges that are related to well rate allocation: 1) reservoir communication, 2) well interference, 3) changing skin factors or other near wellbore boundaries, 4) uncertainties around reservoir fluid properties, and 5) difficulty in obtaining well rate tests for a variety of reasons. For many intelligent wells, it is a common practice to install permanent downhole gauges which are playing critical roles in field management. This paper describes a framework on how to capitalize on the real time data from well pressure and temperature sensors and use the data in Integrated Asset Modeling (IAM) to allocate the well rate with enhanced accuracy, increased frequency, and reduced processing time. The paper uses Atlantis in Gulf of Mexico as an example to demonstrate this process. The real-time data supported model based allocation process becomes virtual flow meters for the intelligent wells. For Atlantis, field-wide allocation accuracy has been improved from previously +/โ 10% error using the traditional allocation method based on well rate test and downtime method to current +/โ3% error using the new method. This paper also shows model maintenance is a journey that needs strenuous attention especially after water injections commences and more production wells come online.
- North America > United States > Texas (0.93)
- North America > United States > Gulf of Mexico > Central GOM (0.48)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 744 > Atlantis Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 743 > Atlantis Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 742 > Atlantis Field (0.99)
- (2 more...)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Downhole sensors & control equipment (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (1.00)
- (7 more...)
- Information Technology > Sensing and Signal Processing (1.00)
- Information Technology > Architecture > Real Time Systems (1.00)
- Information Technology > Data Science (0.94)
- Information Technology > Communications > Networks > Sensor Networks (0.34)
Technology Update The trend of increasing wellbore complexity for extended reservoir contact and greater reservoir heterogeneity demands improved monitoring and control solutions. Traditionally, the only option has been the deployment of a cabled system, but this limits the application of intelligent well technology to new installations or workovers. In any case, cabled systems are not always possible in new installations, especially where the completion is discontinuous, and slimhole or monobore completions may not allow cables to be deployed along the tubing string. Wireless technology is proving to be a more flexible alternative to addressing the issues of permanent downhole monitoring. Tendekaโs wireless gauge, an interventionless completion technology that has been successfully deployed in the North Sea, allows real-time flowing bottomhole pressure (FBHP) to be efficiently transmitted to the surface, an attractive option for wells, in which the cabled gauge system has failed or was not initially installed. Originally designed to 3.5ย in., the company has recently produced a 2.25 in. version. Benefits of Wireless Technology The system transmits data from the lower completion to the surface via pressure pulses. The tool design allows the wellโs production to be partially choked for a short time to create a pressure pulse, which is detectable on the surface pressure gauge. The wellโs energy is used to transmit data to surface, thereby reducing power consumption, and the system requires no additional surface installation or pickup because an existing tubing head pressure gauge can be used to detect the pulse train. For most operators, the system can be deployed by a single intervention, allowing highly accurate data to be sourced almost instantaneously for a fraction of the cost of a recompletion. Compared with a memory gauge system, it allows data to be collected in real time and provides a continuous confirmation of operation. The gauge can be set in blank pipe, giving optimal freedom for installation depth, and it can be installed as close to the producing interval as required. A benefit of using pressure pulse transmission is the ease of installation. No retrofitting of topside equipment is required, and many of the technical and contractual issues are avoided when introducing a new monitoring system. Successful Deployment A major operator in the North Sea retrofitted the 3.5 in. wireless pressure and temperature gauge at 2200 m in a low-pressure (32 bar) gas well offshore Norway. The existing wellhead pressure sensor was used to capture the wireless signal and extract the data, therefore, no extra infrastructure was required. The application was especially challenging because the well was a marginal producer and the wellhead pressure had large background pressure variations, because of limited well deliverability. Despite these conditions, pressure pulse transmission proved effective. Even if the well starts to significantly deplete while the wireless downhole gauge is installed, the gauge itself will modify its pressure pulsing method to ensure that a detectable pulse train is transmitted to surface.
- Europe > United Kingdom > North Sea (0.46)
- Europe > Norway > North Sea (0.46)
- Europe > North Sea (0.46)
- (2 more...)
- Well Completion > Completion Selection and Design > Completion equipment (1.00)
- Well Completion > Completion Monitoring Systems/Intelligent Wells (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Abstract Traditional slickline work usually encompasses basic mechanical manipulation for downhole intervention work. In the recent past, a variety of battery-powered downhole tools have emerged in the market, providing additional deepwater solutions for the industry. These tools include the extended-reach downhole power unit and the smart release tool. The downhole electrical power unit is an electro-mechanical setting tool that uses a timer activation switch to begin the setting process for a variety of downhole tools. The smart release tool provides a timer-based mechanism to release the deployment wire from the downhole toolstring, eliminating the exposures associated with dropping a cutter in the event of a stuck tool. These tools can be conveyed on slickline for a variety of intervention solutions, including setting tubing plugs and packers, pulling subsea tree plugs, setting pressure gauges in tubing profiles, and providing a mechanical release in highly-deviated, extended-reach wellbores. This paper discusses specific well-intervention case histories using the downhole electrical power unit and the smart release tool. In the first case history, the downhole electrical power unit was used to set a packer assembly during a safety- valve repair. The smart release tool was used to soft set memory pressure gauges in wells without functioning, permanent downhole gauges, eliminating the need for jar action that could damage the gauges. Adaptations were made to the existing tool designs to respond to the well-specific challenges. These case histories demonstrate applications in which the electro-mechanical timer-activated tools have provided solutions for deepwater Gulf of Mexico well-intervention projects. The discussion includes lessons learned from previous project designs, development of operational best practices, and possible future applications to extend the role of slickline in deepwater operations. Applications may include the use of the downhole power unit to set packers and bridge plugs in conjunction with memory logging tools to correlate depth, as well as continued use of the smart release tool to minimize risks associated with downhole mechanical evaluation and memory data acquisition.
- Well Completion > Completion Installation and Operations (1.00)
- Production and Well Operations > Well Intervention (1.00)
- Management > Professionalism, Training, and Education > Communities of practice (1.00)
- (3 more...)
Real-Time Downhole Monitoring of Electrical Submersible Pumps Rated to 250ยฐC Using Fiber Optic Sensors: Case Study and Data Value in the Leismer SAGD Project
Medina, Max (Statoil) | Torres, Carlos (Statoil) | Sanchez, Julio (Statoil) | Boida, Lindsey (Statoil) | Leon, Alfredo (Baker Hughes) | Jones, Jason (Baker Hughes) | Yicon, Carlos (Baker Hughes)
Abstract Leismer is the first Statoil operated steam-assisted gravity drainage (SAGD) project in the Athabasca region of Alberta, Canada. Electrical submersible pumping systems (ESPs) are the standard artificial lift method for this project. A field trial was planned for newly developed ESPs rated to 250ยฐC. The increased temperature rating allows operating SAGD chambers at higher pressures, thus providing more operational flexibility for increasing recovery and dealing with common exploitation problems. The field trial required reliable and comprehensive down-hole monitoring, so that thorough ESP performance analysis could be performed under real field conditions. Given the extreme conditions at which ESP systems operate in SAGD, fiber optic pressure and temperature sensors were selected for real-time down-hole monitoring. These sensors were placed at the pump intake, inside the motor and at the discharge. The fiber optic gaugesโ performance is comparable to standard SAGD measurement devices, but without some of the disadvantages. The sensing system configuration, ESP interface and installation will be described. This paper will also present the value of real-time ESP monitoring. The pump operation is controlled by continuously history matching performance with well performance software and adjusting parameters to changing down-hole conditions. This ensures the ESPs are run near the best efficiency point. Pump intake sub-cool is controlled to minimize steam flashing occurrence. ESP motor temperature is monitored to boost reliability and run time. Finally, discharge pressure measurement has been used for history matching multiphase flow correlations. This improves ESP performance calculation accuracy in the fieldโs other wells. Integrating ESP advances with fiber optic measurement has allowed effective local technology qualification under real operating conditions. This project has provided abundant information and knowledge for field-wide production optimization.
- North America > United States (1.00)
- Asia (1.00)
- North America > Canada > Alberta (0.66)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Downhole sensors & control equipment (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (1.00)
Abstract This paper presents a unique process for deriving reservoir properties (i.e., minimum horizontal stress, kh/u and reservoir pressure) in isolated reservoir layers intersected by the same wellbore. It is based on simultaneously performing multiple diagnostic fracture-injection tests (DFIT) with extended multi-day shut-in periods using downhole shut-in tools and bottomhole memory gauges. A case study of 58 wells completed in the Mesaverde and Dakota sandstones of the San Juan Basin is used to describe and assess the above application. These intervals are gas productive, slightly to significantly sub-pressured, and possess a very low permeability pore network enhanced by natural fracture networks. As many as seven individual intervals per well were tested using the simultaneous process in an area spanning the entire San Juan Basin. Large scale, multi-stage hydraulic fracturing is necessary to establish commercial production from these intervals. The diagnostic tests were done prior to the large-scale fracture treatments, yet did not impede the subsequent implementation of the treatments. In the Dakota interval, the diagnostic testing results agreed well with the kh derived from post-frac production analysis and led to a process of treatment design optimization. In the Mesaverde interval, less agreement was found between diagnostic test and production analysis results. Despite the lack of validation, fluid leak-off rates measured during the diagnostic testing provided insight into fracture half-length differences documented in a previous study of microseismic mapping. As part of the case study, procedural guidelines and best practices developed in the process of doing over 200 tests will be discussed. Multiple Diagnostic Fracture Injection Tests Done Simultaneously in a Single Wellbore The method to perform multiple diagnostic fracture injection tests (DFIT) simultaneously in a single wellbore came from the need to characterize mature formations which were differentially pressure depleted. The majority of oil and gas reservoirs the San Juan Basin of northwestern New Mexico and southwestern Colorado were discovered in a sub-pressured state, i.e., initial reservoir pore pressure was less than the hydrostatic head of fresh water. Due to variances in sub-interval permeability and drainage area extent, seventy plus years of sustained production and multiple infill campaigns have rendered the major producing intervals substantially differentially depleted on a layer by layer basis. Using the Equation 1, Figure 1 is provided to illustrate the magnitude of intra-formation layer reservoir pressure differences that have been measured in a single wellbore for four of the producing formation in the San Juan Basin.
- North America > United States > New Mexico (1.00)
- North America > United States > Colorado (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.34)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (0.86)
- Geophysics > Borehole Geophysics (0.68)
- North America > United States > Arizona > San Juan Basin (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 210/24a > Lewis Field > Brent Group Formation (0.98)
- North America > United States > New Mexico > San Juan Basin > Dakota Sandstone Formation (0.94)
- (2 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract This paper presents the results of an investigation into fracture growth pattern in three horizontal wells, each fractured multiple times. The completion system was selected such that it allowed recording of the bottom-hole pressure in two critical locations; at the frac port which was being fractured, and, within the previously fractured part of the same wellbore. Downhole cups isolated the two locations from each other. The data show remarkable results. All fractures initiated axially and re-oriented to become perpendicular to the minimum principal stress (MPS). The re-orientation details varied widely between different fractures in the same well, and also between wells. In-spite of these variations, there was no communication within the formation between the multiple fractures. All fractures in the same well had the same value of MPS, and in fact nearly the same in all three wells. In one of the wells there was obstruction to proppant movement inside the fracture which caused increasing pressures during fracture extension. In one instance this resulted in screen-out very near the wellbore early in the treatment, and in another case inside the fracture and close to the end of the stage. Still, the high pressures encountered during these fractures did not cause communication with the previous fractures. The growth pattern in all fractures can best be described as off-balance, with no evidence of "complexity".
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Esther Field (0.99)
- Well Drilling > Drilling Operations > Directional drilling (0.71)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (0.53)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (0.48)