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Abstract Objectives/Scope This architecture is a result of a study completed for the Kuwait Oil Company under the Enhanced Technical Services Agreement with Shell. Specifically this covered subsurface data management. Several visits to Kuwait were required and during interviews with key stakeholders gaps where identified and many issues highlighted. The recommended architecture was modified to incorporate these requirements and finally agreed and approved. Methods, Procedures, Process This architecture was centered on having a QCed data store with seamless integration to KOC current existing systems. This reduced cost by the elimination of the need to introduce a new database. Further, this structure built on the existing knowledge base in place was a key factor in the architecture approval. The existing fragmented systems were characterized by different data values and data in several locations. There was a clear need for an integrated QCed data store. The need for clear accountabilities and for different disciplines to work together more closely was very much evident. The concept is derived from our Shell architecture structure concept but utilizing KOC existing systems. The focus in this architecture is on the seamless integration and defining clear data flows and roles and accountabilities. Each data type is covered by flow charts to specify the flow of data and the assigned focal points responsibilities and how the data is managed throughout the process. The structure and process is intended to keep the master data store always current with the latest QCed data. Uploading and quality review of the initial data set is therefore a key first step. Results, Observations, Conclusions With clear accountabilities and responsibilities defined and a clear data workflow the data store will be always in good shape. Having the QCed assured data at your fingertips saves a lot of time and money. Novel/Additive Information Having the technical user in ownership of his data and resposible on it's evergreening will assure the rest of the technical community they are using the latest most QCed data.
Abstract Producing heavy oil from shallow wells using rod pump applications requires careful design considerations especially for down hole components to achieve maximum production rate and maximize the run life. This paper highlights a successful case study of one such heavy oil sucker rod pump well, in the North Kuwait field of Kuwait Oil Company (KOC), where the rods were specially designed to penetrate through the viscous oil and address the pump floating problem to achieve uninterrupted pump operation. Conventionally, as a rule of thumb for the shallow wells, the rod design initially constituted of twenty percent sinker bars and eighty percent sucker rods. This was to add weight on the pump for stability and proper balancing. In the case of this well, with the same design philosophy employed, it was observed that the pump floated over the viscous oil. The maximum pump fillage was observed to be less than fifty percent. Eventually operational changes were made by reducing the speed and operating at maximum stroke length. However this still did not bring any improvement. Hence, specific design modifications were made in the rod string and the pump size to be able to solve the pump floating problem, achieve maximum production rate, and operate at the maximum possible efficiency. Following the design change, it was observed that the pump was now able to penetrate through the viscous crude effectively. This increased the pump fillage to 75% consistently, enhancing the production rate. It was also observed to improve the unit balancing. This well design was considered as part of the pilot in heavy oil project in north Kuwait field. Since the floating pump phenomena is expected in KOC heavy wells, this design would be employed on similar sucker rod operated wells and neighboring wells suffering from the same well conditions. It is expected that by overcoming this operational issue there will be considerable cost savings and production enhancements.
Abstract Sea water contains sulfate and formation water contains barium and strontium, if the sea water injected in oil fields reservoirs then the result is the potential for significant barium and strontium sulfate scaling and deposit & possible of reservoir souring due to SRB, s activity. Scale deposition is a common problem in sea water injection systems, the type and severity of scaling varying between fields. Sulfate scale formation is one of the most critical problems encountered in oil and gas industries daily activity and operations, the only effective way to avoid sulfate scale is to prevent it from forming. To prevent barium /strontium sulfate from forming and minimizing the potential of scale formation and associated well work over and squeeze treatment costs, Sulfate most therefore be selectively removed from sea water before being subjected to injection. A pilot plant CPP-NF (Compressed Phase Precipitation & Nano Filtration) testing was thus conducted to primarily and sufficiently deplete sulfate from sea water before being injected. The main objectives of the pilot plant is to study and evaluate the feasibility and cost-effective of CPP-NF technology for de-sulfation of sea water and/or MSF brine in Subiya Sea Water Treatment Plant SWTP, the foundation of the selected technology rests on how KOC can : 1) - increase the value and quality of the injected sea water, and 2)- implement the technology in such a way that the improved sea water quality would not cost more than the current situation and serve KOC long term goals. The pilot testing was very successful and the removal of sulfate was consistently in the range of 98–99%, furthermore, the pilot testing also revealed that the issue of high TSS (Total Suspended Solids) within the facility can be resolved at no additional cost.
- Water & Waste Management > Water Management > Lifecycle > Treatment (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Health, Safety, Environment & Sustainability (1.00)
Unlocking Additional Reserves Using Horizontal Wells with Multi Stage Fractures in the Western Desert of Egypt
AbdElNasser, M. G. (Qarun Pet. Co., Ahmed H. El-Banbi, Cairo University) | Al-Maraghi, A.M.. M. (Qarun Pet. Co., Ahmed H. El-Banbi, Cairo University) | Abady, S. M. (Qarun Pet. Co., Ahmed H. El-Banbi, Cairo University)
Abstract This paper presents a case study for drilling a horizontal well with multi stage transverse fractures in the NEAMA field in Karma concession in the western desert of Egypt. The well production results are expected to lead the Western Desert operators to change the development strategy for several western desert fields to unlock the unrecovered reserves in the upper Baharia tight formation. NEAMA field has total of 9 wells: 5 wells on production with total production around 500 BOPD, and 4 shut-in wells due to low productivity. The field STOIIP is around 15 MMSTB. With the historical low initial production rates, it was decided to develop the stranded reserves by drilling a horizontal well to replace three vertical wells and test the feasibility of applying horizontal wells with multi-stage fracturing in such tight reservoir. A horizontal well with 7 fracturing stages was completed at the down-dip part of the field, LWD (Logging While Drilling) measurements were used to control well's direction and predict rock lithology. The LWD helped to control the well trajectory between the upper and lower boundaries of the reservoir's zone of interest. The well was completed with permanent downhole pressure gauge and ESP system in the vertical hole. The well was put on production with initial rate of 400 BOPD with 20% water cut which was four times the total field production. The well production was maintained at low water cut until water production increased significantly. Integrated analysis of all collected data revealed that water channeling behind casing was responsible for the excessive water production. It was planned to work over the well to restore its oil production. The paper discusses the integrated data analysis techniques that led to the choice of completion option of horizontal well with transverse fractures for new wells in NEAMA field. The results and additional analyses of both pressure and production data are expected to help other Western Desert operators to develop significant reserves of tight UBAH reservoir.
Abstract Polymer flooding is an attractive option in hydrocarbon maturation plans. Several successful polymer floods and pilots have been implemented. One of the risks in polymer flooding is loss of injectivity. The consequences of loss of injectivity can be large. In conditions where matrix injection is required, reduction of injection rate may result in a much slower propagating polymer front and consequently later arrival of the anticipated oil bank eroding on the economic value of the EOR process. In extreme cases it can even lead to loss of the injector. Under fracturing conditions the loss of injectivity may be less noticeable, but it can lead to out of zone fracturing or fractures that grow too much in size and cause shortcuts to the producers or affect future infill well drilling. Reduction of injectivity is a generic concern in conventional waterfloods and can play an even larger factor when adding polymer to the waterflood. The increased viscosity of the injected polymer solution is the most obvious reason for an anticipated decrease in injectivity, but also other mechanisms can have an impact. These mechanisms include excessive polymer adsorption and associated permeability reduction, filtration of impurities in the polymer solution, fluid incompatibilities or reduced water quality. In this paper we will discuss the various causes for loss of injectivity and propose a structured approach for the associated prevention and mitigation options. Prevention includes (1) selection of the most appropriate polymer type; (2) best practices for preparation of the polymer solution; (3) safeguarding the water quality; and (4) enabling options for mitigation in case excessive injectivity loss is observed. The remediation step includes (1) the identification of the root-cause of an apparent injectivity problem; (2) the design of an appropriate clean-up treatment; (3) monitoring of the operation; and (4) implement measures to avoid repetition of the problem. We will include an overview of the preventive and mitigation options for the different causes of injectivity decline in polymer floods.
- Europe (1.00)
- Asia > Middle East (0.69)
- North America > United States > Texas (0.68)
- 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...)
Abstract The Kuwait Oil Company is developing the North Kuwait Jurassic Gas fields in order to increase domestic gas supply. The reservoirs are difficult with deep, poor quality reservoirs under high pressure containing H2S and CO2 leading to significant challenges. KOC entered into an Enhanced Technical Service Agreement (ETSA) with Shell in order to benefit from IOC expertise and to optimize the development. Some 40 Shell staff work with KOC. A core element of the ETSA is to build and enhance KOC's staff competencies to develop the North Kuwait Jurassic Gas fields. This professional competencies development program is done through the application of various training and coaching activities. KOC has an established and well-structured competence assessment and training regime for all staff under their employment. Shell, with its wide experience in sour and High Pressure/High Temperature (HPHT) gas field development, is well placed to complement and build on this important competency development process. Shell has embarked on a journey to shorten it's time-to-autonomy by transitioning from traditional classroom training to providing structured development programs including on-the-job-training, blended learning and coaching. The paper will describe how training and coaching activities were selected for KOC's North Kuwait Jurassic Gas team, how they were implemented and monitored, and what the critical success factors were. Shell's training and coaching program to the North Kuwait Jurassic Gas team have started five years ago with a steady increase of activities year-on-year. The multiple years' implementation of the North Kuwait Jurassic Gas competency development program have allowed for learnings, review and fine-tuning of the program. The paper will address the most important elements for a successful training and coaching program in this unique partnership. This contains of four elements, the role of management and business; type of training and coaching event; staff's own involvement and training program management. The paper will show how an IOC supports an NOC to enhance staff competencies in a challenging technical area, how this training and coaching plan is being managed and executed and what are key elements to consider.
Challenges in Developing Part Field Models to Assess Waterflood Performance for the Upper Burgan Reservoir, Greater Burgan Field, Kuwait
Muhammad, Y.. (Schlumberger) | Diaz Teran Ortegon, L. R. (Schlumberger) | Ibrahim, M. N. (Schlumberger) | Datta, K.. (Kuwait Oil Company) | Burman, K.. (Kuwait Oil Company) | Ma, Y. Z. (Schlumberger) | Gomez, E.. (Schlumberger) | Bond, D. J. (Kuwait Oil Company) | Gurpinar, O. M. (Schlumberger)
Abstract The Burgan Sands constitute the major reservoir in the giant Greater Burgan field. The Upper Burgan Sands contain significant volumes of oil, several billions of barrels, and have generally poorer and more variable reservoir quality and poorer continuity than the bulk of the Burgan sequence. Secondary water flooding is currently under consideration. This paper describes the challenges in developing part field models that are appropriate for waterflood simulation studies and that are, as far as is practicable, conditioned to the available dynamic data. The general approach to choosing "type areas" to represent typical portions of the field will be described. The process of developing geo-cellular models and conditioning them to dynamic data will then be illustrated. The existing geological and simulation models are considered too coarse to provide a proper basis for modelling the Upper Burgan. The extent to which this resolution has allowed geological models to be conditioned to dynamic data has been limited. A rock typing exercise integrated available core, log, and production data. Speed zones and flow barriers were identified. Calculated flow capacities and productivity indices generally matched field data well. Pressure breaks in the RFT profiles correlated well with vertical flow barriers. In addition, Permeability anisotropy ratios (Kv/Kh) were developed from detailed RCA and probe permeameter data acquired in key wells. Subsequently, MicroModels at whole core scale were developed and simulated to generate representative Kv/Kh ratios by Facies. Based on sedimentology studies and rock typing work, and the existing structural model, detailed geo-cellular models were produced. Dynamic models were then developed and conditioned to selected dynamic data. The approach used to condition these models to pressure transient data, local water movement as indicated by a detailed water encroachment survey, and to the pressure breaks seen on RFTs is described. This process both confirmed the plausibility of the geo-model and reduced uncertainty in permeability anisotropy. The field was segmented into equi-uniform polygons, on which waterflood patterns were evaluated, number of wells and throughputs determined, and the volumes of water to be handled estimated. A series of numerical simulation models were developed, through variations on the reservoir quality, reservoir connectivity, oil type, and development options. Generated water-cut vs. recovery factor profiles were utilized in a hybrid approach combining analytic and numerical evaluations to determine production profiles and potential waterflood recovery factors over time for each of the polygons, and the whole field. The work demonstrates a methodology by which relatively quick but comprehensive and robust evaluation of the potential value of a waterflood development could be made. It allows for sensitivity assessments and a degree of optimization.
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Ratawi Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Mauddud Formation (0.99)
- (3 more...)
Abstract Cold heavy oil production (CHOP) exploits the mechanism of enhanced solution gas (or foamy-oil) drive to achieve an economic oil rate and ultimate recovery. Understanding the foamy-oil dynamics and being able to simulate the process enable us to evaluate the cold production potential more realistically. This has led to the improved cold heavy oil recovery in Shell Canada's Cliffdale development in Peace River area. A recently developed foamy-oil dynamic model has been employed to evaluate the effects of well spacing and patterns on oil recovery. The results revealed that under the foamy-oil drive, the oil recovery improves as the well spacing decreases, because of decreasing well spacing leads to faster reservoir pressure depletion and stronger foamy-oil drive. In contrast, with a conventional black-oil model, the estimated ultimate oil recovery stays constant irrespective of the well spacing, and the only benefits of down spacing would be the production acceleration. The benefits of capturing foamy oil dynamics for the evaluation of CHOP development has been demonstrated with an example of a high level economic screening approach for the search of optimal well spacing and the number of laterals. The evolution of typical well spacing and the number of well laterals with time in the Peace River CHOP development has resulted from both the ever-increasing field operation experience and the improved understanding of foamy-oil drive dynamics.
Abstract Stage tools have been commonly used in North America for monobore completions to optimize economics. By cementing back the vertical and build sections of the wellbore, the requirement of the intermediate casing and liner hanger packer can be eliminated. An operator working in the K-1 carbonate formations of a massive field in eastern Saudi Arabia was examining a unique application of a stage tool to effectively cement and isolate a water-producing build section of a sidetracked lateral wellbore. The well incorporated a liner hanger packer with a multistage completion system. This paper will describe the distinct operational challenges encountered and how they were solved by redesigning an existing stage tool. The well profile and construction specified that the liner had to be hung above the sidetrack point. Therefore, it was critical that the sequential operation of running the lower completion string, setting the liner hanger, releasing the liner hanger running tool, setting the open hole packers, cementing the upper liner section and then setting the top packer be completed with tremendous accuracy for a successful job. The operator selected a stage tool with a secondary contingency closure mechanism that did not limit the inside diameter through the system. This mechanism would ensure that all stages could still be stimulated if the secondary closure option was required. The use of the stage tool with a liner hanger system required some design modifications; the typical single foam plug, used to displace cement and close the tool in the standard version of the stage tool, was not an option. Instead, the operator required that a separate drill pipe dart and wiper plug assembly be used to displace cement through the drill pipe and the liner. The stage tool was, therefore, redesigned to close with a wiper plug launched from below the liner hanger packer. After open hole conditioning, reaming and logging, the lower completion was run to setting depth and all equipment functioned without any issues. The problematic water producing zone was cemented and isolated and the stage tool was closed without the need to use the secondary closure mechanism. The stage tool was then milled out, leaving the well ready for stimulation. The redesigned tool enabled the operator to effectively cement the upper wellbore with no inside diameter restriction for stimulation. This paper highlights the first introduction of cementing stage tool technology in conjunction with a multistage completion system to an operator in Saudi Arabia and the tool redesign required for accommodating a liner hanger packer in the wellbore. This method could also be applied to any type of lower completion such as sand management screens, inflow control devices or in conjunction with slotted or solid liners as an off-bottom cementing application.
Abstract Wara reservoir of Greater Burgan field is a heterogeneous shaly sand reservoir deposited in fluvio-deltaic environment. Modeling the changes in hydrocarbon saturation and water encroachment in Wara reservoir has been a great challenge due to a combination of factors like heterogeneity, multiple Oil Water Contacts and multiple Oil Gas Contacts etc. Understanding the water encroachment and monitoring zones of water breakthrough is a key for effective water flooding reservoir management. Pulsed neutron capture (PNC) logs are commonly used for formation evaluation behind casing and to assess time-lapse variations of hydrocarbon saturations. Systematic time-lapse PNC logging can give a detailed description of hydrocarbon saturation changes in response to injection and production operations during water flooding. This paper addresses the workflow that has been utilized to create a 3D static model of Water encroachment using flags that characterize the swept and partially swept zones in the reservoir created from Sigma curves of Time lapse PNC logs along with synthetic sigma curves from the open whole logs acquired at the time of drilling the well. The remaining oil in place volume which was estimated from the sweep model was consistent with the volumetric of the simulation model and with the remaining oil in place calculated from the production data. Volumes of different vintages are created with time lapse PNC logs. The difference between these volumes can be used to understand the complex water encroachment in the reservoir due to multiple oil water contacts and also it can be used as a source to calibrate the 4D seismic data acquisition model. Connected volumes of the swept and partially swept zones computed from the model were utilized to visualize the swept zones.
- Geology > Geological Subdiscipline (0.70)
- Geology > Sedimentary Geology > Depositional Environment > Transitional Environment > Deltaic Environment (0.55)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.36)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (0.54)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Raudhatain Field > Upper Burgan Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Raudhatain Field > Mauddud Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Raudhatain Field > Lower Burgan Formation (0.99)
- (17 more...)