The Greater Burgan field is the world’s largest sandstone oil field. It has been producing since 1946 under primary depletion from natural water drive. Sub-surface modeling is an integral part of reservoir management and Kuwait Oil Company (KOC) has been investing significant amount of resources in this technology to support field development planning and depletion strategy. In 2001, the first comprehensive Greater Burgan full-field geological model was built with 65 million cells encompassing all the major reservoirs. Subsequently, a reservoir simulation study with a 1.6 million cells dynamic model was conducted in 2003 utilizing parallel simulation technology. In the last decade, active field development plans have resulted in major surface facility upgrades and more than 300 new wells drilled. The existing sub-surface models no longer sufficed to meet technical requirements and as a result, an unprecedented Greater Burgan sub-surface modeling project was commenced in 2009. This is a 4-year project consisting of structural, static and dynamic modeling. It started with Sequence Stratigraphy Study followed by Geo-modeling. The latter was completed in August 2011 and subsequently paved way to Dynamic Modeling phase of the study. This paper discusses up-scaling of the high resolution geological model and the specific problems that the study team had to overcome in the process. State-of-the-art technologies were applied to the construction of the biggest-ever geological model (900 million cells) of the Greater Burgan field. The high resolution of the static model was necessitated by not only the sheer size of the field, but also, by the complex depositional environment defining the internal architecture of the reservoir and the resultant heterogeneity in the system. Sedimentological and stratigraphic data were used extensively to describe the internal architecture of the reservoir, capturing the level of heterogeneity observed in the field. A primary use of this high resolution model was to create a basis for the flow simulation model used in reservoir management. Although computing technology has advanced significantly, conducting flow simulations on such a fine scale model demands prohibitive amount of computation and becomes impractical when a time constraint is imposed on the project. Therefore, model up-scaling is essential to conduct simulations in a reasonable run time. Preservation of volumetric quantities and flow features were the two key considerations for the successful up-scaling. While volumetric conservation can be achieved by following a strict procedure, preserving flow features across the various reservoirs imposes a great challenge. This paper addresses actual challenges encountered during the up-scaling process. The discussion focuses on the following topics: Choice of the model size considering both computational time and accuracy of simulation results. Need for multi-scale approach with three simulation models: Fine, Coarse, and Very Coarse - each to be used to answer specific questions of the study;Right balance between areal and vertical grid coarsening that ensures adequate model physics and preservation of geological features;Mechanistic modeling to support decisions made in the process of up-scaling;Preservation of flow features in various reservoirs, difference between massive and more heterogeneous reservoirs;Transferring water saturation between fine and coarse models: testing various approaches to find one that produces the best volumetric match.
Interference testing although primitive in terms of its introduction and idea to the petroleum industry, still stands to this day as one of the most cost effective and efficient ways of establishing communication between wells and determining the reservoir transmissibility in the region. This paper discusses the methodology and results obtained from a four month pressure data acquisition campaign for a transient interference test performed in a carbonate reservoir known as Marrat, in the Giant Burgan field of Kuwait. The Marrat long term interference test was conducted around a water injector pilot with distances as far as 0.9 km at the subsurface locations between the injector and producer wells. Therefore, the interference test was used to evaluate the transmissibility between the injector and the nearby observation wells. The producer wells were shut-in for the entire length of the test so as not to create any disturbances that could hinder the interpretation processes. After conducting this test, a better understanding of the subsurface uncertainty as well as communication between the wells was highlighted. Other objectives were added to the tests which were to determine the water bank distance from the injector, as well as to describe the least resistive path that the water prefers to travel in. The tests showed that not all the wells responded to the pressure pulse, and therefore the assumption that a fault was isolating one of the wells. One of the main conclusions was a strong directional transmissibility that was at first associated with a high permeability corridor corresponding to the depositional environment. The other conclusion was the orientation of the fracture plane which could cause this high directional transmissibility. A comparison and integration of the acquired pressure data with a separate geologic stochastic model was constructed and discussed in this paper. Based on the integration work of the interference test and the geologic study it was therefore concluded that a secondary recovery using water flooding would be beneficial and necessary for sustaining Marrat reservoir production in the long term based on the location of both producer and injector wells.
The Greater Burgan field in Kuwait is the largest clastic oil field in the world. Its sheer size, complex geology, intricate surface facility network, 5,000 well-completions and 68-years of production history represent formidable challenges in reservoir simulation. In the last two decades, many flow simulation models, part-field and full-field, were developed as reservoir management tools to study depletion plan strategies and reservoir recovery. The new 2013 Burgan flow simulation was a major undertaking in terms of effort and financial cost. The model size, innovative technology, supporting resources, integrated workflow and meticulous planning applied to this project were unprecedented.As the Burgan field has matured over time, the reservoir pressure has declined in certain areas, with associated reduced productivity. The reduction of wells' productivity, combined with the increasing water production, has necessitated improved oil recovery (IOR) initiatives in order to support the Kuwait Oil Company (KOC) 2030 strategy, sustaining oil production and ensuring high recovery from Burgan reservoirs. This paper describes the development of a dynamic model to design pressure maintenance projects for optimal reservoir management and IOR strategies. The prediction model was built on a history matched model on three levels, Global (Field), Regional (Reservoirs / Gathering Centers) and Wells. These three levels depict the concerted history matching effort in accordance with the recurrent data quality. Details of geologic and dynamic modeling have been documented and presented in previous Burgan SPE papers and are not repeated in this paper.The primary objectives of the Burgan prediction model are meeting the production target profiles with optimal field development plans (FDP) and to maximize oil recovery. Two of the most promising projects are currently in different phases of development, Wara Pressure Maintenance Project (WPMP) and Burgan Sand Upper (BGSU-PMP). In this paper, only the WPMP is discussed in detail as the waterflood project is now entering operation stage after 10 years of planning and construction. BGSU-PMP is part of the Burgan FDP but is not focused within the scope of this paper.Sub-surface modeling in the giant Greater Burgan field complex is not just enormous, it is also arduous and challenging. The accomplishment by the team was momentous despite a less-than-expected result. Nonetheless, lessons learnt offered valuable information for future improvement. It has been a long and difficult journey from geological model to dynamic model over the last five years. Yet, in pursuing IOR and EOR, the journey has just begun.
The Greater Burgan field in Kuwait is the largest clastic oil field in the world. Its sheer size, complex geology, intricate surface facility network, over 2,200 well completions and 65-years of production history associated with uncertainty present formidable challenges in reservoir simulation. In the last two decades, many flow simulation models, part-field and fullfield, were developed as reservoir management tools to study depletion plan strategies and reservoir recovery options. The new 2011 Burgan reservoir simulation effort was not just another simulation project. Indeed, it was a major undertaking in terms of technical and human resource. The model size, innovative technology, supporting resources, integrated workflows and meticulous planning applied to this project were unprecedented in the history of the Greater Burgan field development. This paper describes work done to prepare a representative numerical model which could be utilized to optimize the remaining life of the reservoir complex. Right from the onset, representative numerical modeling concerns were identified. These led to a systematic collaboration framework being built in place between the static and dynamic modeling teams. Calibration of the model to the historical observations was executed at three levels, Global, Regional and Wells -the Cascade Approach. The cascade approach was designed to enable a concerted model calibration effort in accordance with the recurrent data quality. For instance, while the total field production history attains a high degree of accuracy, the data at the regional Gathering Center (GC) is of a lower level of certainty, but far more reliable than the data at an individual well. Commercial modeling software have been utilized extensively to produce several utilities such as water encroachment maps, Repeat Formation Tester (RFT) matching tools and aquifer definition and adjustment workflows. Subsequently, synergy in the integrated use of these tools produced a robust model calibration process on all three levels in the cascade approach.The main goal of the project -development of a predictive simulation model, always remained at the fore of the project team's mind during the model calibration. Check-point prediction models were defined and constructed at regular intervals during the model calibration phase. This approach allowed qualitative assessment on the evolution towards a representative numerical model. Furthermore, it allowed synchronizing simulation workflows and expedited project deliverables. The overall result was a sound full-field reservoir simulation model that achieved a good match of production, pressure and saturation histories, leading to reliable forecasting of oil recovery under different development scenarios.
Geo-steering is a very critical part of today's field development economics, our production targets are getting more complex, thinner oil columns, which need more complex geo-steering, continual improvement needed in People, technology and processes. Drilling a well at an angle other than vertical can obtain more information by hitting the production targets and stimulate reservoirs in ways that cannot be achieved with a simple vertical well which became a valuable ability in oil business. To augment this aspect Kuwait Oil Company has established Geo-steering Center (Fig-1) which has become the hub for decision making while the well is getting drilled for landing at top of reservoir or lateral is being drilled (Fig-2). The establishment of Geo-steering control Room in FD (S&EK) is an outcome because of constant supervision and direct guidance by manager of Field Development South and East Kuwait, which added a new dimension to drilling the modern horizontal wells in the Greater Burgan Field. The team of Geologists of FD (S&EK) in this collaboration center ensures that horizontal wells are steered correctly and safely to their final targets. The Geo-steering center can be operated 24 hours a day if require. Each geologist may be responsible for as many as 3 wells in different fields (BG, MG & AH) and different reservoirs. Like driving, geo-steering requires constant attention and dedication all the time. The center recently moved into a new and expanded facility that is equipped with the latest in visualization, communication and computer technology in order to properly place and geologically navigate us with many complex horizontal wells path in Greater Burgan field. Geo-steering horizontal wells can be done remotely from the center, with data coming into the center from more than one well at any given time. For every well, Logging-While-Drilling (LWD) sensors near the drill bit send information about the Lithology and directional survey of the well to the control unit at the rig from where data is then transmitted by satellite to the geo-steering center. The team developed software instantly can load the data so geologists can see on their workstations the LWD and trajectory data to determine where the drill bit is in relation to the drilling plan and the reservoir target.
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