The huge original oil in place (OOIP) of heavy oil within the upper Maastrichtian carbonate succession of Tayarat Formation in Kuwait Burgan field lead to paying more attention to its economic value and the necessity of characterizing it at multi-scales for better commercial utilization. However, its high degree of heterogeneity and complexity as a consequence of depositional and diagenetic factors, the presence of fractures in high frequencies, and existence of heavy oil (10 −15° API) with very high viscosity (80,000 cP) and non-movable bitumen in high quantities make the evaluation process very challenging and difficult. This study is aiming at characterizing these carbonate succession using a robust combination between digital and conventional methods. One hundred seventy-seven (177) feet of representative whole core intervals were imaged by Dual Energy (DE) X-ray CT imaging technique to assess heterogeneity and identify main porosity regions within each core section for representative sample selection. The selected and extracted samples were characterized geologically and petrophysically using MICP analysis, porosity-permeability measurements, micro XCT images and petrographical analysis in order to identify main sedimentary textures and reservoir rock types (RRT), and then generate texture-based poroperm trends. The generated poroperm trends were combined with the DE derived logs in order to generate high-resolution porosity and permeability logs. The Dual Energy CT imaging provided bulk density and photoelectric factor data that were critical for the determination of porosity and lithological variation along the core lengths. The petrographical analysis revealed common and distinctive geological textures and RRT's within the main lithological groups of the Tayarat Formation. Unique and distinctive texture-based poroperm trends were generated for each lithological group. The derived porosity and permeability logs showed a very good match with the lab-derived porosity and permeability data. The integrated digital and conventional data at multiple scales were essential in improving our understanding of Tayarat geological and petrophysical properties.

The Burgan Minagish reservoir in the Greater Burgan Field is one of several reservoirs producing from the Minagish formation in Kuwait and the Divided Zone. The reservoir has been produced intermittently since the 1960s under natural depletion. A powered water-flood is currently being planned. The pressure performance of the reservoir has proved hard to explain without invoking communication with other reservoirs. Such communication could be either with other reservoirs through the regional aquifer of through faults to other reservoirs in the Greater Burgan field. Recent pressures are close to the bubble point. A coarse simulation model of the nearby fields and the regional aquifer was constructed based on data from the fields and regional geological understanding. This model could be history matched to allow all regional pressure data to be broadly matched, a result which supports the view that communication is through the regional aquifer. Using this model to predict future pressure performance suggested that injecting at rates that exceeded voidage replacement by about 50 Mbd could keep reservoir pressure above bubble point. It was recognized that the process of history matching performance was non-unique. This is a particular concern in the context of this study because the model inputs that were varied in the history matching process included aquifer data that was very poorly constrained. To address this problem multiple history matched models were created using an assisted history matching tool. Using prediction results from the range of models has increased our confidence that a modest degree of over-injection can help maintain reservoir pressure. This paper demonstrates the utility of computer assisted history match tools in allowing an assessment of uncertainty in a case where non-uniqueness was a particular problem. It also emphasizes the importance of understanding aquifer communication when relatively closely spaced fields are being developed.

As part of KOC strategy to develop the technical skills of the new recruits this paper will present a series of best practices related to decision workflows during drilling of horizontal wells through a recognized multidisciplinary team which optimized the preparation level and knowledge standard for the young generation through practical workshop and in short period. The best practices identified included aspects related to reservoir management, location selection, subsurface characterization and drilling specifics. Those were the key elements in the preparation of the technical training with the support of a multidisciplinary team that proved beneficial to the decision processes and issues faced during drilling in real time workflows. However optimization of a well needs skill, knowledge, right vision and experience, hence the results of the extensive drilling campaign and different cases of horizontal wells allowed the establishment of a practical training workshop protocol using actual acquired data for the planning, follow-up and assessment of drilling operations, which is now used in Fields Development South and East Kuwait. The practical workshop encompassed two case histories of horizontal wells where good decision procedure resulted in avoiding complications during drilling and effectively optimized most of the drilling path. This practical, interactive workshop was successful in developing with an integrated framework, the necessary skills in the participants, in all technical disciplines involved, namely Geosciences, Petroleum Engineering and Reservoir Engineering, in a pioneer effort of the Greater Burgan teams, not used before in KOC for training. The impact of this workshop was to enhance the experience of the young professionals in Petroleum Engineering, Geoscience interpretation and Reservoir Management, as well as to build their integrated knowledge on horizontal drilling for the benefit of KOC, across all Directorates and possibly applicable to other oil companies.

Improving water-flood efficiency in heterogeneous reservoirs with high permeability contrast is of high strategic importance to maximize oil gains, debottleneck production facilities and alleviate water-handling constraints. This paper presents key lab, simulation and field design insights to implement Deep Reservoir Conformance Control (DRCC) in the Wara formation of the Greater Burgan Field. Prior technical assessment and high-resolution streamline modelling are covered in other technical publications. Full-field high-resolution streamline reservoir simulations have been used to identify 23 candidate injectors for DRCC. The wells having one layer taking more than 50% of the total water injected were considered as good candidates for DRCC to mitigate water channeling challenges and increase sweep efficiency accordingly. Mechanical water shut-off options were considered, but it was confirmed that near-wellbore solutions do not adequately address deep reservoir conformance issues and can compromise water accessibility to unswept oil zones. Furthermore, mechanical water shut-off options require recompletion and can be expensive and difficult to deploy. To overcome these drawbacks, DRCC has been evaluated in an integrated laboratory and simulation study to design a field implementation plan. The recommended DRCC approach involves injecting a microgel followed by a gel. The microgel enables deep treatment while the gel strengthen Permeability Reduction near the well. Laboratory evaluation qualified a microgel having a size of around 2 µm and a gel combining water-soluble polymer with an organic crosslinker. Gelation time was 2 days and full gel consistency was obtained after two weeks, under the form of a strong and slightly deformable gel (E-F on Sydansk scale). Permeability reduction post gelation was as high as 10,000 times. Reservoir simulations were executed to validate this approach, size-up the treatment and forecast performance. A pattern involving an injector and a producer well was selected. Laboratory coreflood data were used as input for the simulations. The combination of microgel followed by gel with a total volume of around 6000 bbl, pumped in two days, induces a gain in oil production of around 20 to 50% in 10 years. Simulation shows improvement of both vertical and areal sweep efficiency. Moreover, the gain appears very early after chemical injection. The combination of microgel and gel gives an efficient in-depth conformance system that can increase waterflood efficiency in formations such as Wara. This innovative approach has high potential in multi-layer high-permeability heterogeneous sandstone reservoirs.

A detailed Geological and Petrophysical characterization was achieved in a stepwise approach as part of full field 3D Reservoir Modeling and Simulation study for Minagish reservoir in the Greater Burgan field in Kuwait.Foundation of Reservoir Rock Types (RRT) was developed in first step based on Mercury Injection Capillary Pressure (MICP) dataset. A combination of Discriminant Analysis and Indexed Self Organizing Map (SOM) was used for rock type classification using hyperbolic tangent method. To improve classification of bimodal Pc curves, additional pressure values at different non-wetting phase saturations were used in conjunction with above mentioned parameters. In second step, the available Routine Core Analysis (RCA) porosity, permeability data was grouped together based on common patterns to generate rock types in RCA domain. Blind tests in two of the cored wells revealed a conformance of 81% between MICP and RCA Petrophysical Groups (PG). In the final step of the process, petrophysical groups were propagated in log domain using available log measurements common in all the wells of the field. It was challenging to establish a high level of accuracy for PG's in log domain mainly due to fine scale heterogeneity and inability of log data to capture rock fabric variation.This porosity estimate, coupled with rock type classification, helped to derive a continuous permeability log with a correlation coefficient of 0.89 validated in key cored wells. The porosity and permeability data in all the wells was incorporated in the 3D geocellular model after up-scaling honoring the unique, per rock type, Phi-K relationship.Modeled capillary pressure curves generated for each rock type in the core domain using MICP data set in 3 wells were used in saturation height modeling. The modeled equation was captured in the 3D geocellular model after populating rock types in the 3D grid to map water saturation for volumetric estimation.