Case Study: Integrated Study for Assessing Production Enhancement From a Matured Large Carbonate Reservoir
Authors: Al-Maraghi Eisa , Nair Cholamcottu V.G. 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

An integrated study has been conducted to build a reservoir management tool to evaluate feasibility of enhancing the production and maintaining the plateau rate long for the Umm Gudair field, a large carbonate reservoir located in Kuwait and the Partitioned Neutral Zone. A comprehensive data gathering campaign was made during initial phase of infill drilling and an appreciable volume of rock and fluid data were obtained which assisted the geoscientists and engineer in developing an improved static and dynamic model.

The lower cretaceous Minagish Oolite is the primary producing horizon of Umm Gudair field and is one of Kuwait's largest carbonate reservoir. It is located at an average depth of 8100' subsea and has a mean net oil column of about 200 ft. Although the field was discovered in 1962 and was on commercial production from 1968, it was produced at a low rate (mostly production to reserves ratio &lt; 0.5) due to limited production demands and processing capacity of the GCs. Accelerated production started about 5 years back with drilling of 70 additional producers, installing Electrical Submersible Pumps (ESP) in all wells, implementing water shutoff jobs and commissioning of two super GCs. Once the peak target production rate was achieved, the assets strategic objective was aimed on extending the plateau rate further to have a long plateau period. This required integration of large volume of drilling and surveillance data collected during the recent years and building an improved geological and reservoir model that will provide a good tool to assess future performance and to optimize the development plan to achieve the strategic production objectives of the asset.

A team of geoscientists developed a complex geostatistical geologic model, considering 3D seismic, large suit of log data from 170 wells, core description of about 6000 ft of cores collected from 31 wells, etc. The latest geological model has improved definitions of porosity, permeability, and Swi obtained by incorporating new well-bore petrophysical calculations, the properties assignment by rock types and representation of reservoir heterogeneity at the flow unit scale through appropriate application of deterministic, stochastic, and object modeling techniques. The detailed fine scale geologic model was built using one of the latest software and upscaled using a hybrid procedure involving statistical methodologies. The upscaled models were sense-checked through streamline simulations to ensure that the selected simulation model preserves the features of the finescale model.

The simulation model was history matched with 45 years production and surveillance data. Large volume of these data were available that included oil, gas, and water production of 165 wells, about 1900 data points on static/buildup pressures of the wells distributed through the historical production period and Repeat Formation Test (RFT) pressure profile in 45 wells. Additional data considered are saturation variation detected from open-hole and thermal decay logs, well productivity index (PI) data and flowing bottom hole pressure. History matching of the well and field production performance is done by ensuring the quality of the engineering data and applying minimum modifications to the geologic model maintaining the integrity of the geologic descriptions.

An excellent history match was obtained on a field-wide, regional, and individual well basis for water production, static pressure, and RFT profile. Reason for the success in achieving an excellent history match can be attributed to the care taken during data collection and analysis, improved geologic model, the upscaling procedure applied in converting the geologic model to the simulation model, and the processes applied in the history match.

The current production strategy for this reservoir is to produce it at a plateau rate of 250,000 bopd and extend the plateau production period through additional development activities like infill drilling, pressure support, etc. Therefore, the objective of performance study was to evaluate alternate development strategies to select the optimum development plan for the field, constrained by the overall production strategy. Predicted performances of the different cases were evaluated mainly on the basis of oil/water production profile, pressure decline, plateau period, acceleration of production, ultimate recovery and migration across the concession line.

Although there are only 3 crude processing facilities (GCs), facility network for the prediction cases has been prepared with some pseudo flow stations to model preferential production from specified areas that were required to implement the key elements of the production strategy. This approach provided flexibility to manage the wells at different levels as required. The wells rates in the prediction mode were constrained by the target production from the specific GC where the well is connected. An uptime factor has been implemented at well level to account the impact of downtime due to work over delays, Electrical Submersible Pump (ESP) run-life and ESP performance efficiency.

Based on the different Case studies, growth options and possibilities are identified in accordance with the Asset's longterm production strategy, along with the required additional development activities and modification of surface facilities to achieve the optimum production and reserves.