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Early in 1998, three horizontal oil producers were drilled with short radius horizontal section of 1000 ft to 1600 ft. Those wells were shut in 2007 due to the evolution of watercut as a result of inverse water coning experienced in Zone-Y. Gas lift was selected as the preferable artificial lift technique for subject reservoir, accordingly, the three horizontal producers were planned to be worked-over during 2011 in order to install gas lift mandrel. The expected production rate with GL was estimated to be around 400 bopd with a high watercut of ±70% after the gas lift application. An extensive review of actual wells’ performance in addition to the application of simulation model were performed in order to study the optimum scenario to reactivate and put the wells back on stream naturally taking the advantage of the workover job. Evaluation of multiple scenarios recommended to extend the horizontal section of subject wells to unswept area and also to consider water shut-off technique in the original hole to enable producing them naturally prior to Gas lift startup. An innovative one step approach, with direct rig intervention, utilized LWD (Logging While Drilling) resistivity data to identify intervals swept by advancing waterfront instead of the conventional approach carried out in two steps; the first being the rigless coiled tubing intervention to identify water entry intervals (PLT-Production Logging Tool) and the consequent utilization of rig intervention to carry out the actual water shut-off plus horizontal section extension operation. Using LWD data further improved the shut-off operation efficiency by deepening the depth of investigation while extending the horizontal section in the pay-zone, which was not possible with the rigless PLT operation. Another setback with rigless PLT operation is the requirement of minimum threshold flow condition which was not possible to achieve in the inactive producers. During the Workover, the Openhole log (LWD) recorded while drilling for all the three wells showed that the area around the original hole is depleted to Sw of ~70% and the extended hole is totally located in oil bearing Zone-YL, thus confirming the model findings and the analytical analysis. Accordingly, it was decided to isolate the original hole with 4 ½" pipe and swell packers and complete each well as single producer. The production test results for the three wells, post the workover, showed that each well is currently producing dry oil of around 1500 bopd with nil watercut. Results of accomplishment team recommendation revealed the following: The three wells were able to flow naturally and became active with nil watercut.A cost saving of around 15.0 MM$ was achieved as a result of the cancellation of drilling three infill horizontal wells that were originally planned in the same locations to sweep the unswept areas including new surface flowlines, equipments and cathodic protection.Additional capacity of 4500 bopd has been added to Zone-YL sustainable production capacity.

A prolific mature reservoir Unit-Y producing since the early seventies was subdivided into two major flow units, an Upper sub-zone (USZ) with Darcean permeability and a Lower sub-zone (LSZ) with permeability averaging a few tens of milliDarcy. This reservoir is part of a super giant onshore carbonate oil field undergoing secondary peripheral water flooding and operated by ADCO about 110 km southwest of Abu Dhabi. The Upper sub-zone (USZ) of the reservoir witnessed a very efficient piston-like waterflood in spite of some early water breakthrough since the early eighties due to the presence of high permeability vuggy streaks difficult to detect on conventional logs and usually not recovered during coring. Since the late nineties, the Lower sub-zone (LSZ) was the target of an intensive development involving two hundred horizontal producers with a 3000’ long 6" openhole reservoir section. With a relatively moderate horizontal permeability, the main flooding mechanism in the Lower sub-zone (LSZ) was identified as the slumping of water from the flooded areas of the Upper sub-zone (USZ) after production drawdown from the producers in the Lower sub-zone (LSZ) was larger than the slightly negative oil-water capillary imbibition threshold initially preventing the gravity-controlled downward movement of water. The unusual aspect of this inverted water coning situation brought a focus on the determination of the optimum production rate for the horizontal producers located in the Lower sub-zone (LSZ). A maximum production rate of 1500 blpd was assigned to the Lower sub-zone (LSZ) horizontal producers until field observations (production logging, repeat saturation logging, multi-rate testing, fiber glass casing) and the results of two pilots batches including twenty seven producers set at a higher production rate could be used to calibrate reservoir simulation models. All data acquired and studies performed over the last ten years have shown that these horizontal wells could be safely produced at a higher rate with no adverse effect on the water breakthrough timing, planned ultimate recovery or well integrity. The adoption of this higher production rate resulted in a major optimization of the business plan requirements at a time of high rig demand and with an increasingly busy surface running out of new drilling locations.

This paper represents a case history of a full-field development plan for one of the major fields (field "A") in Abu Dhabi Company for Onshore Oil Operations (ADCO-UAE) consisting of three different reservoirs. Field (A) development is becoming increasingly complex and expensive as this field acts as a hub for another two producing fields and several undeveloped fields. This involves developing an efficient design and planning philosophy. Best practices in integrating new technologies in materials, construction, operations as well as management techniques including the right team to really be successful are all part of the "big picture". ADCO assigned a cohesive and highly motivated team involved in the ‘big picture" event with a clear direction in terms of policy, risks and implementation aimed to shorten the decision process without compromising the company Major Project Approval Process (MPAP) requirements and Shareholders guidelines. The Project Management main factors that were tackled successfully during this event were the focus on profitability and increase of NPV by adopting a multi-disciplinary approach to field management; align various departments involved right from the concept to the implementation stage through continuous interaction; cultivate an open-ended approach to all aspects of engineering and Field Management by taking into account both the surface and subsurface perspectives of oilfield Project Management. The paper will also address the structure of the team and how it set feasible targets in terms of production building blocks of other fields through eventual expectations in terms of surface facilities and helped in overcoming challenges and minimizing risks through careful integrated risk register. Finally assessed specific problems and issues relevant to the field operability and evaluate possible strategies to tackle it. The key objective and achievements of the event were the deliverables for the Stage-4 of the MPAP. The paper will discuss the achievements as a result of this event. The integration of the development options alternatives, into a single development plan enabled shortening the decision process and secured Shareholders approval on Gate-5 finance proposal as it was recognized as an economically favorable development opportunity. The development plan continued to other Gates (7 & 9) with the same approach in order to properly accomplish the success of such plan with a value of multi Billion USD.

The subject field has been on production for more than 35 years from multi-layered heterogeneous carbonate reservoirs. Due to the field's maturity, the water cut has started increasing gradually in some producers and, consequently, production from these wells has been affected awaiting implementation of artificial lift. To deal with the water production and prolong the natural flowing life of the wells, various water shut-off techniques available in the industry were evaluated in order to select the most suitable one that could be deployed in open-hole sections of horizontal wells. This paper presents two case studies where a mechanical water shut-off technique, involving swell packers, was successfully applied in horizontal open-hole sections. The systematic approach adopted by the operator to build the business case, select the candidates, acquire the PLT data, execute the jobs, evaluate the performance of the water shut-off jobs and future plans are presented in this paper. The paper also addresses the conceptual application of borehole segmentation with swell packers to improve well performance.

The subject reservoir is a heterogeneous carbonate formation in a giant field located in the onshore area of Abu Dhabi. The reservoir can be divided into a higher permeability upper zone and a lower permeability lower zone, with comparable initial oil in place. The reservoir is currently under peripheral water injection. Because of a high contrast in permeability, the injected water has advanced in the upper zone much faster, resulting in watered out wells in this zone. The water movement in the lower zone is by inverse coning from the upper zone. A gas injection pilot was initiated in 2002 to evaluate the benefit of miscible gas injection as a secondary process in the lower zone and a tertiary process in the water-flooded upper zone. This paper covers the pilot description and the corresponding compositional simulation studies. A comprehensive pilot monitoring program was designed to acquire key performance data, including, time-lapse saturation logs, PLT, wellhead and bottom-hole pressure, production tests, gas tracers, and well head samples. The compositional simulation studies comprise one-dimensional models for examining the displacement process, a fine-grid pilot model for analyzing and optimizing pilot performance, and a full field model for assessing potential benefits associated with field-scale gas injection options. The pilot has been in operation for over three years and has met all the initially set objectives. The paper discusses the observation results and compares them with simulation predictions. We show that model predictions satisfactorily match field observations. In particular, both model results and time-lapse saturation logs indicate that the gas, which is injected from a horizontal well in the bottom of the lower zone, quickly moves to the more permeable upper zone, resulting in poor sweep of the lower zone. The results of the monitoring program are used to optimize the pilot performance and to calibrate the dynamic reservoir simulation model for more reliable predictions.

Simulation models are routinely used as a powerful tool for reservoir management. The underlying static models are the result of integrated efforts that usually includes the latest geophysical, geological and petrophysical measurements and interpretations. As such, these models carry an inherent degree of uncertainty. Typical uncertainty analysis techniques require many realizations and runs of the reservoir simulation model. In this day and age, as reservoir models are getting larger and more complicated, making hundreds or sometimes thousands of simulation runs can put considerable strain on the resources of an asset team, and most of the times are simply impractical. Analysis of these uncertainties and their effects on well performance using a new and efficient technique is the subject of this paper. The analysis has been performed on a giant oil field in the Middle East using a surrogate reservoir model. The surrogate reservoir model that runs and provides results in real-time is developed to mimic the capabilities of a full field simulation model that includes one million grid blocks and takes 10 hours to run using a cluster of twelve 3.2 GHz CPUs. In order to effectively demonstrate the robustness of Surrogate Reservoir Models and their capabilities as tools that can be used for uncertainty analysis, one must demonstrate that SRMs are competent in providing reasonably accurate results for multiple realizations of the reservoir being studied. In order to demonstrate such robustness and their predictive capabilities as well as their limitations, this paper will examine the performance of the surrogate reservoir models on different geologic realizations of the static model.

Reservoir simulation has become the industry standard for reservoir management. It is now used in all phases of field development in the oil and gas industry. The full field reservoir models that have become the major source of information and prediction for decision making are continuously updated and major fields now have several versions of their model with each new version being a major improvement over the previous one. The newer versions have the latest information (geologic, geophysical and petro-physical measurements, interpretations and calculations based on new logs, seismic data, injection and productions, etc.) incorporated in them along with adjustments that usually are the result of single-well or multi-well history matching. A typical reservoir model consists of hundreds of thousands and in many cases millions of grid blocks. As the size of the reservoir models grow the time required for each run increases. Schemes such as grid computing and parallel processing helps to a certain degree but cannot close the gap that exists between simulation runs and real-time processing. On the other hand with the new push for smart fields (a.k.a. i-fields) in the industry that is a natural growth of smart completions and smart wells, the need for being able to process information in real time becomes more pronounced. Surrogate Reservoir Models (SRMs) are the natural solution to address this necessity. SRMs are prototypes of the full field models that can run in fractions of a second rather than in hours or days. They mimic the capabilities of a full field model with high accuracy. These models can be developed regularly (as new versions of the full field models become available) off-line and can be put online for automatic history matching and real-time processing that can guide important decisions. SRMs can efficiently be used for real-time optimization, real-time decision making as well as analysis under uncertain conditions. This paper presents a unified approach for development of SRMs using the state-of-the-art in intelligent systems techniques. An example for developing an SRM for a giant oil field in the Middle East is presented and the results of the analysis using the SRM for this field is discussed. In this example application SRM is used in order to analyze the impact of the uncertainties associated with several input parameters into the full field model.