The Gas-Assisted Gravity Drainage (GAGD) process has been suggested to improve oil recovery in both secondary and tertiary recovery through immiscible and miscible injection modes. In contrast of Continuous Gas Injection (CGI) and Water-Alternative Gas (WAG), the GAGD process takes advantage of the natural segregation of reservoir fluids to provide gravity-stable oil displacement and improve oil recovery. In the GAGD process, the gas is injected through vertical wells to formulate a gas cap to allow oil and water drain down to the horizontal producer (s). In this paper, a field-scale compositional reservoir simulations were conducted to study the feasibility of the GAGD process to enhance the recovery of oil in synthetic and real oil reservoirs. The GAGD process was implemented through the 5th SPE comparative solution project model (SPE5) and the heterogeneous upper sandstone oil reservoir in the South Rumaila oil field, located in Southern Iraq. Four different gas mixtures were injected: carbon dioxide, flue gas, nitrogen to methane, and associated gas (AG). In the SPE5 model, it was investigated that CO2-AGD process is much better than other gas mixtures with respect to achieving the highest oil recovery because of the influential role of CO2-rock-oil interaction to enhance the recovery of oil in this homogeneous system. The flue gas and nitrogen plus methane mixtures had similar efficiency by obtaining approximate oil recovery. However, the results of south Rumaila field GAGD evaluation indicated that the associated gas has a slight higher oil recovery than other gas mixtures including CO2 because of its compatibility with the existing reservoir and fluid properties. More specifically, the oil recovery by the end of the perdition period through the CO2, AG, flue gas, and N2+CH4 were 73.88%, 74.25%, 74.13%, and 73.91%, respectively; whereas, oil recovery at the beginning of the prediction period is 66.8%. In addition, there are many other reservoir factors have significant impact on the process efficiency and led to change the efficiency of each of the four gas mixtures, such as heterogeneity. It can be concluded that the immiscible flooding of using associated gas for re-injection in the South Rumaila field has the same effect of using the CO2 with respect to achieving a promising oil recovery. Consequently, associated gas can be efficiently utilized for a pilot EOR project implementation in the Rumaila field as a cheap solvent alternative to the carbon dioxide.

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The deployment of a new positive displacement motor (PDM) technology as a solution to improve drilling performance in deep vertical exploration wells in northern Kuwait. The new technology of the positive displacement motor was developed within the framework of new capabilities in motor optimization modeling, a holistic approach to configuring motor components as an integrated unit, and new engineering advances in the material and design of motor components. The engineering advances and innovations can be distinctly categorized into two major components, the power section and the lower end. The power section components went under extensive empirical and experience-based failure analysis to refine the design of the subcomponents. The refined designs were then scrutinized with the industry-first motor optimization modeling that simulates both the performance and fatigue of the power section by analyzing eight influential variables of down-hole conditions, and components material and geometry. The second component, is the newly designed high torque lower end which houses an overhauled assembly of transmission and bearing sections. The new lower end was engineered to reliably handle and fully harness the full capabilities of the power section. The result, is an integrated new motor technology that is characterized by its superior resistance to stall, ability to sustain higher limits of differential pressure, and performance reliability in harsh drilling environment. Kuwait Oil Company (KOC), with its ever-expanding exploratory drilling campaign in northern Kuwait, was looking for significant improvements in drilling performance of vertical deep-drilling exploration wells. As such, KOC agreed to test the new motor technology in an exploration field north of Kuwait. The deployment of the new technology would take place in the 16 in section of a vertical well with a starting planned depth of 10,565 ft (3,220 m) and a total depth of 14,605 ft (4,456 m). The section drills through highly-interbedded and abrasive sandstone and carbonates strata with highly-variable windows of pore pressure and rock compressive strength. Given the complex lithology and the high-pressure environment, previous drilling campaign were tainted by low penetration rates, and motors and bits failures. In March of 2017, the new motor technology was field tested for the first time worldwide in northern Kuwait. The field test run covered an interval of 3,658 ft (1,115 m) over three runs. The new motor technology justified its higher specifications by improving the rate of penetration (ROP) by 62% compared with the fastest offset well drilled. The superior rate of penetration can be attributed to the new motor ability to deliver higher ranges of differential pressure, specifically 57% higher than offset wells. The deployment of the new motor technology successfully proved the capabilities of the new motor in drilling optimization and reliability, and also validated the engineering and modeling processes behind the new components.

The aim of most hydraulic fracturing treatment is to design and implement the best stimulation strategies that help to increase the short and long-term productivity of the stimulated reservoir section. This can be achieved by selecting the best treatment fluid types that are compatible with the formation to achieve the best combination of fracture geometry and well's productivity. The main objective of this study is to investigate the short and long-term wells’ productivity for the different types of hydraulic fracturing treatment fluids in the East Texas Basin Cotton Valley formation. Two hundred and sixty one Cotton Valley wells were identified and selected for this study. All the wells were horizontal and hydraulically fractured that were completed after 2012. The wells were classified based on the type of hydraulic fracturing fluid into four major groups: gel, water, cross-linked gel, and hybrid fracs. The hydraulic fracturing chemicals were obtained from FracFocus public record database. FracFocus data were processed then combined with production and completion data obtained from DrillingInfo database. Several data workflows were developed to classify the treatment fluid types based on the chemical ingredients of each fracturing treatment. The productivity in this paper is reported in terms of equivalent barrel of oil which converts every 6 MCF of gas into 1 equivalent barrel of oil. This paper investigates the Cotton Valley initial production (BOE/Day), cumulative 6 months, 1 year, 2 years, and 5 years and compares the productivity for each type of hydraulic fracturing fluids. This work also provides several insights about the wells performance as a function to stimulation parameters such as the amount of pumped proppant, the volume of pumped water, and the length of the perforated horizontal lateral. The normalized production and stimulation parameters to the perforated lateral are also discussed in this paper. This study discusses several data processing workflows that will help to illustrate the procedures to extract data from FracFocus and DrillingInfo. It provides an understanding of the hydraulic fracturing fluid types’ occurrence and measures the effect of stimulation and completion parameters on the short and long-term productivity.

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