Throughout the last few years, oil company strategies have moved toward recovery of the maximum oil in place from mature fields and reservoirs that were previously considered technically challenging. The Mauddud formation in the Bahrah field is a low permeability carbonate formation with moderate to high oil viscosity. Viscosity is between 2 and 7 cp at 170°F, but a 90-cp viscosity at surface conditions is commonly observed once a well is placed on production, creating challenges for a vertically drilled well that could not provide necessary levels of sustainable production. In an attempt to achieve economic continuous production, a 3,000-ft lateral horizontal well was drilled. The lateral length was designed as an optimal solution for such a challenging reservoir to help sustain the production flow. Additionally, a multistage acid fracturing (MSAF) treatment was performed. This paper discusses the design, execution, and production of the first MSAF treatment performed in the Mauddud reservoir using a cased openhole completion with swell packers and sliding sleeves that were placed in seven stages across the 3,000-ft lateral interval. Post-operation analysis exhibited highly sustained production, creating a shift in oil company plans toward drilling new horizontal wells and applying MSAF treatments to move the Bahrah field into the development phase. Results obtained from this operation were effectively used to help improve production in similar mature formations. Based on this pilot treatment, a wide-scale field development strategy was planned, and many wells were drilled, completed, and fractured similarly in Bahrah field.
Central Asia has become one of the energy hubs in the world with latest significant discoveries including but not limited to Kashagan, Tengiz, Karachaganak, Azeri-Chirag-Guneshli fields. Geographical and political dynamics of the Central Asian countries help the countries to stand out as a significant stable and sustainable source of energy in the region with great resources of supply and low domestic demand. This study outlines economic and technical analysis of oil and gas resources of central Asia under demand and supply dynamics of world hydrocarbon production. A comprehensive literature review has been carried out to investigate the basins and major oil and gas fields of the region, their development from the beginning, the technologies utilized, types of recovery processes, supply capabilities and potential of future supply are addressed. Real field applications are illustrated with applications in different parts of the region with challenges, advantages and drawbacks discussed and summarized in comparison to other major energy hubs of the world and their major oil and gas fields and basins. Central Asia is a relatively young and dynamic region with growth potential of harnessing the great and relatively new resources. Due to the political and geopolitical dynamics of the region, Central Asia serves as a strong and stable provider of energy obtained from fossil fuels. Low domestic demand in the region makes it more attractive in terms of the amount of export potential. There is no recent up-to-date study that investigates and outlines not only the technical characteristics of fields, reservoirs and basins in the region but also the demand/supply dynamics of the resources in the regions as they compare to the other major energy hubs in the world. This study comparatively outlines the key elements of successful applications in the region along with the lessons learned from challenges as well as the current and near-future potential of Central Asia as an energy hub in the world.
Producing hydrocarbons at appraisal and development targets from deep, overpressured, high pressure/high temperature (HPHT) Jurassic carbonates in Northern Kuwait has been a challenge as a result of the complex reservoir heterogeneity. Because of the tight carbonate formation properties, matrix acidizing does not always deliver hydrocarbons at economical rates; in this scenario, hydraulic fracturing is required. Hydraulic fracturing, however, presents placement and activation challenges as a result of the wellbore construction limitations and a complex tectonic setting/high stress environment. The zone of interest in this dolomitic reservoir was identified as an acid fracture candidate because of the immobility of fluids identified during multiple pressure sampling tool attempts, despite a reasonable valuation of the log-computed porosity and permeability in the range of approximately 10% and 1.1 md, respectively. In addition, solid hydrocarbons (bitumen) were reported in the cuttings samples, which indicates the possibility of in-situ conductivity damage. The well trajectory was designed as a high angle deviated well to maximize the reservoir exposure, with a maximum inclination of 49 to 50° through the zone of interest. The reservoir was drilled at a slight overbalance with 13.0 ppg of oil-based mud, using mud weight management techniques to minimize the formation damage. The highly deviated wellbore and the highly anisotropic stress regime complicated the effective design and placement of the acid fracturing treatment. As an added challenge, the operation had to be completed within a very short period because of the high cost of the deep drilling rig on site to facilitate the operation. The hydro-fracture field case was built on the analyses of the open hole logs, 1D geomechanical earth model, and a customized data-fracture suite to meet the data acquisition needs, followed by the design and calibration of an acid hydro-fracture treatment using a pseudo3D grid-based fracture modeling and calibration software. A solids-free dynamic diversion schedule was built and field-laboratory level fluid design tests were conducted to reach the most optimal design possible. A robust and operationally pragmatic fracture program was developed and implemented successfully in a very short notice period. The mobility of the formation fluids was established, leading to a critical understanding of this sour unconventional carbonate flow unit. Data fracture analyses and a customized acid fracturing technique described in this paper are the first of its kind in the deepest parts of the Northern Kuwait sour gas basin. A collection of completions data has proven critical in terms of reservoir deliverability aspects and in the calibration of the mechanical formation properties, leading to a better understanding of the hydro-fracture geometry and how to effectively connect to the higher mobility segments of the reservoir. This paper also outlines the future optimization plans based on the lessons learned from the fracture tests conducted in the well.
A significant challenge in the tight Mishrif oil reservoir of the Minagish field is ensuring hydrocarbon flow through the complex and highly damage-susceptible carbonate intervals. In recent years, field development strategies have begun to prioritize multilateral well technology over vertical and deviated wells because of the advantages of maximized reservoir contact, higher production rates, and improved access to reserves (hydrocarbon in place). The downside of most unconventional multilateral wells is that laterals are open hole, completed with much complexity, and pose challenges for effective acid stimulation because of poor acid distribution over the long interval. The Mishrif formation in the Minagish field in west Kuwait is a challenging tight carbonate with poor reservoir quality, relatively low pressure, and no external pressure support. The stimulation methodology was highly modified as fit-for-purpose to address the unique challenges of multilateral well operations, formation technical difficulties, high-stakes economics, and untapped potential from these formations. Furthermore, to enhance production, the lateral lengths of the well were designed as an optimum solution. To maximize and sustain hydrocarbon flow and production, a multiple stage acid pinpoint treatment was performed by dividing the wellbore into small intervals, based on petrophysical and reservoir properties evaluations; a high-rate pinpoint technique was used for both laterals individually. The selected sections were individually acid stimulated, and the inflow contribution from the entire productive sections of both laterals was maximized with a highly reliable and effective multistage continuous operation. The post-operation well test and production data show a significant production increase; long-term production data show a sustained production increase, stable pump intake pressure, and low water cut, demonstrating the success of the pinpoint technique as an optimized solution for the first multilateral well. The success of this well stimulation method has enabled the use of this pinpoint-squeeze as the best technique for all horizontal wells in this field. This paper summarizes the design processes, challenges encountered, production response, and lessons learned from applying this pinpoint acidizing technique. It can be considered as a potential approach for addressing stimulation challenges in similar tight carbonate reservoir conditions in other fields.
Water injectors typically suffer from injectivity decline attributed to near wellbore (NWB) damage typically caused by variation in injected water quality, pores plugging caused by scale precipitation, and fines migration. Conventional stimulation treatments to improve injectivity are conducted with coiled tubing (CT) to enhance fluid placement. However, this often sacrifices stimulation effectiveness because of the relatively low fluid penetration into the formation compared to bullheading treatment. The net result is lower than the expected treatment efficiency and increased stimulation frequency. This paper discusses a new placement technique using a fluidic oscillator (FO) tool that causes alternate bursts of fluids within the wellbore. The resulting pressure pulses propagate radially into the formation, carrying the stimulation fluid and enhancing its penetration deeper into the reservoir. A well- planned stimulation treatment recipe in combination with CT and a FO proved to be very effective in terms of stimulating water injectors. Case histories from six water injector wells stimulated using this technique is presented. Post-stimulation results show considerable increase to injectivity rates and decrease of stimulation frequency.
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