The strategy of the Kuwait Oil Company (KOC) is to implement key/emerging technologies at a country wide scale to meet future oil demand and production targets as planned in KPC 2040 strategy through overcome the field's challenges. KOC's Optimization strategy focuses on: Increased and optimize oil production from production optimizations Extension of field life Production interruption associated with pressure build up in reservoir, wellbore and flow lines have observed among many wells in West Kuwait fields perforated in Upper Burgan formation, which has a great impact on the company strategy. Tight emulsion phenomena is consider one the most challenging problems in West Kuwait wells due to the nature of asphaltenic crudes and high water cut production percentage. Traditional approaches to reduce high pressure and break the emulsion phase through injecting chemical near wellhead or in annuls is usually not successful in most cases and require large amount of chemical. Due to the complexity of this issue, a novel approach was used in this study to identify the main causes of oil production reduction and overcome the challenge to maximize oil production in West Kuwait fields.
The Mishrif formation in west Kuwait is a tight carbonate reservoir having low oil mobility. It is fractured and heterogeneous with wide variation in porosity ranging from 10 to 25%, matrix permeability of about 0.1 to 10 md, and 20°API oil. Production tests and geomechanical study results have revealed that productivity is mostly from the high-permeability matrix and critically stressed fracture networks. Recently, the Mishrif development has been dominated by horizontal wells to maximize reservoir contact and enhance productivity. However, a challenge in such openhole completion is the stimulation strategy requiring effective diversion technology due to the uneven acid distribution along the lateral section. To address those challenges, a novel engineered workflow has been implemented relying on distributed temperature sensing (DTS) to assess the fluid coverage across the openhole section. Results enable identifying high- and low-intake zones, segmenting the uncased section into intervals requiring different levels of stimulation, and making informed decisions regarding diversion requirements. The intervention was conducted in two stages. Coiled tubing (CT) was the selected fluid conveyance method on the first stage given its capacity for more controlled fluid placement, and high-rate bullheading stimulation was selected for the second stage. During the treatment, multiple challenges were faced, mainly driven by a high-permeability streak identified by the DTS near the heel of the lateral. The CT stimulation procedures were modified on the spot, and measures were taken to minimize the impact on the thief zone, which included a combination of diversion techniques, such as high-pressure jetting, dual injection, and pumping of a near-wellbore nonreactive diverter, which is composed of a customized blend of multimodal particles and degradable fibers to minimize fluid leakoff into the high-intake zone. Likewise, real-time downhole telemetry was crucial throughout the CT stimulation because it allowed the highest injection rate possible below the preset pressure limits, continuous monitoring of downhole dynamics along the intervention, and optimal actuation of the high-pressure jetting tool. Upon completion of the CT stimulation, a second DTS log was carried out to evaluate the fluid coverage and effectiveness of the diversion strategy, enabling further adjustment of the bullhead stimulation program. This stimulation workflow implemented in west Kuwait represents a cost-effective alternative to stimulate openhole tight carbonates. This study brings new perspectives for treating complex reservoirs in the region, and shares lessons learned for future interventions.
In recent years, field development strategies have begun to prioritize horizontal well technology over vertical and deviated wells because of the advantages of maximized reservoir contact, higher production rates, and better access to available hydrocarbon reserves. Some of the horizontal wells completed with openhole wellbores in carbonate formations are actually stable and good producers when the reservoir permeability is sufficiently high to not require a large or complicated stimulation treatment. If the permeability is low (i.e., less than 10 mD), as in most cases, this type of completion challenges any type of acid stimulation because of the well architecture and resulting poor distribution of the stimulation fluid over the entire lateral section. The Mishref reservoir of the Minagish field, located in western Kuwait, is a tight carbonate formation with poor reservoir quality and relatively low reservoir pressure; it was completed conventionally with openhole wellbores. The acid stimulation treatments performed in this area that showed positive results led to the selection of a multistage acid fracture stimulation of shorter horizontal wells. To enhance production in this field, the lateral length of the horizontal wells has been increased; the increased length, however, has also increased the challenges associated with proper stimulations if these issues are not considered during the completion stages of the wells. To maximize and sustain hydrocarbon production in long horizontal open holes, a multistage acid fracturing stimulation is still required if selective tools are used to complete the openhole section. The selective completion tools enable the mechanical segmentation of the annular space of the wellbore by dividing it into the required small isolated intervals based on petrophysical and reservoir properties. The isolated sections can be selectively stimulated to maximize the productivity in one continuous intervention. This paper summarizes the design processes, stimulation challenges, production response, and lessons learned from one multistage acid fracturing stimulation performed on a well drilled and completed in the Mishref reservoir of the Minagish field. In this well, the entire 1,800-ft length of the openhole lateral was divided into seven isolated stages by using swell packers and sliding sleeves. Because of the architecture and nature of the wellbore and the requirement to generate long fractures to properly drain the reservoir, the isolated compartment length (distance from the swell packers isolating the stage) was reduced to an average of 106 ft, and a sliding sleeve was placed in the middle of isolated sections. The paper documents the pilot multistage acid fracturing treatment on this type of completion; it also demonstrates the success of the stimulation in that the outcome exceeds the expected production increase, resulting in a more sustained production, as compared with the offset wells.
Objectives/Scope The Horizontal wells enhance reservoir performance by placing a long wellbore section within the reservoir. As they help in reducing water and/or gas production, increasing oil rates, reducing sand production and finally in achieving efficient drainage of the reservoir. The inflow control devices (ICDs) are used to address the issues of premature water and/or gas breakthrough, uniform flow distribution and reservoir depletion in the oilfield. They reduce the flow of unwanted fluids and balance the production distribution across the entire lateral section. The production contribution across the ICDs monitoring to take necessary remedial action is one of the challenges in this type of completion. In this case study, the main objective was to determine the contribution profile and source of water in horizontal well with passive ICD completion installed back in 2011. The various challenges were the low production rate, heavy oil with water, erratic and inconsistent nature of the well flow, ESP design test with lack of recent flow results, and lack of some data about the ICDs. In addition, unlike most of the cases where the ICDs are installed in open hole, this case the ICDs are installed in 7in liner with nine perforation intervals. Methods, Procedures, Process This paper presents the use of multi arrays production logging combined with spectral noise and high precise temperature tools, to determine the contribution profile and source of water in this challenging ICD completion. Results, Observations, Conclusions The contribution profile across the ICDs was determined using the multi arrays production logging data and temperature simulation models assisted by noise data. The results were in contrary to the previous production logging results and helped significantly in the design of proper ICD cleaning operations. The work-over resulted in successfully restoring and attaining high oil gain. Novel/Additive Information The innovative combination of multi arrays production logging combined with spectral noise and high precise temperature tools to determine the contribution profile and source of water in horizontal well with ICD completion.
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