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.

Increasing water cut in oil-producing zones is a common issue, particularly in mature fields. Currently, most decisions are governed by economics, and incurring additional expenses, such as handling produced water, is undesirable. Depending upon the source of the water production, chemical isolation provides one effective solution to this issue. This paper describes a cost-effective coiled tubing (CT) intervention to implement permanent zonal isolation for water shutoff using an organically crosslinked polymer (OCP) sealant system and a modified organically crosslinked polymer (m-OCP) sealant system to provide a controlled, shallow penetration solution to the problem in a high-permeability, low-pressure reservoir. The traditional water shutoff method uses rig intervention for cement squeezes, which targeting shallow penetration can be time consuming and expensive in a high-permeability, low-pressure reservoir. The OCP sealant system is an organically crosslinked polymer that is thermally activated to effectively seal the targeted interval. The m-OCP sealant system combines particulates with the OCP sealant system to provide leakoff control to help promote shallow matrix penetration. The production logging tool (PLT) data for the candidate well indicated that the maximum water cut originated from the lower perforations and a single zone. CT intervention was selected to accurately place the OCP and m-OCP sealant systems and to permanently block water production by creating polymer barriers inside the reservoir and to remove any remaining OCP/m-OCP from the wellbore. OCP and m-OCP are resistant to acid and H2S and provide the required radial penetration. This system provides a predictable and controlled set time (as shown by laboratory testing). Because this system does not develop compressive strength, a simplified cleanout with a jetting nozzle is required to wash it from the well. After completing the zonal isolation with the OCP sealant system, the pressure test for the zone indicated a good seal. An electric submersible pump (ESP) was run on the completion string, and initial test results showed that the water cut was reduced from 97 to 75%, and oil production increased from 175 to 300 bpd. Increased production will recover all intervention and chemical costs within 20 days. The polymer sealant system with the customized intervention solution successfully reduced the water cut for this west Kuwait field. The same approach can be applied to other similar fields worldwide.

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.

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The five detector pulsed neutron (FDPN) tool is one of the most advanced tools in cased-hole reservoir evaluation. The evolution of multi-detector pulsed neutron tools (MDPN) created a turning point in the methodology to properly handle the different challenges within petrophysical cased-hole evaluation either in conventional or unconventional formations. This study demonstrates the applications of the FDPN tool and the methodology to handle the challenges in the multi-barrier well bore systems. The FDPN tool was used in two double-barrier well bore field cases in addition to one case with a triple casing system. Each case was unique in terms of objectives and challenges: Case 1 (13.375 inch, 9.625 inch and 7 inch casings) aimed to estimate the presence of gas in the annulus between the two casings and the formation gas behind the double-barrier wellbore system, while Case 2 (7 inch liner and 4.5 inch ICD) required to perform a three-phase calculation. In Case 3 (13.5 inch, 10.75 inch and 7.625 inch casings) diffusion-corrected sigma was recorded to be able to determine the water saturation in a triple casing system. In all these case studies, Monte Carlo simulations (MCNP) were performed to characterize tool response and to determine if the data to be recorded will achieve the objectives of these jobs. In Case 1, the FDPN tool helped to establish the presence of gas in the annulus between casings and determined the gas saturation profile in the formation using the difference between the normalized capture and inelastic ratios. This case was unique since other MDPN tools were not able to quantify the volume of gas in the formation due to their lower gas sensitivity. In Case 2, the objectives were successfully achieved. Also, it was possible to differentiate between the formation gas and the gas pockets between the 7 inch liner and the 4.5 inch ICDs using the comparison between inelastic and capture measurements. In Case 3, a diffusion-corrected sigma was measured and identified formation water movement in the zone of interest which helped to make a decision about drilling of the offset well. The FDPN tool provides a higher spacing between the detectors and neutron generator which gives a better quantification of hydrocarbons especially for large casing and borehole sizes. Furthermore, the spacing between the long and proxy detectors is increasing the gas measurement sensitivity compared to other MDPN tools. Also, the 1.69 inch pulsed neutron logging tool was successfully run for first time in Kuwait to record diffusion corrected Sigma over a triple casing interval.