An operator launched a "water shutoff" polymer development project for a monobore gas well completion in the Gulf of Thailand. The shutoff concept involved a conservative tubing pad application in which a water shutoff polymer technique was used to help prevent wellbore restriction by sealing off the target reservoir permeability zone. Job planning and careful laboratory testing were conducted to simulate bottomhole conditions. In 2009, the treatment was used to perform shutoff of the top water producing zone using bullheading. The design consisted of the shutoff treatment followed by a loss circulation material (LCM) to help ensure wellbore fluid placement in the designed positions and that the pressure response could be monitored from the surface. The shutoff operation was performed according to plan, and coiled tubing (CT) was used for cleanup after placing the shutoff treatment. As a result of well testing after the shutoff treatment, water production dramatically decreased by 50%, demonstrating the effectiveness of the technique in terms of safety, economics, and operation. A long-term monitoring program was established to evaluate the polymer's seal-off performance for development of future field strategies.Since 2009, water production monitoring has proven that the shutoff polymer is one of the best solutions for long-term water shutoff in terms of safety, economics, and operation. This technique does not require mechanical sealing off of the perforations, making it more feasible for future well interventions.

Successful completion and performance of a horizontal well is one of the most dynamic and complex tasks within the oilfield industry, especially when conventional well is an underperformer. Sustaining production from tight reservoirs with conventional stimulation techniques is one of the most challenging tasks. The reservoir of interest is a tight, low permeable carbonate with thin layers. Productivity proven insignificant with considerable in place volume. The objective is to increase and sustain productivity of a pilot well that consists of an open-hole completion. Multi-disciplinary data is reviewed in a systematic way to identify reasons of low productivity and to identify possible solutions. After comprehensive studies and risk assessments, it is concluded to re-complete well with cemented Frac string to perform hydraulic fracturing with Plug and Perf (PnP) technique. This technique is applied within a conventional tight reservoir, allowing for the flexibility of stage count, stage spacing, and multi-cluster design in order to maximize the stimulated reservoir volume (SRV) along 2,000 ft. in upper layer, 1,000 ft. across middle layers and 2,000 ft. in lower layer. In addition, company and service provider collaborated to enhance this design through a zero over-flush technique along with diverting agents. Core, logging data collected from pilot hole is used to build 1D Mechanical Earth Model (MEM), which is further calibrated with MiniFrac performed with Wireline Formation Tester (WFT). A challenge is to avoid Frac height growth towards underlying reservoir, which is separated by dense carbonate layer of 40 ft. Extensive modeling is conducted in order to choose correct Frac design along the lateral in which landing depth is variable in different target layers of interest that added complexities to Frac Fluid selection. Finally, two Frac systems are selected for different segments of the lateral. After running a cemented casing, Six (06) Acid fracturing treatment and five (05) Proppant fracturing treatments are successfully executed in the lower and upper layers respectively. A comprehensive production test is performed to evaluate and compare the testing results of pre and post frac well. To evaluate the contribution of each stage, a Production Logging Tool (PLT) is deployed. The PLT tool shows the contribution and flow distribution across all the clusters and the efficiency of the Frac design and diversion technique/system. This paper summarizes the design processes, selection criteria, challenges, and lessons learned during design and execution phases. It may provide a potential approach for selecting the proper hydraulic fracturing (Acid Vs Prop) and technique (PnP with clusters Vs PnP with one set of perforation). Company has significant portfolio of undeveloped tight carbonate reservoirs with low productivity and considerable volume in place. This technique will pave the way for developing these reservoirs.

Multiple-zone stimulation poses unique challenges for completion engineers. Achieving accurate fracture and proppant placement while performing an efficient and low-risk operation can be unattainable when using conventional stimulation methods. The uncertainty with respect to fracture and proppant placement is amplified when fracturing in ductile rock, where, to maximize access to the reservoir, more fractures must be placed along a given lateral. This increase in fracture intensity can result in an increased risk of unplanned well intervention and downtime, with more trips to run guns, as well as more plugs to drill out.Stimulation techniques involving coiled tubing (CT) deliver improved efficiencies in horizontal completions because of the ability to instantly address contingencies by having CT in the hole throughout the operation. This method enables accurate fracture and proppant placement, as these operations typically focus on placing one fracture at a time. Isolation is commonly achieved using sand plugs, which have demonstrated to be especially effective; however, when fracture intensity is applied, sand plugs might not achieve the spacing required. This is because of the length of sand plugs often necessary to achieve isolation. Also, the time to set sand plugs can be considerable if they do not properly set the first time.This paper introduces a new CT annular fracturing (CTAF) system, referred to as CTAF-Anchor, that offers a low-risk, operationally efficient, and effective multizone stimulation method designed to reduce the non-productive time (NPT) between stages and allow for closer fracture spacing to maximize stimulated reservoir access. Also included is a detailed study of the process and case histories that translated into a maximized return on investment (ROI) for the operator.

This paper introduces a new coil tubing deployed system which uses Hydrajet Assisted Fracturing (HJAF) technology to lower treatment pressures and optimize fracture extension in the zone of interest. This process offers a low-risk, operationally flexible, and efficient multi-stage stimulation method designed to reduce the time between stages and minimize the total fluid pumped into the reservoir. Also included is a detailed case history in the Spearfish that demonstrates how this process can maximize return on investment (ROI) for the operator.

Well pressure integrity is a primary concern during offshore operations. Without proper control, barriers can significantly impact safety and production activities. Once a well barrier is unable to deliver pressure control, correcting the pressure integrity problem as quickly as possible becomes a priority. This paper describes a case where, in a conventional gas lifting oil well, a downhole packer leaked during production and significantly reduced hydrocarbon production. A conformance system was introduced to a Gulf of Thailand operator. The conformance system's rigid setting fluids are a new generation solution for plugging or temporarily isolating specific zones. The system was engineered to help ensure conformance would set at the right angle and temperature under specific well conditions. High-pressure resistance, low solution viscosity, and zero shrinkage are advantages of using the system to recover well pressure barriers. The conformance operation was performed using an electric line (e-line) punched target below the downhole packer inside production tubing to help establish conformance injectivity. Once the rate was confirmed, the conformance solution was squeezed to target the zone using coiled tubing (CT). CT was an important component of the solution necessary for cleaning as thoroughly as possible. Conformance pressure was confirmed under controlled conditions. The design only allowed a few hours for the solution to build up compressive strength, so a pressure test was performed from the "A" annulus, and the well could hold 1,500 psi. The recovery of well pressure integrity successfully addressed the well control issue for the entire life of the well and restored hydrocarbon production from an inability to produce to production of 200 B/D. Using this system, a workover of the rig was not necessary to recomplete the well by replacing the downhole packer and risking hydrocarbon exposure during workover operations. This conformance solution was ideal for correcting the packer leaking problem.