Channeling behind casing connecting two sandstone reservoirs in well 13 was suspected due to poor cement job, possibly due to the high angle well of 76 deg. Avoiding communication behind casing between two sands is detrimental for field reservoir management where reservoir pressure maintenance with water injector wells is paramount for continuous production. This paper describes the treatment background, engineering approach, laboratory testing and QA/QC procedures, fluid design stage and job execution using the propriety low viscosity polymer system to seal off channeling behind casing. Cement bond log performed in well 13, a 76 deg. directional well drilled offshore Peninsular Malaysia showed very poor bond behind casing. An injectivity test conducted by setting a retrievable packer in between perforation intervals of the two sand bodies near the suspected channeling confirmed communication between the two sands. Repair alternatives were evaluated opting between cement or polymer gel squeeze. Hydraulic calculation based on the injectivity test result, roughly set the equivalent channel diameter as 0.15 in. Cement squeeze was therefore rejected in view of the small and long cement channel of 109 m. An alternative method to squeeze a low viscosity polymer system into the channel behind casing was hence designed for the purpose of sealing off the channel. The procedure developed was to create a single perforation in between the two perforations in both reservoirs and squeezing the polymer. A retrievable bridge plug and a retrievable packer straddled the squeeze perforation interval and a polymer gel squeezed through the said perforation. After several squeezes each followed by a curing time, pressure tight seal isolating the two reservoir sands was obtained. This was confirmed by setting a retrievable packer above the lower most perforation in the reservoir sand followed by injecting brine while monitoring for returns through the upper perforation, which were none. This unique method, never applied before, to repair a 109 m continuous cement channel between two reservoir sands separated by a thick shale layer using cross linked gel was successful. Two years later the seal is still intact with production from this dual completion well continuing trouble free. The proprietary gel applied is a cross linked low viscosity polymer which cures under downhole temperature to form a tough seal. It is learned that running a retrievable bridge plug and a retrievable packer in tandem in high angle well best not be attempted in future, instead, both should be run separately. Acidizing through the squeeze perforation will assist to improve squeeze pressure. Application of cross linked gel to repair cement channel has been proven to be a viable alternative to cement squeeze.

Tunu and Tambora gas fields are located in the Mahakam river delta in the province of East Kalimantan, Indonesia. The fields consist of wet gas bearing sand bodies over a height of 13000 ft. The main producing zones are developed by intensive drilling with wells simply completed to allow a bottom up perforation strategy. The main objective is gas production from the deeper Main Zone layers. The shallow reservoirs prone to sand production are not primarily targeted. When sand production after additional perforation is observed, gas production is normally limited to maximum sand free rates or the wells are shut in to avoid damage to surface equipment. Sand consolidation has been used as a sand control method since the 1940’s. However, it had never been attempted in operator’s fields in Indonesia. To author’s knowledge sand consolidation is not commonly used in South East Asia, in general. Unlike widely used conventional sand control methods this alternative method allows production from sand prone reservoirs while maintaining full wellbore access below treated zones. The treatments presented in this paper were to validate sand consolidation as a viable sand control option in operator’s fields in the Mahakam Delta, utilizing new internally catalyzed epoxy consolidation fluid. The treatments were performed with 1.75’’ coil tubing and a packer. To date three Tunu/Tambora wells have been treated. The treated reservoirs have been producing without sand production after treatment. This paper describes candidate selection, job execution and treatment results.

The integrity of sand control method is often compromised as wells get older and the field becomes more mature. An operator in East Malaysia pursued a cost-effective alternative remedial sand-control solution to restore the functionality of its sand control completion and provide unhindered oil production in a well. The well, located offshore Sarawak Malaysia, was a single string oil producer completed in 1987 with gravel pack and screens. It was a producing well for several years until the gravel pack completion failed and the well started to produce excessive sand. The well was beaned down (BD) to achieve an acceptable sand production limit by the operator of below 15 pound per thousand barrels (pptb). The initial remedial sand control measure was to install a thru-tubing screen, hung inside the production tubing. The thru-tubing screen failed to control the formation sand and a second 200 micron thru tubing screen was installed. That screen managed to control the sand production at acceptable levels but induced significant pressure drop, which reduced the oil production from the optimum level of production.Workover (WO) operations would involve pulling the existing completion, and re-gravel packing the zone would be costly. In addition to cost, induced mechanical skin in a gravel pack might not be lower than thru-tubing screen application. Chemical consolidation treatments using solvent-based resins historically have been used successfully as alternatives to remedial sand control, although their application, has typically been limited to short intervals.An aqueous based consolidation resin was developed that provides some advantages compared to conventional solvent based resin systems. The aqueous based resin system uses an internally cured water-based epoxy resin. Unlike the solvent based resin systems, which have a low flash point, the aqueous base consolidation resin system is not flammable. It is safer and less complex operationally. The consolidation-fluid mix can also be foamed for diversion purposes to treat wells with relatively large variations in permeability over longer zones compared to the solvent based resins. This paper describes the treatment background, engineering approach, laboratory testing, fluid design stages, quality assurance/ quality control (QA/QC) procedures, and the treatment execution for the chosen well. The field trial showed no sand was produced after treatment. In fact, the production rate was twice that of the production rate with the thru tubing screen in place. The promising result from this well creates new opportunities for simple, environmentally acceptable, and cost-effective remedial sand-control solutions for the operator.

Field A, an oil field located in Peninsular Malaysia, was completed in 2007 with an initial production of 6,000 BOPD and managed to reach a peak production of 15,000 BOPD the same year, with a water cut of 15%. Toward the end of 2014, a decrease in production was observed with an increase in water cut to 85%. Coupled with high water cut, some of the wells experienced sand production issues. Most of the wells were completed with either standalone screens or without any sand control methods. After a few years in production, the sand-producing wells were shut-in to help prevent damage to surface facilities. Two idle oil wells, Wells 1 and 2, were identified and efforts were made to reactivate them. High costs can be associated with remedial mechanical sand control to work over a well, so a chemical consolidation treatment using solvent-based resin was identified as a less expensive solution for remedial sand control for these wells. Chemical sand consolidation using solvent-based epoxy resin was tested in a laboratory using produced sand samples from the selected wells and showed good results. The chemical consolidation treatments for Wells 1 and 2 were designed based on these results. Before treatment was performed for either well, Well 2 was replaced with Well 3 because of a gas supply shortage, which affected total field production. In October and November 2015, Wells 1 and 3 were intervened and chemical sand consolidation was executed on both wells. After the treatment, Wells 1 and 3 were brought back on production. Sand production for Well 1 was below the threshold limit of 15 pounds per thousand barrels (pptb). However, the performance of Well 3 did not meet expectations. This paper describes the process of treatment design and execution for the chemical sand consolidation of Wells 1 and 3 and explains the workflow used during the design stage. Coiled tubing isolation technique and bullhead treatment technique are discussed together with lessons learned from Wells 1 and 3 in terms of designing chemical sand consolidation treatments for future applications.

Field A is mature hydrocarbon producing field located in east Malaysia discovered in 1963. With multistacked reservoirs more than 7,000 ft high, the reservoirs are predominantly friable and unconsolidated, requiring sand exclusion from the beginning. Most of the wells were completed using internal gravel pack (IGP) methods in the main reservoir. Being an aging producing field, many of the main reservoirs have been depleted and watered out, making the wells inactive. There are, however, several shallower marginal reservoirs, which have been bypassed and undeveloped, known as behind casing opportunity (BCO) reservoirs. The challenge is accessibility to this sand prone reservoir, which might require substantial workover operations, and thus higher costs. Remedial options with proven screen completion can be costly and economically difficult to justify. Mid-2020 marks seven and a half years since the application of a single treatment of epoxy resin in an idle well located in Field A as a remedial approach for BCO. The treatment, proven economically attractive by yielding cost savings of USD 5 million compared to the workover option, further supported by rigorous production monitoring, is unequivocally valuable based on the duration of sustained sand-free production, once again providing reassurance in making this solution a reliable sand-control remedial method for marginal reservoirs. It is important to note that the solution considered a range of laboratory data associated with the chemicals that effectively addressed the requirement based on the characteristics typical of this formation. Well test data from 2013 to 2019 supported sand-free production. Despite experiencing an increment of water cut percentages up to 93.29%, the well is still performing at acceptable production rates. The groundwork processes of candidate identification to the execution of converting the well are described, emphasizing technology comparisons applied in terms of resin fluid system type, execution plan, lessons learned, and best practices developed for maximizing the life of a sand-free producer well.