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.
Many oil and gas fields have long been suffering from sand production due to either the absence or failure of primary well sand control. To avoid mobilizing costly work-over rig to pull out the tubing, operators have tried various thru-tubing remedial sand control. The well's condition such as sands accumulation and space constraints due to small inner diameter of tubing always make this remedial job challenging. It is not surprising that the results are not all satisfactory. Among the industry-recognized remedial sand control, Stand Alone Screen (SAS) is the simplest and the cheapest method. Many SAS have been installed but most were failed with screen erosion as the main failure mechanism. Flowing high velocity fluid with sands wears out the screen fast making it impossible for the sands to bridge and to create formation sand pack around the screen. Ceramic Sand Screen (CSS) technology which was recently introduced to the industry aims to address this erosion issue. Having more than ten times hardness of stainless steel, sintered silicon carbide ceramic material in CSS offers superior resistance to wear. The pilot was conducted by installing CSS in three (3) selected wells with sand production history. While waiting for acoustic sand monitoring installation, the wells were put on production with the same choke size and regular manual samplings were conducted to monitor the sand production. The acoustic sand monitoring campaign began in November 2017. Sands production was carefully monitored during the process to determine the final choke size at which the wells would continuously produce. In the middle of the campaign due to adverse weather conditions, all non-essential personnel had to be abruptly demobilised from the field leaving acoustic sensors hooked-up to the respective flow line. This gave opportunity to have unplanned extended sand monitoring window. Loss of Primary Containment (LOPCs) occurred in two CSS wells not long after that. In one the choke body was heavily eroded and the other well had a punched hole at the first elbow of the flowline. These incidents prompted full investigation to be conducted. This included pulling out the installed CSS and performed tear down analysis. Acoustic sand monitoring that just happened to be available in one of the wells proved to be critical in understanding the CSS failure. The paper presents briefly on the CSS pilot project, the chronology of events until the incident, sands production trend from the acoustic sand monitoring. Using all available information, the paper provides details analysis on CSS failure mechanism.
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.
High water production in a gas well could significantly reduce gas production due to high friction losses in the tubing, the effect of water blocking in front of perforations and formation damage due to water, which, eventually, could lead to a significant loss of recoverable reserves. Selective mechanical water shut-off , (i.e. casing patch), the main technique used to solve this problem so far, has some disadvantages, mainly reducing the inside diameter of the production tubing which makes future mechanical water shut-off of the deeper reservoirs more difficult. Chemical water shut-off is the preferred solution to this problem.Peciko is a giant multilayer gas field located in the Mahakam delta of East Kalimantan, with water depths of around 30 -40 meters. There are more than 100 reservoirs per well, with average thicknesses of less than 1 m. Most of these reservoirs were perforated and produced commingled throughout the lifetime of a well. Efficient water shut-off is very critical when water breakthrough occurs at some of these reservoirs, in order to optimize gas production from the other reservoirs. Production logging measurements are used to identify the water producing reservoir to be isolated. This paper presents a successful field application of chemical water shut-off at Peciko field. In this application, the chemical water shut-off is the unique solution due to the thickness of the reservoir to be isolated (>8 m), not feasible using current mechanical techniques, and the interest of keeping a full bore access to allow future mechanical water shut-off for the other deeper reservoirs, while isolating the water source located above. Sealing quality at the isolated water zone was confirmed by a production logging job performed after the chemical water shut-off operation. This successful chemical water shut-off reduced the water production rate from 4,000 bwpd to less than 100 bwpd, and allowed an instantaneous gas production gain of 10 MMscfd with an estimated cumulative gain of 10 Bscf in 3 years. TX 75083-3836, U.S.A., fax +1-972-952-9435.
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