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.
Post-fracture proppant flowback has been an unwanted result of high-pressure/high-temperature hard-rock fracturing in the Mahakam river delta for a number of years, causing abundant production-related issues coupled with additional operational risks for the operator. Previous attempts to reduce proppant flowback with resin-coated proppant (RCP) have proven to be both unsuccessful and expensive due to the brittle nature of the hardened RCP and the extended cleanout periods associated with post-job fracture cleanout using RCP in the swamp environment, leading the operator to search for an alternative solution. In early 2012, the service company implemented a new proppant flowback control service for mid- to high-temperature wells. This service has been applied to the high-pressure/high-temperature fracturing campaign in the Mahakam delta with excellent results. The service consists of a resin-coated fiber additive coupled with technical support software for design and optimization purposes. The service was pioneered on four hydraulically fractured wells throughout 2012 and 2013. From the four wells currently treated with the new proppant flowback control service, a total of 180 lbm of proppant has been recorded at surface production facilities. All of this proppant is known to be from well A (approximately 0.18% of total proppant placed during fracture treatment). Wells B, C, and D have all recorded zero proppant returned to date. None of the four wells shows any indication of perforation burial from proppant, and there has been no decline in production that can be attributed to proppant flowback. Introduction Over the last 30 years, an operator has been developing several fields in the Mahakam river delta, in the province of East Kalimantan, Borneo, Indonesia (Fig. 1). The fields comprise a series of interbedded deltaic sandstones, shales, coals, and, locally, limestones, with gas-bearing sand bodies, typically with a total vertical depth of less than 12,000 ft. The majority of the wells are multizone gas producers completed with cemented tubing that are perforated and produced using a bottom-up strategy. Hydraulic fracturing operations are currently performed in two separate fields within the Mahakam delta. The fracture targets in both cases are medium- to low-permeability gas reservoirs in hard-rock formations. In this case, this is defined as reservoirs with ~1.0 mD permeability and lower and a Young's modulus of >4.0 Mpsi. The fracturing fluid utilized is a high-temperature organo-metallic crosslinked system with high-strength ceramic proppant that is used because of the reservoir and stress environment in the region. The operator has endured proppant flowback following hydraulic fracturing in both fields. In some cases, this proppant flowback caused considerable production loss with production meeting only 20% of the full potential of the well. This is due to restrictive well choking after proppant detection, as seen in the Fig. 2 for well Z. There have been cases of both perforation burial, leading to well shut-in for cleanout and proppant production at surface. The potential of further lost production and extensive damage to surface necessitated a permanent solution to proppant flowback in the Mahakam delta.
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. Most of the wells are multizone gas producers completed with cemented tubing without primary sand control, and are produced with a bottom-up perforation strategy. The main objective is gas production from the deeper Main Zone layers. The shallower reservoirs prone to sand production were not targeted until recent years. With progressing depletion of deep reservoirs in the Main Zone and bottom up perforation strategy the operator started perforating upper zones. This resulted in an increasing number of interventions or shutting wells in due to sand production. Due to this fact the operator started considering remedial sand consolidation about 5 years ago. The first successful trials using internally catalysed epoxy resin fluid were prepared in late 2008 and results presented at the 2010 SPE International Symposium and Exhibition on Formation Damage Control (Chaloupka et al. 2010). Initially, these consolidation treatments aimed to find a remedial solution for existing wells choked back or shut in due to sand production. These successful trials, however, quickly turned the project into using consolidation essentially as a primary sand control method. First treatments targeted weakly consolidated sands in both Tunu and Tambora fields (5,000 to 8,000 ftTVD) using high temperature internally catalysed epoxy consolidation fluid. The treatments showed encouraging results and confirmed this as a viable option for sand control. In 2010 with growing confidence in the method the operator considered performing sand consolidation in very shallow fully unconsolidated Tunu Shallow zones (2,300 to 5,000 ftTVD) as an alternative to standard single trip multi-zone gravel packs which are conventionally pumped in Tunu Shallow. Five treatments have been performed using a low temperature version of the consolidation fluid with encouraging results. The preliminary performance envelope validated from the treatment is 3 MMscfd of gas per meter perforated or a drawdown of 300 psi. The paper aims to describe the experience from the initial trials to field application including placement and fluid QAQC procedures as well as treatment results. The failures and difficulties that have been encountered are looked at in more details.
Multizone Single Trip Gravel Pack (MZ-STGP) completion has been the mainstay in Mahakam River Delta and North Java Sea in Indonesia since 2007. The system has been used as a sand control solution for its cost efficiency, the ability to complete multiple sands in a single trip and to provide zonal isolation for production selectivity. Initial completions have used the 9 5/8” system offering large bore and pumping capacity required for deeper zone gravel packing. Additional requirements has driven the need for a use of a smaller system under various scenarios such as cases where 9 5/8” casing cannot reach planned depth, retrofitting gravel pack in existing wells or completing unexpected additional reserves below 9 5/8” casing shoe. The paper reviews successful history of a 7” MZ-STGP system including its first worldwide installation in 2009. Introduction of the new system has been very smooth including another world's first combined 7” and 9 5/8” multizone gravel pack completion. The paper presents application concerns when considering multizone systems, as well as lessons learnt from the presented cases. To date, eight wells have been completed successfully using this slimmer system within expected time frame confirming rig time reduction of 8-10 days per well compared to stacked gravel packs. Not only has the 7” MZ-STGP proven to reduce costs for operators, but it has also permited significant flexibility in drilling and completion operations. The system is now considered as a standard contingency for many operators in cases where a 9 5/8” shoe must be set higher than planned or when openhole completion cannot be run inside of an 8 1/2” open hole.
A major operator manages multiple deep water projects in the Gulf of Guinea. This paper describes the latest 44-well project in Nigeria. The operator required an ISO 28781 qualified bi-directional subsurface isolation barrier valve (IBV) (Fig. 1) to be installed in each well. This work presents results of IBV deployment in the field. The wells were drilled and completed from sixth generation drillships. To comply with the operator's dual barrier policy, a bi-directional IBV was installed in each well to help ensure reservoir isolation for temporary well suspension or before running upper completion and tree installation. Careful attention to well fluid cleanliness, sound quality assurance/quality control (QA/QC), and operational procedures were considered paramount to successful remote opening of the IBVs and were identified as best practices by both parties. The IBV is run in the open position as an integral part of the lower completion. A collet shifting tool closes the ball isolating the formation, enabling inflow and positive pressure testing to be performed. The reservoirs are isolated by the closed ball in the IBV, allowing safe installation of the upper completion from a floating rig or well suspension without a subsea tree. The use of an ISO 28781 Type CC V1 qualified IBV provides both zonal isolation and fluid-loss control. Once a well is completed and the subsea tree installed, the IBV is remotely functioned to the open position by applying multiple tubing pressure cycles. The first batch of wells were drilled and completed with lower completions and suspended while waiting for subsea tree deliveries. Later, wells were drilled and completed with both lower and upper completions, and trees were installed later from an offshore inspection maintenance and repair (OIMR) vessel. IBVs were successfully closed and inflow and pressure tested during the lower completion phase. IBVs are run in sieved non-aqueous based mud (NABM). Filtered high viscosity pills are spotted across the IBV before closing. Once closed, the casing above the IBV is displaced to filtered completion brine at a rate ensuring any debris is lifted to the surface. The wells remain suspended with IBVs closed until the operator performs flowback and injectivity testing from a drillship. Additional injectivity testing was also performed from an OIMR vessel. Well suspension duration with IBVs closed varied between two months and 2.5 years. All valves cycled opened without issues. Four coiled tubing (CT) interventions were performed in the field, passing through the open ball without issue, confirming the IBVs were in the fully open position. This paper describes full QA/QC and operational procedures, which led to successful deployment and excellent functionality of the IBVs.
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