Proppant hydraulic fracturing has been a successful stimulation method used to enhance production in sandstone reservoirs. But for fracturing carbonate formations, the possibility of the existence of natural fractures and the hardness of the rock can be challenging. This paper will elaborate on a carbonate-fracturing pilot project in Soka field, which is the leading carbonate proppant hydraulic fracturing project in Indonesia. Platform carbonate limestone from the Baturaja formation is the major component of Soka field reservoir. The platform consists of limestone with infiltrate mudstone/packstone and chalky limestone with poor porosity. The limestone mudstone/packstone lithology is dominated by mud, clay, and fine silt carbonates which results in the limestone becoming dirty and causes the low acid-solubility value of limestone in the field. Stimulation jobs were performed in two wells in Soka field. From log analysis, the carbonate formation in both wells shows a high shale content (20%) and low permeability (6 md). Acid-solubility tests performed on both well cores showed low acid solubility. Matrix acidizing was performed in both wells, but they still showed low influx. Well A, after being perforated and matrix-acidized, only produced 40 BFPD, with a 30% water cut and a high GLR 19,061 scf/STB. Well B, after being perforated and matrix-acidized twice, had very low influx from reservoir to wellbore. Proppant hydraulic-fracturing stimulation was performed in both wells using hydocarbon-based frac fluid and 12/18-mesh ceramic proppant. After being hydraulically fractured, Well A produced 165 BFPD at 18/64 inch choke, with 60% water cut and a GLR of 700 scf/STB, while Well B produced 173 BFPD at 25/64 inch choke, with a 0% water cut and a low gas rate. Production from both of these wells is maintained at the reservoir critical rate for each well.

Many techniques have been used to model, diagnose and detect fracture dimension and propagation during hydraulic fracturing. Diagnosing fracture dimension growth vs time is of paramount importance to reach the desired geometry to maximize hydrocarbon production potential and prevent contacting undesired fluid zones. The study presented here describes a technique implemented to control vertical fracture growth in a tight sandstone formation being stimulated near a water zone. This gas well was completed vertically as openhole with Multi- Stage Fracturing (MSF). Pre-Fracturing diagnostic tests in combination with high-resolution temperature logs provided evidence of vertical fracture height growth downward toward water zone. Pre-fracturing flowback indicated water presence that was confirmed by lab test. Several actions were taken to mitigate fracture vertical growth during the placement of main treatment. An artificial barrier with proppant was placed in the lower zone of the reservoir before main fracturing execution. The rate and viscosity of fracturing fluids were also adjusted to control the net pressure aiming to enhance fracture length into the reservoir. The redesigned proppant fracturing job was placed into the formation as planned. Production results showed the effectiveness of the artificial lower barrier placed to prevent fracture vertical growth down into the water zone. Noise log consists of Sonic Noise Log (SNL) and High Precision Temperature (HPT) was performed. The log analysis indicated that two major fractures were initiated away from water-bearing zone with minimum water production. Additionally, in- situ minimum stress profile indicated no enough contrast between layers to help confine fracture into the targeted reservoir. Commercial gas production was achieved after applying this stimulation technique while keeping water production rate controlled within the desired range. The approach described in this paper to optimize gas production in tight formation with nearby water contact during hydraulic fracturing treatments has been applied with a significant improvement in well production. This will serve as reference for future intervention under same challenging completion conditions.

Multizone single-trip gravel-pack (MZ-STGP) completion systems not only save rig time to complete wells with long multilayer intervals but can significantly reduce capital and operational expenditures by standardizing completion design and simplifying operation complexity. It can also help improve quality, health, safety, and environment (QHSE) performance for a long-term project development. This paper discusses a case history of an operator in Indonesia developing a major offshore field primarily with MZ-STGP completion systems to produce marginal reservoirs. A MZ-STGP system was selected to reduce multizone gravel-packing operation time as compared to conventional stacked-pack systems. The main focus was to standardize completion design and help improve system reliability and operational efficiency, which is associated with both logistic preparation and field execution. Despite exploring cost-effective solutions, operational safety—including well control, particularly for developing a shallow-gas field—was the number one priority, as usual. A new concept type of safe running system was developed and implemented as part of a field operation standard to help ensure a safe and efficient operation. Based on MZ-STGP system trial results and lessons learned during the early stage, a standard MZ-STGP completion instruction was approved and applied as a guideline to standardize completion operation and identify and mitigate potential operational risks quickly to improve safety, performance, and efficiency. By understanding the principle of MZ-STGP system limitations, the system-working envelope was expanded and refined without jeopardizing system reliability and performance. With more than 170 wells with MZ-STGP installation and more than 650 zones gravel packed in a 12-year time span, a case history review provides an opportunity to share lessons learned and fundamental success factors and explore the future of this technology.

Shallow gas development in Tunu field, East Kalimantan, Indonesia requires cost effective solution to safely produce multi layered sand prone reservoirs while maintaining low completion cost. Gravel pack solution has been deployed since 2006 and it enables producing small layers with multi zone single trip gravel pack system. However the system reaches its technical limits in term of cost, number of completed zones and well deviation. Developing alternative sand control solution is required to produce small marginal reservoirs and maximize recovery while maintaining robust sand control. Ceramic screen is considered as emerging alternative solution to cut sand control cost for marginal reservoirs. Ceramic material provides far superior erosion resistant compared to standard metallic screen. The paper will present the design of ceramic screen for cased hole Stand Alone Screen (SAS), its deployment in three Tunu wells and the production result from the completed reservoirs.

Tunu is a giant gas field located in Delta Mahakam, East Kalimantan, Indonesia operated by Total E&P Indonesie. The field development targets two domains: Tunu Shallow Zone (TSZ) and Tunu Main Zone (TMZ). The primary objective of TSZ completion is to have a cost effective sand control methodology to ensure economic vialibility of the wells since TSZ consist of small elliptical shaped deltaic sand bodies containing low reserve gas pockets with a typically short production life. Multi zone single trip gravel pack (MZ-STGP) systems have been utilized as sand control completion methodology. Technical limitations of these techniques in terms of zone spacing, number of zones and well deviations drove the need developping an alternative completion technique. Using short screen assembly and open-hole isolation technology, a unique multi zone open hole stand alone screen (MZ- SAS) system was developed. The initial development consists of 14 wells. Both low and high angle deviated wells, numbers of different completion jewelries and different type of reservoir drill-in fluids (RDIF) have been used over the initial phase of the development. The objective of this paper is to review the evolution and improvements in the drilling, fluid, completion and specific post well completion strategy. This has provided a best practice for future completions in the development of similar reservoirs in the portfolio.