Arisandy, Mellinda (PETRONAS Carigali Indonesia Operations) | Mazied, Miftah (PETRONAS Carigali Indonesia Operations) | Putra, Bayu P (PETRONAS Carigali Indonesia Operations) | Yogapurana, Erik (PETRONAS Carigali Indonesia Operations) | B Mohd Idris, Jamin Jamil (PETRONAS Carigali Indonesia Operations) | Darmawan, Hendra I. (PETRONAS Carigali Kuala Lumpur)
This paper describes geochemistry analysis, hydrocarbon charge and entrapment model for prolific "MA" Block in the West Natuna Basin. Even though the area is currently at a mature exploration stage, the behaviour of hydrocarbon distribution in the area is still poorly understood and the link between discovered hydrocarbon and possible kitchens is still unknown. This study is an attempt to understand hydrocarbon expulsion, charging and entrapment in "MA" Block to de-risk further exploration efforts.
Several localized inverted half-grabens were identified through seismic interpretation. Nearby wells were then selected in evaluating source rock quality and maturity. In order to determine hydrocarbon expulsion model, 1D-3D burial history and thermal maturity models were constructed using integration of source rock and fluids geochemistry, temperature, seismic, and well data. Hydrocarbon charge and entrapment models were then simulated using 3D basin modeling software and calibrated with existing proven accumulation to produce a risked understanding of hydrocarbon distribution in the study area.
This study suggests that the most possible source rocks are the Late Eocene and Oligocene shales of Lama Formation and Lower Gabus Formations. Both source rocks are indicated by type I & type III kerogen. Lama source rock was confined in the initial grabens and post mature in deep paleo-grabens. This study confirmed that charging is derived from four (4) kitchen areas: Anoa, Gajah, Kakap, and Kambing grabens. The oil samples from "MA" Block indicated lacustrine facies. Rock geochemistry analysis portrayed oil-prone and gas-prone source rock.
In general, hydrocarbon was migrated from the southeastern area (Kambing graben) and southwestern area (Gajah graben). Hydrocarbon was later on accumulated in the nearest structural entrapments (anticlines). In the deep grabens (Kakap and Kambing), the hydrocarbon expulsion was starting as early as 37 Ma and 31 Ma, respectively, while in shallow graben (Anoa) the expulsion was starting at 29 Ma. The earliest structural trap commenced at 21 Ma, aligned with the initial compressional regime that was affecting the West Natuna Basin. Notable accumulative erosion in Miocene was nearly 1000 m at inverted structures, by which partly removed regional seal and reduced reservoir effectiveness. Significant yet-to-find hydrocarbon is predicted to be concentrated in the Anoa, Kakap, and Northeast Kambing area.
Major Hazard Management (MHM) of high risk production installation is achieved by oil and gas operators by complying with applicable regulations and adopting various practical and innovative risk management techniques. The learning from offshore and onshore disasters is bringing new levels of best safety practice into the industry. Premier oil has developed a MHM programme for its global asset, which is successfully implemented in South East Asia.
Premier Oil approach for existing facilities (Anoa Field platform complex and FPSO) comprises the following elements:
Premier Oil intends to extend this approach to its new development in South East Asia i.e. Gajah Baru in Indonesia and Chim Sao in Vietnam.
In the summer of 2000, Conoco began a program to develop a series of shallow, low-pressure gas reservoirs in the Indonesian waters of the West Natuna Sea. The project consists of a series of subsea wells linked by pipeline to a central mobile gas processing and compression unit which feeds a sales line to Singapore. Overall project life is 20 years and will require development of 8 small fields with reserves of the order of 1 TSCF gas.
Initial project planning used conventional well designs to deliver rates of the order of 20 MMSCFD/well from a number of gas reservoirs. This type of well productivity required 10 wells to meet Conoco Indonesia's maximum contract supply rate with several wells allocated to each reservoir. To improve project economics, a reduced well count employing high performance completion designs was developed. The high performance completions were designed to provide flow rates of the order of 100 MMSCFD at initial reservoir pressures ranging from 1250 psi to 1900 psi. These flow rates allowed well counts to be reduced to one well per reservoir.
This paper will review Conoco's methodology for design and implementation of the first 4 high performance completions in the West Natuna Sea Gas Project. Well deliverability and initial project results will be discussed.
Conoco, through its Indonesian subsidiary Conoco Indonesia Inc. (CII), has explored the Indonesian waters of the West Natuna Sea for over 30 years. As shown in Figure-1, Conoco's West Natuna Sea Production Sharing Contract (PSC) Area is located approximately 200 miles north/northeast of Singapore near the Indonesian/Malaysian border. During its period of operation the Company has discovered and developed several significant oil fields in the Block-B Production Sharing Contract Area as shown in Figure-2. The Company has also discovered a number of gas fields in the Block-B PSC Area, however, the lack of a local gas market and gas pipeline system has prevented effective development of these fields. Similarly, associated gas produced with oilfield crude has not been economically transported and sold and as a result produced gas volumes in excess of fuel requirements have been flared. As shown in Figure-3, Conoco's gas discoveries and associated gas resources in Block-B have been effectively stranded by lack of a gas pipeline system and local gas market. Adjacent PSC operators have also experienced these types of problems and have suffered significant stranded gas volumes.
In the late-1990s Conoco worked with the Indonesian State Oil Company, Pertamina, and adjacent PSC operators Gulf Canada and Premier Oil to establish a 20-year gas supply contract with Singapore and a gas pipeline from the Indonesian West Natuna Sea to Singapore. An overview of the pipeline system and the various PSC areas is shown in Figure-4. Under the terms of the gas supply contract, the three PSC operators agreed to supply approximately 2.5 TSCF of gas at an average rate of 325 MMSCFD for a long-term electrical power generation project. Each operator is responsible for developing gas fields or associated gas in its own PSC area to meet its share of the total production requirement. Each operator's gas is then metered and flowed to the jointly owned and operated West Natuna Gas Transportation System for transport to Singapore and sale to the purchaser.
This paper describes a case history of an innovative completion design and performance evaluation of a high-productivity subsea gas well in Conoco's Tembang field in the West Natuna Sea. Several completion challenges were overcome to ensure a high-deliverability completion in a thick, highly-laminated, loosely consolidated sandstone interval. The need for reliable high flowrates, high inflow area and effective sand control were the driving factors in the completion design and hardware selection. In addition, expected high fluid loss rates and gas migration were other factors affecting the design of this completion from a semi-submersible rig. A single-trip perforating and packing system was utilized to minimize fluid loss and formation damage during the completion operations. A fracpack was designed to optimize the connectivity between the multiple sand layers in conjunction with alternate path technology which provided the best option for sand placement and reducing the risk of a pre-mature screen-out in the long and highly deviated interval (322 ft MD at 50° inclination).
Evaluation of both pre-fracpack and post-fracpack reservoir and well performance results were performed. The use of a pre-fracpack surge, limited influx, and an injectivity test were chosen due to well control concerns related to completing and flow testing the well with a single-trip perforating and packing system from a semi-submersible rig. Post-fracpack flow testing to the rig immediately after the completion and subsequent production tests were evaluated to determine the well performance with time and effectiveness of the completion technique. These results, along with observations and challenges from the completion operations of the Tembang 4 well, are provided in this paper.
The Tembang gas field is located in the Indonesian waters of the West Natuna Sea (WNS), approximately 200 miles northeast of Singapore. Field location is shown in Figures 1 and 2. The field is being developed as part of the West Natuna Sea Gas Project in water depths less than 300 ft. This 20-year project consists of development of multiple fields and a pipeline network to supply gas from Indonesia to Singapore as discussed in reference 1. The overall project consists of a 28 inch pipeline from Singapore to a series of three Indonesian Production Sharing Contract (PSC) areas operated independently by Conoco, Gulf Canada and Premier Oil Company as shown in Figure 3. Although PSC operator has contributed to pipeline construction and overall sales commitments, each operator is responsible for developing its own gas reserves.
Within the Conoco operated PSC area, Block B, a number of small gas fields have been dedicated to the WNS Gas project and sales contracts to Singapore. The Tembang field is one of several fields that has been developed in phase 1 of the overall West Natuna Sea Gas Project to supply gas to Singapore. Due to its small size, the Tembang field is being developed with a limited number of wells. Each of the field's two reservoirs will be developed with a single subsea well which will be flowed back to a mobile gas processing unit, Hang Tuah, located approximately 8 km away as shown in Figure 4.
This paper concerns completion of the Tembang-4 well in the Tembang Zone-4 reservoir. The Zone-4 reservoir is located at approximately 4130 ft TVDSS and is comprised of multiple sand lobes separated by shales. A type log is provided in Figure-5. Reservoir pressure is approximately 1874 psia and temperature is 205 degrees Fahrenheit. The reservoir contains predominantly methane gas with a specific gravity of 0.64 with approximately 1 mol% CO2.
No preview is available for this paper.
Single Point Mooring Systems are commonly used to moor Floating Production tankers or barges at exposed offshore locations. The first mooring systems were designed for permanent applications. In the last five permanent applications. In the last five years, disconnectable systems have been developed mainly for South East Asia.
These disconnectable systems have been designed around the turret mooring concept, due to their mechanical simplicity and cost attractiveness.
The turret systems have been developed for a wide range of criteria such as environmental conditions, water depth and operating constraints.
After a brief review of different turret mooring systems, this paper discusses the concept of disconnectability. Some mooring systems have been designed to be disconnected in an event where the design weather conditions are reached or in case of typhoon or cyclone warnings.
A comparison of disconnectable versus permanent mooring systems is presented with permanent mooring systems is presented with regards to mooring feasibility, safety of personnel, equipment availability, operating personnel, equipment availability, operating philosophy, downtime, investment cost as well philosophy, downtime, investment cost as well as operating costs.
The use of Floating Production, Storage and offloading systems (FPSO) based on tanker or barge shaped units for developing offshore reservoirs is growing; in the early stages of FPSO's use, these concepts were mainly related to small marginal fields. The attractiveness of these concepts is primarily due to their cost when compared to more conventional solutions as for example fixed platforms. The growing interest for these platforms. The growing interest for these units is due to the fact that these systems may be used in deep waters as well as in very harsh environments, and the most recent developments based on FPSO's have been executed for fields which are not considered any more as marginal.
The majority of these tanker based developments are using Single Point Moorings (SPM), allowing the tanker or the barge to "weathervane" or to have the best heading in the wind, waves and current, leading to the minimum resistance against environmental loadings.
A large variety of SPM's have been developed and used, but all are based on buoyancy or catenary principles; due to different reasons including technological development of flexible risers and redundancy in terms of risk analysis, the present trend is to move towards the use of catenary based systems. This has led to the development of the so-called Turret systems. In this family of mooring systems, two main categories have been developed: in the first one, the tanker is permanently moored to the sea bed and as a consequence the mooring system is typically designed to resist and to survive the 100 years occurrence environmental conditions. As a consequence these permanent mooring systems may be very large in order to survive extreme weather conditions.