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Collaborating Authors
Integrating Pressure Data from Formation Tester Tool and DST to Characterize Deepwater Fields, East Kalimantan, Indonesia
MacArthur, Jack (Unocal Indonesia Company) | Vo, D.T. (Unocal Indonesia Company) | Palar, Steve (Unocal Indonesia Company) | Terry, Albert (Unocal Indonesia Company) | Brown, Trevor (Unocal Indonesia Company) | Hariyadi, _ (Unocal Indonesia Company) | May, Ron (Unocal Indonesia Company)
Abstract In the last three years, two significant commercial hydrocarbon accumulations in Indonesia deep waters of the Makassar Strait were discovered. These fields are located approximately 16 miles northeast of the giant Attaka Field in 1400 ft to 3400 ft of water. To date more than 40 exploration and appraisal wells have been drilled in both fields and extensive pressure data has been collected by formation tester tool and drillstem testing tool. The pressure data, used with other data suchas seismic and well logs, has enabled Unocal Indonesia to characterize deepwater turbidite sand reservoirs. In this deepwater environment, DST is used selectively and only with strong justification due to its prohibitive cost. Instead, the use of the pressure testing tool is pushed to its limit in order to gain extensive pressure, rockand fluid properties data, conventionally obtained by DST. This paper will show the experience of Unocal Indonesia to characterize deepwater reservoirs by means of pressure data from the formation tester tool and DST's to complement geological and seismic data interpretations. Reservoir characteristics such as fluid type, fluid contacts, reservoir connectivity and sand geometry can be inferred from the pressure gradients and pressure transients. These data are used in constructing reservoir fluid flow models for field development plan. Introduction Since early 1990's Unocal Indonesia Company has been employing acost-effective philosophy in exploring and developing fields in the continental shelf of the Mahakam Delta, offshore East Kalimantan, Indonesia. Through the drill bits, their operations are specially designed to sufficiently capture reservoir data in a cost-effective way by carefully selecting between "wants" and "needs" while gathering data. Experience gained over the years from drilling to formation evaluation has resulted in the continuing refinement of the tools and techniques involved to implement these programs. As the company pushes their exploration beyond the shelf into the deepwater in this known hydrocarbon province, this cost-effective practice again provides the backbone for exploration in this new frontier. This paper presents a case study that demonstrates the integration of dataderived from different sources to characterize complex hydrocarbon-bearing reservoirs recently discovered in the deepwater of the Makassar Strait, Indonesia. The key to understanding these reservoirs that lead to their approved development plan stems from a cost-effective data acquisition programwith focus on extensive collection of reservoir data from formation tests. The paper describes how this abundant, less-expensive source of data is used together with data from other sources; such as cores, seismic, logs, and drill-stem testing, to characterize complex turbidite sandstone reservoirs. On the basis of this data, reservoir simulation models are constructed to forecast potential oil and gas recoveries and to drive the field development plan. The methodology employed in constructing these models and key reservoir parameters that influence the decision to select a specific plan of development are alsodiscussed. Deepwater Geology in the Makassar Strait In 1996, Unocal Indonesia began its exploration program in Indonesia deepwater in the Makassar Strait, offshore East Kalimantan. Since then, two significant oil and gas accumulations among others have been discovered lyingin the deepwater of this known hydrocarbon province. Located approximately 16 miles ENE of the giant Attaka Field, these new fields are in water depths ranging between 1400 to 3400 (Figure 1).
- Asia > Indonesia > South Sulawesi > Makassar (0.86)
- Asia > Indonesia > East Kalimantan > Makassar Strait (0.54)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Deep Water Marine Environment (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.30)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- (2 more...)
Integrating Pressure Data From Formation Tester Tools and DSTs To Characterize Deepwater Fields, East Kalimantan, Indonesia
MacArthur, Jack (Unocal Indonesia Co.) | Vo, D.T. (Unocal Indonesia Co.) | Palar, Steve (Unocal Indonesia Co.) | Terry, Albert (Unocal Indonesia Co.) | Brown, Trevor (Unocal Indonesia Co.) | Hariyadi, _ (Unocal Indonesia Co.) | May, Ron (Unocal Indonesia Co.)
Summary In the past 3 years, two significant commercial hydrocarbon accumulations in the deep waters of the Makassar Strait, Indonesia, were discovered. These fields are located approximately 16 miles northeast of the giant Attaka field in 1,400 to 3,400 ft of water. To date, more than 40 exploration and appraisal wells have been drilled in both fields, and extensive pressure data have been collected by formation tester tools and drillstem tests (DSTs). The pressure data, used with other data such as seismic and well logs, have enabled us to characterize deepwater turbidite sand reservoirs. In this deepwater environment, DSTs are used selectively and only with strong justification because of their prohibitive cost. Instead, the use of the pressure-testing tool is pushed to its limit to gain extensive data on pressure, rock, and fluid properties conventionally obtained by DSTs. This paper will show how the deepwater reservoirs were characterized by means of pressure data from formation tester tools and DSTs to complement geological and seismic data interpretations. Reservoir characteristics such as fluid type, fluid contacts, reservoir connectivity, and sand geometry can be inferred from the pressure gradients and pressure transients. These data are used in constructing reservoir fluid-flow models for a field-development plan. Introduction Since the early 1990s, Unocal Indonesia Co. has been using a cost-effective philosophy in exploring and developing fields in the continental shelf of the Mahakam delta, offshore East Kalimantan, Indonesia. Through the drill bits, their operations are specially designed to capture reservoir data in a sufficient, cost-effective way by carefully selecting between wants and needs while gathering data. Experience gained over the years from drilling to formation evaluation has resulted in the continuing refinement of the tools and techniques involved in implementing these programs. As the company pushes exploration beyond the shelf into the deep water in this known hydrocarbon province, this cost-effective practice again provides the backbone for exploration. This paper presents a case study that demonstrates the integration of data derived from different sources to characterize complex hydrocarbon-bearing reservoirs recently discovered in the deep water of the Makassar Strait, Indonesia. The key to understanding these reservoirs that led to Unocal'sapproved development plan stems from a cost-effective data-acquisition program that focuses on extensive collection of reservoir data from formation tests. The paper describes how this abundant, less-expensive source of data is used together with data from other sources, such as cores, seismic, logs, and DSTs, to characterize complex turbidite sandstone reservoirs. On the basis of these data, reservoir simulation models are constructed to forecast potential oil and gas recoveries and to drive the field-development plan. The methodology used inconstructing these models and key reservoir parameters that influence the decision to select a specific plan of development are also discussed. Deepwater Geology in the Makassar Strait In 1996, Unocal Indonesia began its exploration program in Indonesia deepwater in the Makassar Strait, offshore East Kalimantan. Since then, two significant oil and gas accumulations, among others, have been discovered lying in the deep water of this known hydrocarbon province. Located approximately 16miles east/northeast of Attaka field, these new fields are in water depths ranging between 1,400 and 3,400 ft (Fig. 1). Hydrocarbon pays are found in the Pliocene and Upper Miocene stacked sandstone reservoirs deposited in the middle to upper slope setting of submarine fan systems extended from the northern Mahakam delta (Fig. 2).Significant pays are also found deposited in the lower-slope, channel-levee, turbidite setting throughout the Miocene. At reservoir depths varying between4,000 and 12,000 ft subsea true vertical depth (ss TVD), hydrocarbon accumulations are trapped structurally and/or stratigraphically by faulting, anticlinal rollover and/or pinchout. The Pliocene sandstones have a dominant stratigraphic trapping component. The channels are well defined, with traps forming where the sandstones pinch out updip into impermeable shales or are sealed by normal faults. The Miocene traps are predominantly structural, with accumulations, for the most part, located in structurally high positions on a large faulted anticlinal feature. Faults in both the Pliocene and Miocene often act as lateral seals. Typical pay thickness ranges from 200 to 400 ft net hydrocarbon pay, with individual sand beds being a few feet to a few tens of feet in thickness, but bundled into reservoir intervals of tens to hundreds of feet thick. Sandstones in the Pliocene and Miocene are quartzitic and predominantly fine-grained. However, sandstones ranging from very fine to coarse-grained have been encountered at different levels across the fields. The grains are normally subrounded to subangular and moderately well sorted. Average porosities range from 24 to 32%, with permeabilities in the 10- to 1,000-md range. Use of Wireline-Conveyed Formation Tester Tools Before the introduction of the Modular Dynamic Tester (MDT**) tool, the traditional Repeat Formation Tester (RFT**) tool was used to obtain pressure data and to identify formation fluid. Although the pressure measurement could be observed in real time, fluid sampling ability was lacking because samples were limited to two per trip and fluid identification could be known only after the tool was retrieved at the surface. This not only hindersreal-time decisions but also can be costly, especially when dealing with multiple pays and high daily rig cost, as in the deepwater environment. To reduce costs, an advanced method of formation pressure and fluid testing had to be used.
- Asia > Indonesia > South Sulawesi > Makassar (0.86)
- Asia > Indonesia > East Kalimantan > Makassar Strait (0.68)
- Phanerozoic > Cenozoic > Neogene > Miocene (1.00)
- Phanerozoic > Cenozoic > Neogene > Pliocene (0.85)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.50)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation (0.88)
- Asia > Indonesia > East Kalimantan > Makassar Strait > Kutei Basin > West Seno Field (0.99)
- Asia > Indonesia > East Kalimantan > Makassar Strait > Kutei Basin > Attaka Field (0.99)
This paper was prepared for presentation at the 1999 SPE Asia Pacific Oil and Gas Conference and Exhibition held in Jakarta, Indonesia, 20โ22 April 1999.
- Geology > Structural Geology > Fault (0.74)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.69)
- Asia > Indonesia > Kalimantan > Sepinggan Field (0.99)
- Asia > Indonesia > East Kalimantan > Kutei Basin > Bengara PSC > Tabul Formation > SS-1 Well (0.99)
- Asia > Indonesia > East Kalimantan > Kutei Basin > Bengara PSC > Meliat Formation > SS-1 Well (0.99)
Comparison between well production performance tests and reservoir simulation predictions based on log data including multicomponent induction measurements in a low-resistivity, electrically anisotropic, laminated shaly sand gas reservoir
Damodaran, Raj M. (Baker Atlas) | Fanini, Otto (B.G. Energy Holdings Ltd.) | Colley, Nick (B.G. Energy Holdings Ltd.) | Mezzatesta, Alberto (Baker Atlas)
Abstract Well production performance tests were performed for a low resistivity, electrically anisotropic, laminated shaly sand gas reservoir. This paper compares such production test results with reservoir well simulation predictions based on log data, which include multicomponent induction measurements of formation resistivity anisotropy. Previously accurate gas well production performance evaluation of low contrast, low resistivity laminated shaly gas sand zones often required the performance of a production well test. A reliable prediction of well production performance through reservoir simulation based on log data has been a challenge. Such a predictive ability is required for optimum completion and field development decisions. The reliability of these simulation predictions has been compromised by the petrophysical limitations of gas-in-place evaluations for thinly bedded, laminated reservoirs. This situation arises whenever traditional scalar saturation equations are applied to conventional resistivity instrumentation data. Traditional laminar shaly sand saturation equations are based on a horizontal parallel conductivity model dominated by the high shale conductivities in vertical wells. These equations typically result in significant underestimates and uncertainties in gas-in-place evaluation in laminated zones. Such equations must be fine-tuned from one well to the next. Formations containing laminated sand-shale sequences and laminated sands of different porosity and/or grain size exhibit macroscopic electrical anisotropy. This formation property provides us with additional information about laminated hydrocarbon-bearing sands. New multicomponent induction logging hardware makes it possible to directly measure the vertical, Rv, and horizontal, Rh, resistivities and the resulting resistivity anisotropy (in the so-called transversely anisotropic media) for vertical, deviated, and horizontal wells. The use of both vertical and horizontal resistivities in petrophysical evaluation provides improved reservoir characterization, leading to better prediction of well production performance using reservoir simulation techniques. A standard suite of logs, including multicomponent induction data, was recorded in a well interval with thick and laminated sands within a gas reservoir. Petrophysical analysis of these laminated zones utilizing resistivity anisotropy has resulted in an approximately 20% increase of estimated gas-in-place over estimation methodologies previously applied to similar gas reservoirs1. Production test flow rates were compared with reservoir simulation predictions. Two interpretation results were considered in generating the simulation model, one incorporating the resistivity anisotropy tensor estimated from multicomponent induction tool measurements, and the other where a conventional, single resistivity interpretation was used. The 3DEX resistivity anisotropy data interpretation has lead to a more accurate shaly sand reservoir characterization of hydrocarbon volume-in-place which, when used with standard reservoir simulation techniques, resulted in better production flow rate prediction results in comparison with actual production well test results. Introduction Can additional log data such as resistivity anisotropy improve well flow prediction in laminated sand-shale sequences? Conventional estimation of fluid saturation in laminated sequences may lead to underestimating hydrocarbon reserves. The presence of laminations with thickness below that of the instrument resolution can result in an observed macroscopic anisotropy as described in Figure 1. Even though the thin, individual sand and shale laminae may be isotropic, the layered sequence of sands and shales exhibit apparent electrical anisotropy at the scale of the logging instrument resolution. Measuring the resistivity anisotropy and incorporating it in a petrophysical evaluation provides improved evaluation of thinly bedded reservoirs, leading to a considerable improvement in reservoir simulation predictions for well performance tests. This in turn provides support for the petrophysical evaluation results.
- Asia (1.00)
- North America > United States > Texas (0.94)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Oceania > Australia > South Australia > Cooper Basin (0.99)
- Oceania > Australia > Queensland > Cooper Basin (0.99)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- (2 more...)
Overcoming Differences between Log and Test Results: A Case-Study of Three Appraisal Wells Drilled into Low Contrast Low Resistivity Carbonate Reservoir
Daungkaew, Saifon (Schlumberger) | Karpekin, Yevgeniy (Schlumberger) | Pokhriyal, Krishna (Schlumberger) | Herianto, Bambang (Schlumberger) | Duangprasert, Tanabordee (Schlumberger) | Thanh, Tung Huynh (Schlumberger) | Rahman, Rasheed (Schlumberger) | Yogapurana, Erik (PETRONAS Carigali Sdn. Bhd.) | Nasifi, Wahyudin Bahri (PETRONAS Carigali Sdn. Bhd.) | Bt. M. Razman, Nur Faradilla (PETRONAS Carigali Sdn. Bhd.) | Bin M Fadhil, M Imran (PETRONAS Carigali Sdn. Bhd.)
Abstract In three appraisal wells that targeted carbonate reservoirs, formation evaluation was performed with conventional triple combo, borehole image, nuclear magnetic resonance logs, and Wireline Formation Tester (WFT). Several zones with hydrocarbon shows were identified, but the level of saturation was found too low to promise oil flow. Downhole testing tool was used as a primary mean to confirm hydrocarbon presence by evaluating pressure gradients and direct interval testing. In the second well, downhole fluid scanning confirmed water flow in most of the permeable intervals, but in several intervals low permeability limited extended testing time where fluid ID was not conclusive in differentiating mud filtrate from formation water. Subsequently DST was conducted in three intervals of well-2 based on identified potential oil zones from the logs and information gathered in the first well. Testing confirmed water in two zones, however the third, relatively thin zone tested oil. Standard quick-look saturation interpretation gave low oil saturation and significant volume of free water in the oil-tested zone what contradicted the DST result. As the field goes into the development stage, the need to overcome limitations of the conventional evaluation methods demanded further refinement of evaluation program and log interpretation techniques for Low Contrast carbonate formation. Further analysis of image and magnetic-resonance logs indicated different rock fabric across the three tested zones, with pore geometry ranging from vugular to interparticle type. The oil-tested zone was found to have higher irreducible water saturation and higher clay content than other two zones. A non-conventional saturation equation based on the connectivity theory was applied with in-situ clay conductivity calibration. The new saturation matched better NMR irreducible water saturation, and the overall evaluation became conformant to the DST results in all three zones. In the last well, anticipating presence of thin reservoirs with low permeability, the evaluation program was modified to include downhole testing tool with a new probe type that suits better tight formations and that permits faster clean-out and sampling of formation fluid. With its help, a thin rim of oil was discovered below the gas cap, fluid contacts were accurately delineated with in-situ fluid density measurements. This paper aims to show the learning curve in data acquisition and interpretation during the exploration drilling campaign, where measurements and evaluation methods were optimized to overcome formation evaluation challenges, to identify all hydrocarbon accumulations, and to provide accurate assessment of the reserves.
- North America > United States (0.68)
- Asia > Indonesia (0.46)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.93)
- Geology > Geological Subdiscipline (0.93)
- Geology > Mineral (0.69)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.34)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- (2 more...)