Mini-DST Applications for Shell Deepwater Malaysia
Abstract: fax 01-972-952-9435. AbstractExploration and appraisal campaigns for deepwater environments are a continuous challenge in today's operations. Data acquisition in such environments requires reservoir information of the highest quality before expensive development plans can be put in place. New technology, real time monitoring and integrated reservoir data are essential to understand such reservoirs. Another challenge presented by thinly bedded reservoirs is the presence of vertical heterogeneity and varying lay… Show more
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Cited by 7 publications
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Deepwater turbidite reservoirs are composed of interbedded porous and permeable sands with variable proportions of thin silt and clay beds. These reservoir sands vary in thickness from millimeter to meters in thickness. The reservoirs are highly permeable, but the silt and clay laminations affect the reservoir permeability in each layer, resulting in changes in the well productivity and sweep properties. We illustrate the applications of NMR, borehole images and wireline formation testing technology in oil-base mud to evaluating the lithology, the geometry, and the net producible fraction of these reservoirs: We demonstrate that the partitioning of NMR T2 distribution is a robust method for calculating independent volumes of clay, silt and sand. We present the experimental set-up and the application of a novel method to calculate the thin sand fraction of a laminated reservoir from NMR free fluid volume. The results of this method are compared to the sand counts from a high resolution borehole image and from core images. This comparison reveals the effect of the lamination geometry on the formation evaluation. We illustrate the effects of thin silt and clay laminations on wireline formation tests, and on the productivity and flow profile of a production test. The dynamic reservoir information obtained from these measurements enables to understand the fluid flow behaviour and potential productivity in such a reservoir. These techniques reduce the uncertainty of hydrocarbon volume and productivity computations in a highly laminated deepwater reservoir. The field example used in this paper is a turbidite sand from North West Borneo. The techniques demonstrated here are also applicable to the analysis of other categories of thinly bedded, shaly sand reservoirs. Introduction Recent advances in NMR technology and signal processing have focused on measuring reservoir fluids volumes and properties in-situ and on identifying reserves in thinly laminated reservoirs, thereby extending the range of NMR applications beyond the volumetric estimates of moveable fluids. Care must be taken to ensure that productive sand units are not discounted by formation evaluation in volumetric estimates of deepwater siliciclastic depositional settings with largely laminated succession of rock layers of varying thicknesses. This issue is becoming increasingly important in Miocene turbidite fans of the North Western Sabah province of Borneo, where many wells logs indicate sequences dominated by thinly laminated layers with low resistivity contrast between sand and shale layers. These beds are often too thin to be properly resolved with conventional logging tools. The acquisition of new technology logging services, such as tri-axial resistivity, high resolution oil-base borehole images and nuclear magnetic resonance (NMR) logs, as well as acquiring rotary and fullbore cores has increased over recent years. New logging techniques and interpretation methods have been applied to improve the evaluation of these thin-bedded reservoirs. This paper highlights efforts placed on the use of NMR logging to delineate reservoir properties to a finer resolution than convention tools. In addition, the use of images and wireline formation testing from the example well, provides the appropriate benchmark for improving estimation of net producible sand thickness in thinly bedded reservoirs. Passey et al. (Ref. 1) define petrophysical thin beds as contiguous units of rocks with thicknesses between 1 in. (2.5 cm) and 2ft (61 cm), that exhibit a narrow distribution of petrophysical properties, but are bounded above and below by other units with significantly different petrophysical properties. These 2 limits represent the currently accepted limits of logging technology: 2 ft is the vertical resolution of a conventional logging tool, and 1 in. is the minimum bed thickness resolved by a borehole imager. (The vertical resolution of modern logging technology actually reaches 1 ft [30.5 cm] for logs, and 0.4 in. [1 cm] for borehole images.)
Deepwater turbidite reservoirs are composed of interbedded porous and permeable sands with variable proportions of thin silt and clay beds. These reservoir sands vary in thickness from millimeter to meters in thickness. The reservoirs are highly permeable, but the silt and clay laminations affect the reservoir permeability in each layer, resulting in changes in the well productivity and sweep properties. We illustrate the applications of NMR, borehole images and wireline formation testing technology in oil-base mud to evaluating the lithology, the geometry, and the net producible fraction of these reservoirs: We demonstrate that the partitioning of NMR T2 distribution is a robust method for calculating independent volumes of clay, silt and sand. We present the experimental set-up and the application of a novel method to calculate the thin sand fraction of a laminated reservoir from NMR free fluid volume. The results of this method are compared to the sand counts from a high resolution borehole image and from core images. This comparison reveals the effect of the lamination geometry on the formation evaluation. We illustrate the effects of thin silt and clay laminations on wireline formation tests, and on the productivity and flow profile of a production test. The dynamic reservoir information obtained from these measurements enables to understand the fluid flow behaviour and potential productivity in such a reservoir. These techniques reduce the uncertainty of hydrocarbon volume and productivity computations in a highly laminated deepwater reservoir. The field example used in this paper is a turbidite sand from North West Borneo. The techniques demonstrated here are also applicable to the analysis of other categories of thinly bedded, shaly sand reservoirs. Introduction Recent advances in NMR technology and signal processing have focused on measuring reservoir fluids volumes and properties in-situ and on identifying reserves in thinly laminated reservoirs, thereby extending the range of NMR applications beyond the volumetric estimates of moveable fluids. Care must be taken to ensure that productive sand units are not discounted by formation evaluation in volumetric estimates of deepwater siliciclastic depositional settings with largely laminated succession of rock layers of varying thicknesses. This issue is becoming increasingly important in Miocene turbidite fans of the North Western Sabah province of Borneo, where many wells logs indicate sequences dominated by thinly laminated layers with low resistivity contrast between sand and shale layers. These beds are often too thin to be properly resolved with conventional logging tools. The acquisition of new technology logging services, such as tri-axial resistivity, high resolution oil-base borehole images and nuclear magnetic resonance (NMR) logs, as well as acquiring rotary and fullbore cores has increased over recent years. New logging techniques and interpretation methods have been applied to improve the evaluation of these thin-bedded reservoirs. This paper highlights efforts placed on the use of NMR logging to delineate reservoir properties to a finer resolution than convention tools. In addition, the use of images and wireline formation testing from the example well, provides the appropriate benchmark for improving estimation of net producible sand thickness in thinly bedded reservoirs. Passey et al. (Ref. 1) define petrophysical thin beds as contiguous units of rocks with thicknesses between 1 in. (2.5 cm) and 2ft (61 cm), that exhibit a narrow distribution of petrophysical properties, but are bounded above and below by other units with significantly different petrophysical properties. These 2 limits represent the currently accepted limits of logging technology: 2 ft is the vertical resolution of a conventional logging tool, and 1 in. is the minimum bed thickness resolved by a borehole imager. (The vertical resolution of modern logging technology actually reaches 1 ft [30.5 cm] for logs, and 0.4 in. [1 cm] for borehole images.)
Over the past few years, there has been a vision in Shell that Optimal Value Testing (OVT) would some day replace conventional drill stem tests for in-situ measurement of dynamic reservoir properties such as permeability and drainage volume. This vision is that OVT would be safer, less costly, and friendlier to the environment, but the key impediment to OVT was that the quality of the results might be inadequate for the difficult development decisions that we face. Definitions of OVT may vary, but in Shell we define it as the testing method that yields fit-for-purpose results with the lowest cost and HSE impact. In more pragmatic terms, it is any pressure transient test in which live hydrocarbons are not produced directly to surface. Currently we have three types of well tests in our OVT toolbox - wireline formation testers, the closed system test with cleanup and repeat surges, and injectivity testing. We have recent examples of closed system tests and wireline formation tests that show we can get comparable data quality to a conventional DST. Injection testing, aimed at determining drainage volume, is less mature and we have yet to execute an injection test. However, there has been considerable design work that makes us believe, given the recent experience with closed chamber systems, that that technology can also be successful. This paper describes the strengths, weaknesses, and opportunities of each OVT type. We present several examples of design, execution, and analysis of these tests. The technology is immature, and there are more issues to resolve than with a conventional drill stem testing. However, by drawing on our increasing breadth of experience, future value of information decisions we take about doing in-situ dynamic measurements will more often include the cheaper, safer, and more environmentally friendly OVT. Introduction The focus of this paper is the use of dynamic well testing in exploratory and appraisal wells. Historically the industry called this a drill stem test, but most modern exploratory and appraisal tests use a dedicated production tubing string rather than the drill string. Following industry convention, however, we will be using the words drill stem test and conventional test interchangeably throughout this paper. This type of testing in which we flow the hydrocarbons directly to surface while measuring the rate and the pressure is one of the major tools petroleum engineers use to decide how to develop a hydrocarbon resource. In most scenarios, these drill stem tests tie up expensive equipment for many days and additionally are a major source of safety and environmental risks. Flaring of the produced hydrocarbon gas is a common example of the high level of such risks. Cost and HSE concerns have driven us to seek better ways to obtain similar reservoir and fluid data. Within our organization, a major international operating company, we have coined the term Optimal Value Testing (OVT) and defined it as any fit-for-purpose well test with minimal cost and HSE impact. In an ideal world, all tests should be optimal, but in our usage the phrase has come to mean any test in which no significant volume of live hydrocarbons is produced to the surface. We have identified three types of tests that might qualify as an OVT - wireline formation tests, closed system tests, and injection tests.
As the cost of exploration wells continue to escalate, we need more than ever to evaluate each well quickly and efficiently to improve the appraisal process and avoid unnecessary expenditure. At the same time, an accurate reservoir characterization is the key to successful reservoir development. This is especially true in thinly laminated reservoirs which exhibit vertical heterogeneity and a wide range of flow properties. Therefore, it is critical to combine high resolution formation evaluation logs and formation tests to predict the well performance prior to the production test. We present an integrated and structured approach for calculating the productivity of a laminated clastic reservoir and we illustrate the method with a field example from Malaysia. A single well predictive model incorporates logs, rock and PVT data, and formation tests to build a flow simulation model at the resolution of the petrophysical analysis. By calibrating the high resolution flow model with dynamic test data from a formation tester Interval Pressure Transient Test (IPTT), the model can be used to predict the well performance. We investigate several key characteristics of thinly laminated reservoirs that affect the well productivity, such as vertical communication between layers. In particular, we examine the effects of clay, silt and sand laminations geometry on the reservoirs productivity. For that purpose, we comment on the information from borehole electrical images, NMR logs, single probe and dual packer wireline formation testers, and production well tests. The workflow is fast to implement as it can be accomplished quickly and efficiently after the well is drilled, in time for planning the well completion and production tests. The high resolution simulation model permits to conduct further engineering studies, whenever required, such as designing the injection and production test for multi-layer reservoirs and water or gas coning studies. Introduction These Deepwater turbidite shallow marine to lower coastal plain reservoirs are composed of interbedded porous/permeable sands with varying percentages of interbedded silt and clay beds. These reservoir sands vary in thickness from millimeter to meters. The reservoirs sands may be highly permeable, but the silt and clay laminations affect the reservoir vertical permeability in each layer. As a result, there are significant vertical heterogeneities in theseis types of reservoirs. It is widely known that the conventional logs may not be able to detect these thinly bedded reservoirs due to their limited insufficient vertical resolution. Therefore, new technology logging services, such as tri-axial resistivity, high resolution oil-base borehole images and nuclear magnetic resonance (NMR) logs have been increasingly used over recent years to help determine an accurate reservoir pay thickness (Ref. 1). In addition to these new logging techniques, interpretation methods such as Log Enhanced Resolution using Borehole Image (SHARP analysis) have been developed to improve the reservoir characterization of these thinly bedded reservoirs (Ref. 2 and 3). After reservoir characterization, other frequently asked questions for thinly bedded reservoir are:What is the productivity of a well drilled in this type of reservoir?What is the connectivity between wells drilled in this type of reservoir? Answers of these questions allow us to evaluate reservoir recoverable reserves. Traditionally, a full scale well test and an interference test are conducted to determine well productivity and well-to-well connectivity, respectively.
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