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 layer flow properties.Wireline formation testers have been commonly used to acquire formation pressures pressure and reservoir fluid samples for a number of decades. Many hardware technologies and interpretation methods have been developed to acquire better quality reservoir information. Dual packer wireline formation testers offer an alternative an additional way to selectively straddle a section of a reservoir and provide the capability to conduct controlled local production and interference as well as to enable the capture of reservoir fluids. Formation permeability, anisotropy, skin factor, vertical connectivity and zonal productivity index are additional reservoir information that can be obtained from a mini-Drill Stem Test (mini-DST) and a Vertical Interference Test (VIT).Pressure transient analysis of a mini-DST data however in such reservoirs is challenging due to the associated uncertainties such as layer flow compartments and flowing fluid viscosity. This paper discusses the use of integrated reservoir information obtained from Downhole Fluid Analyzers (DFA), borehole images, and numerical simulation models to minimize these uncertainties. A systematic pressure transient analysis method for mini-DSTs is also introduced. * Currently with Santos Ltd.Reservoir parameters obtained from mini-DSTs in thinly laminated deepwater reservoirs are then compared with other available static and dynamic reservoir information such as petrophysical data, core analysis, well tests, production logs, and single probe wireline formation tests in order to obtain accurate interpretation results of highest consistency.Field examples will be discussed which show that smaller scale pressure transient tests often have an advantage over full scale well tests testing in terms of providing detailed layer flow behavior, vertical connectivity and flow potential in thinly bedded environments. It will also be noted that the radius of investigation of a mini-DST is limited, typically within tens of feet. This paper demonstrates using field examples that reservoir boundaries can be detected when sufficient radius of investigation is achieved. In addition, the understanding of limitations and advantages will allow the proper selection of test types in order to meet specific objectives and maximize the full potential use of acquired data for field development plans in thinly laminated deepwater environments.
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.
Reservoir fluid identification plays a crucial role in reservoir characterization and hydrocarbon volume estimation. Gas condensate reservoir is well known for its complex behaviour due to the nature of a near critical fluid. The reservoir pressure and temperature in such reservoirs are very close to the critical point, and therefore, small changes in reservoir condition will result in a change of fluid properties considerably. As a result, there exists a broad spectrum of reservoir fluids in this reservoir condition. Identifying reservoir fluid in the zones of interest is extremely challenging, especially when it is associated with overpressured low porosity shaly sandstone reservoir. It becomes difficult and at times impossible to definitively identify different types of formation fluids from the well logs alone. This paper presents challenges of fluid identification process during the exploration/appraisal campaign in such reservoirs, offshore Malaysia, where the operator needs to gather as much information and as quickly as possible to make immediate operation decisions and Field Development Plans (FDP). First part of this paper demonstrates an integration of available data including mud logs, gas chromatography, gas wetness ratio, well logs, formation pressure and DST in order to determine fluid types in a well where an expected reservoir fluid is oil. The result from a systematic integrated reservoir characterization performed later, however, has found that the reservoir fluid is gas condensate. The second part shows an extensive application of Downhole Fluid Analyzer (DFA) in the Wireline Formation Tester (WFT) tool to conclusively identify reservoir fluid types and their properties in-situ and in real time in the second well drilled in a different fault block. In this case, the use of WFT together with DFA has allowed identification and PVT property determination of a full range of downhole fluids including gas, retrograde gas, volatile oil and black oil. This suggests a number of compartments in such complex reservoirs. Introduction Reservoir fluid identification plays a crucial role in reservoir characterization and hydrocarbon volume estimation. In thick, porous and clean reservoirs, the process of fluid identification is straight forward. Initially, the bulk density and neutron porosity logs are used in combination with resistivity logs to identify reservoir fluid type. In clean reservoir, density porosity log will overlay neutron porosity log in water zone. In hydrocarbon bearing zone, density and neutron porosity logs will start crossing over each other. A very large density and neutron porosity log crossover together with high value of resistivity suggests that the formation is gas bearing. Normally, formation pressure gradients obtained from wireline formation tester (WFT) tools greatly help in identifying fluid types.
The inherent uncertainty in establishing reservoir connectivity has always been an issue for reservoir management. Standard correlation methods using logs, cores and seismic data are sometimes inadequate, whereas an extended production test may be too expensive or non feasible. Increasingly, geochemical techniques are being deployed to determine reservoir connectivity based on the compositional differences in the reservoir fluid. In a number of reservoirs around the world, carbon dioxide (CO2) is a critical gas composition. Examples from two such reservoirs, one from the Browse Basin in Australia and the other from the Malay Basin in Malaysia will be discussed in this paper. The CO2 content can vary from very low concentrations in one zone to significantly high in others in the same field. In addition, accurate quantification of CO2 from reservoir fluid samples can be difficult especially if some water is also present in the collected samples. This is due to the nature of CO2 which easily reacts with water, the source of which could be mud filtrate or formation water. As a result, in a well drilled with water based mud (WBM), contamination needs to be mitigated in samples captured for the purpose of quantification of CO2 in a given reservoir. This paper presents field examples from the Asia Pacific region where a new generation Wireline Formation Tester (WFT) tool together with an advanced Downhole Fluid Analyzer (DFA) was used to quantify CO2 in real time as well as acquire high quality PVT samples. As the analyses of hydrocarbon samples from previous exploration wells within the same regions had shown significant variation in CO2 content, new and improved sampling procedures together with advanced DFA measurements were required to accurately measure and quantify CO2 concentrations in a number of reservoirs with varying fluid compositions. In this paper operational considerations and challenges of acquiring high quality PVT samples for different reservoir fluids under varying conditions are also discussed. Introduction The first generation Downhole Fluid Analyzer (DFA) tool was introduced together with the launch of the new and improved Wireline Formation Testers (WFT) in the early 1990's. Its main objective was to identify in-situ reservoir fluids and to obtain fluid fractions, i.e. water/oil fractions, and to monitor contamination cleaning up process prior to capturing fluid samples 1. This was done by the application of optical principles for continuous analysis of fluids in the WFT flowline. The first generation of DFA tools had a visible and near-infrared absorption spectrometer for fluid discrimination and a refractometer for free gas detection. Since then, other generations of the DFA tools have been introduced to obtain additional reservoir fluid information. DFA tools today are used for such applications as:to evaluate downhole fluid sample contamination 2to measure Gas-Oil-Ratio (GOR) and Condensate-Gas-Ratio (CGR)to provide fluid composition, i.e. C1, C2-C5, C6+to identify when the flowing pressure falls below saturation pressureto identify compositional grading 3to identify reservoir compartmentalization 4,5to measure in-situ pH6to monitor the cleaning-up process using downhole pH when sampling formation water in a well drilled with WBM7
A vibrating wire (VW) viscometer is introduced for the in-situ measurement of formation fluid viscosity. This is the first time this simple and robust technology has been applied downhole to measure formation fluid viscosity with a wireline formation tester in-situ. Extensive laboratory tests have demonstrated the efficacy of the VW viscometer over a wide range of pressures and temperatures, with tests performed with a large variety of live fluids under flowing or static conditions. Field examples described here were performed in water and oil zones, both in wells drilled with oil-based-mud (OBM) and water-based-mud (WBM). Knowledge of formation fluid characteristics, including viscosity, is important for reservoir characterization. A decision as to the economic viability of a well can depend upon fluid mobility, and, by consequence, its viscosity. Fluid profiling vertically or horizontally provides information on compartments, compositional gradients, thin beds, transition zones, and zonal connectivity. Better understanding of the reservoir using in-situ viscosity measurements can illustrate the origin of compositional gradient, whether it originates from gravity segregation, thermal diffusion, incomplete equilibrium migration, asphaltene precipitation, or biodegradation. The ability to perform in-situ viscosity measurements decreases the need for an extensive sampling campaign and costly and time-consuming pressure/volume/temperature (PVT) analysis. It helps the operator make real-time decisions for perforation zones and side track drilling. In this article we briefly describe the theory of the VW viscometer and its suitability for downhole measurements. Laboratory results obtained with the sensor at different conditions of pressure and temperature and over a wide range of viscosity are presented. Field results are presented that were obtained during sampling and/or downhole fluid analysis stations for various fluid and mud types, summarized in the examples below: –Oil viscosity in OBM: We present a case of advanced focused sampling (for very low contamination levels) and fluid analysis used to characterize the formation fluid and reservoir, in northern Kuwait. Viscosity measurements were obtained with a high accuracy and compared very well with two other sensors (DV-Rod sensors for in-situ density) that could be used for viscosity measurements in this environment.–Oil viscosity in WBM: The presence of immiscible fluids presents an extra challenge for sensors as the wetting phase may impede proper clean-up of sensor surfaces, thereby biasing the measurement. However, the VW viscometer, of extremely small cross-section, is able to quickly shed itself of debris, mud, and filtrate. In a first example, within 1 hour of sampling the viscosity measurements stabilized to that expected for oil in this reservoir. In the second example with more viscous oil, the measured viscosity of the emulsified fluid decreased as its water content decreased, in agreement with expectations.–Water viscosity in WBM: We discuss formation water viscosity measurements using the VW viscometer. Such measurements allow one to understand the relative mobility of the water and hydrocarbon phases as well as to discriminate between formation and filtrate waters. Downhole viscosity measurements are presented for formation water that are in agreement with their theoretical values at similar conditions.
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