Drill Stem Test Research Articles

A Review of Reservoir Rock Typing Methods in Carbonate Reservoirs: Relation between Geological, Seismic, and Reservoir Rock Types

Carbonate reservoirs rock typing plays a pivotal role in the construction of reservoir static models and volumetric calculations. The procedure for rock type determination starts with the determination of depositional and diagenetic rock types through petrographic studies of the thin sections prepared from core plugs and cuttings. In the second step of rock typing study, electrofacies are determined based on the classification of well log responses using an appropriate clustering algorithm. The well logs used for electrofacies determination include porosity logs (NPHI, DT, and RHOB), lithodensity log (PEF), and gamma ray log. The third step deals with flow unit determination and pore size distribution analysis. To this end, flow zone indicator (FZI) is calculated from available core analysis data. Through the application of appropriate cutoffs to FZI values, reservoir rock types are classified for the studying interval. In the last step, representative capillary pressure and relative permeability curves are assigned to the reservoir rock types (RRT) based upon a detailed analysis of available laboratory data. Through the analysis of drill stem test (DST) and GDT (gas down to) and ODT (oil down to) data, necessary adjustments are made on the generated PC curves so that they are representative of reservoir conditions. Via the estimation of permeability by using a suitable method, RRT log is generated throughout the logged interval. Finally, by making a link between RRT’s and an appropriate set of seismic attributes, a cube of reservoir rock types is generated in time or depth domain. The current paper reviews different reservoir rock typing approaches from geology to seismic and dynamic and proposes an integrated rock typing workflow for worldwide carbonate reservoirs.

Salt dissolution and permeability in the Western Canada Sedimentary Basin

Extensive dissolution of evaporites has occurred in the Williston Basin, Canada, but it is unclear what effect this has had on bulk permeability. The bulk of this dissolution has occurred from the Prairie Evaporite Formation, which is predominantly halite and potash. However, minor evaporite beds and porosity infilling have also been removed from the overlying Dawson Bay and Souris River formations, which are predominantly carbonates. This study examines whether permeability values in the Dawson Bay and Souris River formations have been affected by dissolution, by analyzing 142 drillstem tests from those formations. For both the Dawson Bay and Souris River formations, the highest permeabilities were found in areas where halite dissolution had occurred. However, the mean permeabilities were not statistically different in areas of halite dissolution compared to those containing connate water. Subsequent precipitation of anhydrite is known to have clogged pore spaces and fractures in some instances. Geochemical relationships found here support this idea but there is no statistically significant relationship between anhydrite saturation and permeability. Geomechanical effects, notably closure of fractures due to collapse, could be a mitigating factor. The results indicate that coupling dissolution and precipitation to changes in permeability in regional flow models remains a significant challenge.

Nonisothermal reservoir/wellbore flow modeling in gas reservoirs

Most analytical and numerical flow modeling presuppose isothermal flow behavior in the reservoir. However, for high rates and large consequent drawdown gas reservoirs, the nonisothermal behavior becomes the norm due to the Joule-Thomson (J-T) effect. Other factors, such as a fluid's adiabatic expansion (AE), heat convection, and the heat exchange with surrounding formations may also make contributions. Accounting for this nonisothermal flow behavior becomes a necessity for accurately estimating a well's performance due to changes in fluid properties.This paper starts with the general energy balance in the reservoir and presents a semianalytical solution to estimate the nonisothermal, single-phase gas temperature in the reservoir during production. This solution considers the J-T effect, adiabatic expansion effect, transient temperature behavior, heat convection, and heat exchange of fluid with over and under-burden formation. The variations of gas viscosity, density, J-T coefficient as a function of temperature and pressure are taken into consideration by making a small spatial step at each computational node. A field case study validates the time-variant wellbore temperature profiles with the coupled reservoir heat-transfer model. Distributed temperature measurements or DTS during a drillstem test (DST) made this validation feasible.The J-T effect dominates in the near wellbore region due to dramatic pressure change. The J-T induced cooling usually occurs for gas in the reservoir. However, for high-pressure systems, the gas behaves like a liquid and gets heated up. For some intermediate pressure intervals, the gas temperature slightly increases with expansion, reach a plateau, and then gradually decreases as the gas moves toward the wellbore with declining pressure. By coupling the reservoir heat-transfer model with the wellbore heat-transfer model, one can monitor more accurately.

Quantitatively Assessing Hydrate-Blockage Development During Deepwater-Gas-Well Testing

Summary Hydrate-associated problems pose a key concern to the oil and gas industry when moving toward deeper-offshore reservoir development. A better understanding of hydrate-blockage-development behavior can help flow-assurance engineers develop more-economical and environmentally friendly hydrate-management strategies for deepwater operations. In this work, a model is proposed to describe the hydrate-blockage-formation behavior in testing tubing during deepwater-gas-well testing. The reliability of the model is verified with drillstem-testing (DST) data. Case studies are performed with the proposed model. They indicate that hydrates form and deposit on the tubing walls, creating a continuously growing hydrate layer, which narrows the tubing, increases the pressure drop, and finally results in conduit blockage. The hydrate-layer thickness is nonuniform. At some places, the hydrate layer grows more quickly, and this is the high-blockage-risk region (HBRR). The HBRR is not located where the lowest ambient temperature is encountered, but rather at the position where maximum subcooling of the produced gas is presented. As an example case—a deepwater gas well with a water depth of 1565 m and a gas-production rate of 45 × 104 m3/d—the hydrate blockage first forms at the depth of 150 m. In the section with a depth from 50 to 350 m, hydrates deposit more rapidly and this is the HBRR. As the water depth increases and/or the gas-flow rate decreases, the HBRR becomes deeper. Inhibitors can delay the occurrence of hydrate blockage. The hydrate problems can be handled with a smaller amount of inhibitors during deepwater well-testing operations. This work provides new insights for engineers to develop a new-generation flow-assurance technique to handle hydrate-associated problems during deepwater operations.

Pressure transient measurement statistics and gauge metrology

Downhole pressure transient measurements are usually affected by random noise caused by the intrinsic noise of the measuring device (the pressure gauge), environmental noise, and/or wellbore pressure fluctuations. The interpretation of pressure transients depends on the characterization of the noise signal and the obtaining of an accurate reservoir pressure response. This article presents a new procedure to characterize acquired formation pressure measurements, their statistical properties, and standard deviation by assuming independent and identically distributed random measurement noise. Apparent accuracy and apparent resolution of measurements are introduced. An automated methodology is developed to obtain and characterize the probability density function of the random noise. This new methodology will replace the conventional manual technique of selectively zooming on pressure curves and measuring their variations.Pressure data from a drillstem test (DST) were used to illustrate the automatic calculation of the apparent resolution. The noise affecting the DST data was then fully characterized and its density function computed. The dataset was also used to introduce and illustrate a new methodology for the analysis of pressure gauge drift using the distribution of slopes extracted from the local linearization of the pressure data. This methodology was able to identify gauges suspected of slight pressure drift that was not detectable visually.

Recent exploration results in the Lower Triassic, Bedout Sub-basin: Australia's next petroleum province?

Commencing in 2014, Quadrant Energy and partners have undertaken an active exploration program in the Bedout Sub-basin with a 100% success rate, discovering four hydrocarbon accumulations with four wells. The primary exploration target in the basin, the Middle Triassic Lower Keraudren Formation, encompasses the reservoirs, source rocks and seals that have trapped hydrocarbons in a self-contained petroleum system. This petroleum system is older than the traditional plays on the North-West Shelf and before recent activity was very poorly understood and easily overlooked. Key reservoirs occur at burial depths of 3500–5500 m, deeper than many of the traditional plays on the North-West Shelf and exhibit variable reservoir quality. Oil and gas-condensate discovered in the first two wells, Phoenix South-1 and Roc-1, raised key questions on the preservation of effective porosity and productivity sufficient to support a commercial development. With the acquisition and detailed interpretation of 119 m of core over the Caley Member reservoir in Roc-2 and a successful drill stem test that was surface equipment constrained to 55 MMscf/d, the productive potential of this reservoir interval has been confirmed. The results of the exploration program to date, combined with acquisition of new 3D/2D seismic data, have enabled a deeper understanding of the potential of the Bedout Sub-basin. A detailed basin model has been developed and a large suite of prospects and leads are recognised across a family of hydrocarbon plays. Two key wells currently scheduled for 2018 (Phoenix South-3 and Dorado-1) will provide critical information about the scale of this opportunity.

Complex accumulation and leakage of YC21-1 gas bearing structure in Yanan sag, Qiongdongnan basin, South China Sea

YC21-1 is a gas-bearing structure found within the Yanan sag in the Qiongdongnan Basin, South China Sea. While the structure bears many geological similarities to the nearby YC13-1 gas field, it nevertheless does not contain commercially viable gas volumes. The main reservoirs of the YC21-1 structure contain high overpressures, which is greatly different from those of the YC13-1 structure. The pressure coefficients from drillstem tests, wireline formation tests and mud weights are above 2.1. Based on well-log analysis, illite content and vitrinite reflectance data of mudstones in well YC21-1-2, combining with tectonic and sedimentation characteristics, the timing and causes of overpressure generation are here interpreted. The results indicate the existence of two overpressure segments in the YC21-1 structure. The first overpressure segment resides mainly within the lower and the middle intervals of the Yinggehai Formation, and is interpreted to have been mainly caused by clay diagenesis, while disequilibrium compaction and hydrocarbon generation may also have contributed to overpressure generation. The second overpressure segment comprising the Sanya Formation (Pressure transition zone) and the Lingshui and Yacheng Formations (Hard overpressure zone) is interpreted to owe its presence to kerogen-to-gas cracking. According to petrography, homogenization temperature and salinity of fluid inclusions, two stages of oil-gas charge occurred within the main reservoirs. On the basis of overpressure causes and oil-gas charge history, combining with restored tectonic evolution and fluid inclusion characteristics, a complex accumulation and leakage process in the YC21-1 gas bearing structure has been interpreted. Collective evidence suggests that the first oil charge occurred in the Middle Miocene (circa 16.3–11.2 Ma). Small amount of oil generation and absence of caprocks led to the failure of oil accumulation. Rapid subsidence in the Pliocene and Quaternary gave rise to a sharp increase in geotemperature over a short period of time, leading to prolific gas-generation through pyrolysis and, consequently, overpressure within the main reservoirs (the second overpressure segment). During this period, the second gas charge occurred in the Pliocene and Quaternary (circa 4.5–0.4 Ma). The natural gas migrated in several phases, consisting of free and water soluble phases in a high-pressure environment. Large amounts of free gas are considered to have been consumed due to dissolution within formation water in highly pressured conditions. Water soluble gas could not accumulate in high point of structure. When the pore-fluid pressures in main reservoirs reached the fracture pressure of formation, free gas could leak via opened fractures within cracked caprocks. A repeated fracturing of caprocks may have consumed natural gas stored in formation water and have made water-soluble gas unsaturated. Therefore, the two factors including caprocks fracturing and dissolution of formation water are interpreted to be mainly responsible for the failure of natural gas accumulation in the YC21-1 structure.

Analyzing of Drill Stem Test (DST) Result for Dual Porosity Limestone Reservoir

The aim of this paper is to discuss and evaluate the result of DST which was conducted in a limestone reservoir of an oil field at the depth interval 3764.29-3903.0 meter in well-1 to evaluate the dynamic characteristics of the reservoirs, for instance: skin effect, permeability, wellbore storage, reservoir boundary and average reservoir pressure. Reservoir Pressure profiles has been recorded for both Buildup and draw down intervals. Semi-log and log-log coordinates have been used to plot the pressure signature date of both buildup period and its derivative to improve diagnostic and Horner plot. In addition, a dual porosity reservoir and infinite acting characteristic was discovered as a result of the well test data interpretation. Wellbore storage, skin factor and transient flow effects have been detected in the DST analysis on the dual porosity behavior due to phase re distribution. Using final buildup sections, the flow parameters of dual porosity reservoir were determined as the flow between fissure and matrix was (7.558 x 10-6) while, the storability ratio between fissure and matrix was calculated as 0.3 and permeability is 102 MD for both matrix and the fissure together. However, negative value of skin factor mostly appears in double porosity limestone reservoirs, positive skin factor of the reservoir has been observed in this study. It can be considered that the positive skin factor can be resulted in either the formation was partially penetrated and /or wells were not cleaned up properly.

Temperature Transients Affect Reservoir–Pressure Estimation During Well Tests: Case Study and Model

Summary This paper discusses how the pressure measured by the downhole gauges during a drillstem test (DST) is affected not only by hydrostatic, friction, or kinetic-energy pressure losses, but also by changes in temperature. In oil wells, the bottomhole temperature is decreasing when the pressure is building up after a flow period. The change in temperature is inducing a change in the wellbore-fluid density, itself affecting the bottomhole pressure. Most numerical-simulators modeling flow in pipes do not take into account this effect, because it is not significant for low- to moderate-productivity wells. In high-productivity wells, however, the temperature change can affect dramatically the bottomhole pressure measured above the reservoir, and the pressure can even decrease at the end of a static period. A mathematical model is presented to compute the pressure drop caused by the nonisothermal effects, and it can be used to correct the measurements. Field examples are discussed to illustrate this effect, and recommendations are made on how new technology can improve pressure measurements during well tests. To measure the effects on the pressure measurements caused by the position of the gauges in the DST string, two gauge carriers were run in some well tests in deepwater wells offshore Brazil, one at the level of the tester valve and one below the packer, as deep as possible in the test string. The gauges could transmit data with a wireless telemetry system that allowed the operator to monitor in real time the pressure changes and the difference between the two sets of gauges. In high-permeability wells, using the uncorrected pressure measured with a gauge 50 to 100 m above the reservoir, as is typically the case, can result in a wrong productivity index (PI) and, at times, in uninterpretable results. Locating pressure gauges as close to the reservoir as possible is crucial in high-permeability reservoirs, to minimize the measurement errors, but also to avoid misinterpretations when an obstruction forms below the tester valve. With the new wireless telemetry systems, it is possible to monitor in real time gauges mounted below the packer, much closer to the perforations than the standard gauges placed at the level of the tester valve, thus avoiding making wrong decisions during the test. A long pressure-transient test could be uninterpretable because the gauges are at the wrong depth. Ideally, the pressure gauges should be placed in front of the perforations, but it is not always possible. Therefore, nonisothermal effects on pressure measurements during a well test need to be clearly understood and taken into account when designing and interpreting well tests, particularly in high-productivity reservoirs.

Modeling Critical Flow through Choke for a Gas-condensate Reservoir Based on Drill Stem Test Data

Gas-condensate reservoirs contain hydrocarbon fluids with characteristics between oil and gas reservoirs and a high gas-liquid ratio. Due to the large gas-liquid ratio, wellhead choke calculations using the empirical equations such as Gilbert may contain considerable error. In this study, using drill stem test (DST) data of a gas-condensate reservoir, coefficients of Gilbert equation was modified; 26.7% of DST data has uncertainty. In these data, due to a problem of flow transmitter, the water flow rate is recorded equal to zero. This makes the mean absolute error of 5% in the measuring of total liquid phase flow rate. Because of uncertainty in the water flow rate in some DST data, the coefficients were optimized for two sets of data to investigate the effect of water flow rate on the calculations. The first dataset was the complete set of DST data, and, in the second, data were filtered with the elimination of uncertain data. The regression results showed that the whole data have a mean absolute error of 5.1%. For this regression, the uncertain data had a mean absolute error of 8.6%, while the error of the remaining data was 3.9%. In this case, for 38% of uncertain data, the mean absolute error was more than 10% indicating that these data are the major factor of the error. Mean absolute error for the filtered dataset was 3.0%. Error reduction was due to the elimination of data with uncertainty. In this case, 3% of the total data had a mean absolute error of more than 10%. In other words, 5% error of the liquid phase flow measurement that includes 26.7% of data caused an increase of 2.1% in the error of calculations. This showed that the elimination of uncertain data causes a remarkable reduction in error. To study the effect of temperature on choke calculations, wellhead temperature was considered as a variable in the Gilbert equation form. The regression results showed that the mean absolute error of 3.0% does not change, and the wellhead temperature has no considerable effect on the choke calculation accuracy.

Modeling Critical Flow through Choke for a Gas-condensate Reservoir Based on Drill Stem Test Data

Gas-condensate reservoirs contain hydrocarbon fluids with characteristics between oil and gas reservoirs and a high gas-liquid ratio. Due to the large gas-liquid ratio, wellhead choke calculations using the empirical equations such as Gilbert may contain considerable error. In this study, using drill stem test (DST) data of a gas-condensate reservoir, coefficients of Gilbert equation was modified; 26.7% of DST data has uncertainty. In these data, due to a problem of flow transmitter, the water flow rate is recorded equal to zero. This makes the mean absolute error of 5% in the measuring of total liquid phase flow rate. Because of uncertainty in the water flow rate in some DST data, the coefficients were optimized for two sets of data to investigate the effect of water flow rate on the calculations. The first dataset was the complete set of DST data, and, in the second, data were filtered with the elimination of uncertain data. The regression results showed that the whole data have a mean absolute error of 5.1%. For this regression, the uncertain data had a mean absolute error of 8.6%, while the error of the remaining data was 3.9%. In this case, for 38% of uncertain data, the mean absolute error was more than 10% indicating that these data are the major factor of the error. Mean absolute error for the filtered dataset was 3.0%. Error reduction was due to the elimination of data with uncertainty. In this case, 3% of the total data had a mean absolute error of more than 10%. In other words, 5% error of the liquid phase flow measurement that includes 26.7% of data caused an increase of 2.1% in the error of calculations. This showed that the elimination of uncertain data causes a remarkable reduction in error. To study the effect of temperature on choke calculations, wellhead temperature was considered as a variable in the Gilbert equation form. The regression results showed that the mean absolute error of 3.0% does not change, and the wellhead temperature has no considerable effect on the choke calculation accuracy.

Hydrogeology of the Judith River Formation in southwestern Saskatchewan, Canada

The Judith River Formation forms an important regional aquifer in southwestern Saskatchewan, Canada. This aquifer is used for domestic and agricultural purposes in some areas and supports oil and gas production in other areas. As a result, the available data come from a range of sources and integration is required to provide an overview of aquifer characteristics. Here, data from oil and gas databases are combined with data from groundwater resource assessments. Analysis of cores, drill-stem tests and pumping tests provide a good overview of the physical hydrogeology of the Judith River Aquifer. Water chemistry data from oil and gas databases were less helpful in understanding the chemical hydrogeology due contamination of samples and unreliable laboratory analyses. Analytical modeling of past pumping in the aquifer indicates that decreases in hydraulic head exceeding 2 m are possible over distances of 10s of kilometers. Similar decreases in head should be expected for additional large withdrawals of groundwater from the Judith River Aquifer. Long-term groundwater abstraction should be limited by low pumping rates. Higher pumping rates appear to be possible for short-term uses, such as those required by the oil and gas industry.

An efficient approach for characterizing basin-scale hydrodynamics

As the upstream oil and gas sector continues to use more groundwater resources for their operations, a comprehensive understanding of formation fluids at the sedimentary basin scale is required to inventory and manage available groundwater resources. Basin-scale fluid flow is often simplified to only assess pre-development groundwater conditions without understanding how large-scale hydrocarbon development might be changing regional flow patterns. This study focuses on two aspects of hydrogeological mapping for characterizing basin-scale hydrodynamics: (1) assessing the influence of hydrocarbon production and injection on pressure measurements used to map hydraulic heads and infer groundwater conditions; and (2) determining the effects of variable density groundwater on understanding the magnitude and direction of flow primarily in saline formation water aquifers. Drillstem Tests (DST's) are transient pressure tests that are used to infer regional groundwater flow, but they can be strongly affected when the sample location is located within the vicinity of a hydrocarbon production or injection well. To identify production and injection influences this study implements a Cumulative Interference Index (CII) methodology. This implementation can be used to map pre-development groundwater flow conditions and evaluate regional changes or effects due to historical oil and gas activity. Density effects are often neglected and can have considerable effect on groundwater flow in cases where aquifers contain dense brines, are inclined and sloping, or possess weaker hydraulic gradients than the buoyancy force potential. This study implements a vectorial analysis to identify flow directions in regions where density driven flow is important and can change the inferred magnitude and direction of flow. Two case studies are presented to demonstrate the effectiveness of these methodologies at evaluating basin-scale hydrodynamics.

Case History: High-Pressure/High-Temperature Underbalanced Drillstem Testing

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 178089, “Case History: HP/HT Underbalanced Drillstem Testing, Deepwater KG Offshore,” by Mahesh Sarode and Milind Khati, Halliburton, prepared for the 2015 SPE Oil and Gas India Conference and Exhibition, Mumbai, 24–26 November. The paper has not been peer reviewed. This paper describes the method developed to achieve underbalanced drillstem testing (DST) in a deepwater field offshore India. DST tools rated to 450°F and 15,000-psi differential pressure were configured to maintain integrity and successfully evaluate the well potential. By use of a multicycle DST tool string, the reservoir potential was tested safely and effectively with an underbalanced test fluid in two deepwater wells, achieving the desired test objectives. Introduction An operator in India needed to conduct high-pressure/high-temperature (HP/HT) drillstem testing on a deep-water well with low-density clear brine in the annulus. Performing DST was necessary to assess hydrocarbon potential in the deep water block for further field- development plans. The DST tools performed satisfactorily for approximately 18 days during the test on a semi-submersible rig. The well was completed in a 6-in. hole, which resulted in a 5-in. casing program, thereby creating a significant challenge. The retrievable packer suitable for the 7-in. casing was set above the 5-in.-liner-hanger top, resulting in a tail pipe of approximately 350 m. Well killing at the end of the DST with such a long tail pipe was a challenge. The method of operating DST tools in both underbalanced brine and kill-weight mud was developed along with a meticulously designed well-test program and a well-kill procedure with a long tail pipe below the 7-in. retrievable packer. Before lowering the DST tools, a well- integrity test was performed by conducting an inflow test for a 5-in.-liner shoe, a 5-in.-liner-hanger top, and a 7-in.-liner-hanger top. Hermetic tests were per-formed to ensure that casings sustained the required annulus pressure for operation of the DST tools.

Prediction of Naturally Fractured Reservoir Performance using Novel Integrated Workflow

Generation of naturally fractured reservoir subsurface fracture maps and prediction its production potential are considered complex process due to insufficient data available such as bore hole images, core data and proper reservoir simulator model. To overcome such shortcomings, the industry has relied on geo-statistical analyses of hard and soft data, which are often referred to as static data. This paper presents an integrated workflow that models and predicting fractured reservoirs performance, through the use of gradient-based inversion techniques and discrete fracture network modelling (DFN), which—through the inversion of well test data (i.e., dynamic data)—aims to optimise fracture properties and then predicting of the reservoir production potential. The first step in the workflow is to identify flow contributing fracture sets by analysing available core descriptions, borehole images, conventional log data and production data. Once the fracture sets are identified, the fracture intensity is statistically populated in the inter-well space. In the second step, 3D block-based permeability tensors are calculated based on flow through discrete fractures, and the fracture intensity is then propagated away from the wellbore, i.e., by relating to permeability tensors with fracture intensity. In the final step (fracture optimisation), the fracture properties are computed by DFN modelling, which includes distribution, orientation and geometry in different realisations. Fluid flow is simulated in these discrete fractures to estimate pressure change and pressure derivatives. The production rate associated with drill stem test that performed within this reservoir area has been successfully simulated using the optimised subsurface fracture map that has been generated from the first step.

Analysis of Drill Stem Test (DST) results at Osobnica oil field, in terms of sampling of selected technology parameters

Analysis of Drill Stem Test (DST) results at Osobnica oil field, in terms of sampling of selected technology parameters

Overpressure characteristics and effects on hydrocarbon distribution in the Bonan Sag, Bohai Bay Basin, China

Overpressure is widespread in the Bonan Sag of the Bohai Bay Basin, East China, and has a strong influence on the migration and accumulation of hydrocarbons sourced from the Es3 and Es4 formations. Pressure measurements in drill stem tests and estimates from sonic logs yield overpressures among different reservoirs and mudstone beds. The fluid pressure in the Bonan Sag increases with depth and is divided into the upper, middle and lower overpressure units that correspond to the Es1, Es3 and Es4 formations, respectively. Oil–source correlation suggests that the distribution of hydrocarbons generated from Es3 and Es4 is controlled by the three pressure units. Hydrocarbons generated from Es4 source rock may laterally migrate within sandstones and accumulate in reservoirs in the Es4 Formation due to the gypsum seal in the lower overpressure unit. A small amount of hydrocarbons vertically migrated along active faults into a shallow formation during charging. However, the effects from faults were more significant on the migration and accumulation of hydrocarbons from the Es3 shale source in the middle overpressure unit. Hydrocarbons generated from the Es3 source rock can vertically migrate into the Es2 or Es1 reservoirs; however, most of them accumulated in Es3 reservoirs. Therefore, the exploration interval should be within the middle and lower overpressure units in the Bonan Sag or along the active fault within the upper overpressure unit.

Possible occurrences of transition zones and residual oil zones below oil-water contacts in mature oil fields, southeast Saskatchewan

A transition zone (TZ) from oil to water formed by capillary force beneath traditionally defined producing oil-water contact (OWC) has been well-known for years. Recent research and production activities in the Permian Basin and the Williston Basin in United States suggests that a residual oil zone (ROZ) may exist below traditionally defined OWC under certain geologic and hydrodynamic conditions. If this ROZ is sufficiently thick and extensive, it may be economically recoverable using tertiary recovery techniques. We have investigated possible occurrences of TZ/ROZ in the Williston Basin, southeast Saskatchewan, using well-log interpretation based on Archie’s equation. Out of 33 pools examined, we have evaluated three areas, the Bellegarde Tilston pool area, an unnamed Souris Valley pool, and the Rosebank Alida pool area, as possibly having thick (up to 47 m) low-oil-saturation TZ/ROZs below the OWCs. Evidence includes oil stains, core-based oil saturation, fluorescence on drill cuttings, and oil shows and sulfur water reported in drill stem tests. The oil in place within the possible TZ/ROZs is estimated to be approximately half the amount of the oil within their associated main pay zones. Tilted OWC and other findings may suggest that the identified oil-bearing zones are ROZs related to hydrodynamics. The hydrodynamic flows may also have created some other ROZs that still remain undiscovered.

Analysis of DST to predict oil sand: A case study of Kailashtilla field

Drill Stem Test (DST) describes the dynamic characteristic of the hydrocarbon bearing formation such as wellbore storage, skin effect, permeability, average reservoir pressure and reservoir boundary. The wellbore storage effect and average reservoir pressure help to predict the flowing phase from the reservoir. An effort has been made to analyze the DST conducted in the Kailashtilla field at the depth interval 3261 meter to 3266 meter in well KTL-7. Two sets of pressure profile have been recorded. First conditioning the well for an hour then performed drawdown following pressure build-up. The pressure signature of the buildup period and its derivative is plotted on semi-log and log-log coordinates to develop Horner and diagnostic plots, respectively. Wellbore storage, skin and transient flow effects have been observed in the DST analysis which is an indication of the hydrocarbon bearing reservoir in the zone of interest. The value of wellbore storage effect is low which predicts the flow of liquid hydrocarbon into the well bore from the reservoir. Average pressure of the investigated zone has been estimated which is higher than the water column pressure. The higher average reservoir pressure also authenticates the presence of oil reservoir.Bangladesh J. Sci. Res. 29(1): 19-29, June-2016

Origin and mixing of crude oils in Triassic reservoirs of Mahu slope area in Junggar Basin, NW China: Implication for control on oil distribution in basin having multiple source rocks

The origin of crude oils and their varied geochemical features along the western and northern slope of the Mahu depression in the Junggar Basin has been controversial. Based on the molecular and isotopic geochemistry of hydrocarbons from 46 drill-stem test crude oil samples and 36 core samples, three oil groups (I, II, III) and five subgroups (I1, I2, II, III1 and III2) have been recognized and oil-source correlations have been established. The subgroup I1 oils originated mainly from lower Permian Fengcheng (P1f) carbonate source rocks, subgroup I2 from P1f mudstone source rock and group II oils from Middle Permian Wuerhe (P2w) mudstone source rock whose potential was underestimated in the past. Group III consists of mixed oils, i.e., subgroup III1 received contributions from P1f carbonates and P2w mudstones and subgroup III2 is a mixture of oils from P1f mudstones and P2w-generated oils. In order to determine the main source rocks, the laboratory oil mixing experiments were carried out. Tricyclic terpane biomarker parameters (TTs) were used to quantify the source contributions. Whole oil carbon isotope ratios were also used to verify the proportions of different oils in each mixture. The results show that subgroup III1 oils have diverse mixing ratios in different reservoir, subgroup III2 oils are mainly from P1f mudstones and P2w source rock contributes little. Finally, the accumulation process of oil fields along the northern slope of the Mahu depression was analyzed and the contributions from different sources were revealed. This study provides an effective quantitative method to identify contributions from different lacustrine source rocks to mixed oils in the Mahu depression, which could be helpful in predicting location and composition of undiscovered oils.