Mini-DST in a Gas Reservoir: Issues, Challenges and Benefits
Abstract: Well testing during the drilling of a well using a Drill Stem Test (DST) tool is a well-established practice in the oil and gas industry. As the name suggests the well test is conducted using the drill stem with the DST tool replacing the drill bit. It is done in open or cased hole and the objective is to measure the pressure, permeability and productivity of the zone of interest. It also gives a measure of the damage done to the formation during the drilling process.In the case of an oil reservoir oil is prod… Show more
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A New Safe and Cost Effective Approach to Large Scale Formation Testing by Fluid Injection on a Wireline Formation Tester
In this paper a new method of performing a wireline large scale formation test is introduced. To measure reservoir properties a significant distance from the wellbore, drill stem testing (DST) tests are often employed. In addition to measuring reservoir dynamic properties, a DST provides information regarding reservoir geometry including the extent of the reservoir, upper and or lower boundaries of the reservoir, barriers to flow within the reservoir. The DST is considered the gold standard for dynamic parameters such as reservoir pressure, formation mobility/permeability, well bore skin factor, flow anisotropy, and the best estimate of production potential for the measured interval. Conceptually, a typical DST is simply a controlled limited production of formation fluids over the reservoir interval of interest. However, a full DST has become an operationally intensive and costly endeavor often lasting many days to weeks. Planning and executing a DST is costly requiring highly specialized equipment that is customized for a unique set of reservoir and operating conditions. One of the primary considerations is to insure the environmental compliant disposal of a considerable quantity of produced fluid. Due to the high cost of traditional DSTs, alternate methods of testing have been employed. Wireline formation testers capabilities have increased their pumping capacities and are used to perform a small scale mini-DST that has increasingly been employed as a substitute for full DSTs at a much lower cost. A mini-DST can provide measurements of the reservoir dynamic properties, albeit over a smaller depth interval and smaller radius of investigation. The mini-DST radius of investigation generally extends up to 100feet from the wellbore and over a vertical height of a few feet as opposed to the full DST which can extend thousands of feet from the wellbore and be extended over tens of feet covering an entire vertical producing interval. While a DST can accurately characterize an entire formation production interval's potential, the mini-DST can delineate the formation flow interval and determine the most productive layers, flow barriers and thief zones which are critical to optimizing the completion design. This new method combines a conventional wireline mini-DST and sampling procedure with an extended injection test in order to recover the reservoir flow interval geometry information and improve flow interval delineation. The mini-DST measures the local mobility of the formation, cleans the wellbore of mud filter cake and near well bore mud filtrate contamination, thus enabling the acquisition of a clean formation sample. When acquiring a formation sample the formation fluid properties can be determined with downhole sensors and a subsequent mini-DST can provide the in situ dynamic properties. A selected injection fluid can be used to reverse the process by flowing into the interval. Because the injection fluid would have known properties that are measured in controlled laboratory testing, the dynamic data results will be more definitive. For example, the viscosity will be known enabling the rock permeability determination, where traditionally only the mobility can be determined. In many cases the reservoir oil type is known and the injection fluid can be closely matched to improve the in situ dynamic data results. Aided by favorable backing pressure from the surface, and not limited by the fluid bubble point, the injection fluid may be pumped into the formation at a higher rate than the formation fluid can be withdrawn from the formation. This allows a greater sand face to reservoir pressure differential, yielding an improved pressure signal for evaluation. Furthermore, because fluid is injected, no environmental sensitive disposal is required, and the procedure is inherently safer for maintaining well integrity than a formation fluid withdraw. However, interpretation of the pressure rebound after the injection stops may require a reservoir simulation if the injection fluid property is significantly different from the in situ reservoir mobile fluid. This paper evaluates the new method based on detailed reservoir simulations and using available field equipment capabilities. These simulations include considerations of invasion and cleanup in a multiphase environment. In addition, a sensitivity study summarizes the testing effectiveness by varying the primary parameters such as permeability, anisotropy, skin, and formation barrier distances. From this work, conclusions are drawn comparing the new reverse injection DST method to traditional DST and wireline technologies.
A New Safe and Cost Effective Approach to Large Scale Formation Testing by Fluid Injection on a Wireline Formation Tester
In this paper a new method of performing a wireline large scale formation test is introduced. To measure reservoir properties a significant distance from the wellbore, drill stem testing (DST) tests are often employed. In addition to measuring reservoir dynamic properties, a DST provides information regarding reservoir geometry including the extent of the reservoir, upper and or lower boundaries of the reservoir, barriers to flow within the reservoir. The DST is considered the gold standard for dynamic parameters such as reservoir pressure, formation mobility/permeability, well bore skin factor, flow anisotropy, and the best estimate of production potential for the measured interval. Conceptually, a typical DST is simply a controlled limited production of formation fluids over the reservoir interval of interest. However, a full DST has become an operationally intensive and costly endeavor often lasting many days to weeks. Planning and executing a DST is costly requiring highly specialized equipment that is customized for a unique set of reservoir and operating conditions. One of the primary considerations is to insure the environmental compliant disposal of a considerable quantity of produced fluid. Due to the high cost of traditional DSTs, alternate methods of testing have been employed. Wireline formation testers capabilities have increased their pumping capacities and are used to perform a small scale mini-DST that has increasingly been employed as a substitute for full DSTs at a much lower cost. A mini-DST can provide measurements of the reservoir dynamic properties, albeit over a smaller depth interval and smaller radius of investigation. The mini-DST radius of investigation generally extends up to 100feet from the wellbore and over a vertical height of a few feet as opposed to the full DST which can extend thousands of feet from the wellbore and be extended over tens of feet covering an entire vertical producing interval. While a DST can accurately characterize an entire formation production interval's potential, the mini-DST can delineate the formation flow interval and determine the most productive layers, flow barriers and thief zones which are critical to optimizing the completion design. This new method combines a conventional wireline mini-DST and sampling procedure with an extended injection test in order to recover the reservoir flow interval geometry information and improve flow interval delineation. The mini-DST measures the local mobility of the formation, cleans the wellbore of mud filter cake and near well bore mud filtrate contamination, thus enabling the acquisition of a clean formation sample. When acquiring a formation sample the formation fluid properties can be determined with downhole sensors and a subsequent mini-DST can provide the in situ dynamic properties. A selected injection fluid can be used to reverse the process by flowing into the interval. Because the injection fluid would have known properties that are measured in controlled laboratory testing, the dynamic data results will be more definitive. For example, the viscosity will be known enabling the rock permeability determination, where traditionally only the mobility can be determined. In many cases the reservoir oil type is known and the injection fluid can be closely matched to improve the in situ dynamic data results. Aided by favorable backing pressure from the surface, and not limited by the fluid bubble point, the injection fluid may be pumped into the formation at a higher rate than the formation fluid can be withdrawn from the formation. This allows a greater sand face to reservoir pressure differential, yielding an improved pressure signal for evaluation. Furthermore, because fluid is injected, no environmental sensitive disposal is required, and the procedure is inherently safer for maintaining well integrity than a formation fluid withdraw. However, interpretation of the pressure rebound after the injection stops may require a reservoir simulation if the injection fluid property is significantly different from the in situ reservoir mobile fluid. This paper evaluates the new method based on detailed reservoir simulations and using available field equipment capabilities. These simulations include considerations of invasion and cleanup in a multiphase environment. In addition, a sensitivity study summarizes the testing effectiveness by varying the primary parameters such as permeability, anisotropy, skin, and formation barrier distances. From this work, conclusions are drawn comparing the new reverse injection DST method to traditional DST and wireline technologies.
Integrating Permeability Data from DST Interpretation to Characterize Deepwater Gas Turbidite Reservoir in Niger Delta: Lessons Learnt
Data acquisition in deep water environments is critical in de-risking subsurface uncertainties and data must be of high quality before development plans can be put in place and sanctioned, given the expensive associated field development costs. In exploration and appraisal drilling campaigns for deepwater environments, one of such data acquisition is via the Drill Stem Test (DST), essential to understand the turbidite reservoirs; characterize and reconstruct the depositional environment. One key challenge in the deepwater environment is the connectivity and thinly bedded nature of the reservoirs with obvious vertical heterogeneity and varying layer flow properties. DST is commonly used to acquire formation pressures, reservoir fluid samples and determine the productivity of the formation. In this study, the DST was run in a deep offshore gas reservoir with a net thickness of 49ft over a perforated interval; 13,215 ft MD to 13,294 ft MD. The objective was to quantify average formation dynamic flow capacity (permeability-thickness product), well productivity, prove sufficient gas resources for further development of the structure and obtain information about the lateral extent and architecture of the sand bodies. A series of multi-rate drawdowns and build-ups were extracted from the DST and used for the analysis. The Kappa Ecrin well test interpretation software was used to interpret the DST and from the test, formation properties such as skin and permeability as well as insights about the Infinite-acting radial flow (IARF) and boundaries effects were evaluated. This paper demonstrates the use of DST interpreted results with core data to estimate the range of permeability uncertainty for varying stratigraphy or facies in a deepwater gas reservoir in the Niger delta. Although, the reservoir boundaries could not be fully detected due to limited pressure Build-up (PBU) periods, various model scenarios were evaluated to estimate the range of permeability values using the limited transient phase. Thus, outcome of the interpretation was used to quantify the range of permeability from both the DST and the core plug permeability measurements within the reservoir ranging from 250mD to 1900mD. Finally, this paper also used permeability data from wireline log and DSTs to complement geological and seismic data interpretations and establish the range of uncertainties in permeability.
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