Analysis of Factors Affecting Drillstem Tests in Low-Permeability Reservoirs

Exploration, appraisal, and production well tests have always been a primary source of information for reservoir characterization, well deliverability estimation, and monitoring of field development. Well test operations are one of the most challenging operations performed at the wellsite today, especially in tight oil and gas reservoirs with limited capability or inability of the well to flow naturally and produce reservoir hydrocarbons to surface. Conventional drill stem tests (DSTs) may also not be applicable in some cases due to the high cost of operations or other constraints. Over time, environmental considerations and regulations have become stricter and one of the most significant limiting factors for conducting conventional DST operations in some geographical areas. DST operations in tight reservoirs have always been limited and deemed challenging due to complexities associated with the ability to create enough pressure drawdown, high risks associated with the inability of the well to flow to surface to unload the liquids from the wellbore, and clean-up of the well to unlock true reservoir potential. Therefore, for the last several decades, the oil industry has been trying to find the most effective ways to flow test these wells to determine essential reservoir information and minimize field development risks. Impulse testing is not a new concept and enables testing a well using a simple DST or tubing-conveyed perforating (TCP) string with no flow of hydrocarbon to surface. This method also reduces cost in comparison with conventional DST operations or other standard testing methods. Until recently, the application of this type of test has been limited, mainly by the complexity of interpreting the test data, limited functionalities of the tools, low success rate, and poor quality of acquired data. With the evolution of downhole DST tool technology and enhancements in well test design, along with the appropriate equipment selection, a new generation of low flow rate impulse tests have been engineered for success by bringing together a multidisciplinary team and emphasizing the importance of the job design. The paper describes cost-effective, practical, and proven impulse testing methods for tight oil and gas reservoirs. The proposed methods are versatile and adaptive to the operating environment and the operator's requirements. The zero-emission well testing solution is based on proven conventional well test interpretation methods and a combination of technologies, workflows, and unique equipment arrangements that make it possible to flow test the wells to determine key reservoir dynamic parameters and the productivity indices of new wells during DST or TCP operations or during workover operations if the wells are currently in production. This paper also presents several field examples from operations performed around the globe, with results of the successful pressure transient analysis of the data recorded during the tests that enabled characterizing the reservoir economically and in two cases, with no environmental impact.

The main objective of this work is to propose a mathematical model for the differential sticking coefficient of clayey drilling fluids with a lubricant as an additive and evaluate the influence of differential pressure and lubricant content on filter cake thickness and permeability. Tests were carried out on fluids composed of water and 4.86% of active bentonite clay prepared in Hamilton Beach agitators at a high rotation speed (17000 rpm) for 20 minutes. After a 24-hour time-out in a closed container, lubricants were added to the fluids at different levels. To obtain the differential sticking coefficient (DSC), and the filter cake, a differential sticking tester by Fann with a spherical torque plate was used, and the filter cake thickness was determined in an extensometer. The setting time, differential pressure, and lubricant content were defined as the input variables (independent variables) to the DSC mathematical model. The differential pressure and lubricant rate were the independent variables to the mathematical model of filter cake thickness (FCT) and permeability (K), which varied according to a factorial planning, was known as a second order model. The experimental data regression was performed utilizing Statistic software, version 7.0. The results clearly showed that it was possible to obtain a statistically meaningful and predictive mathematical model for DSC. It was also observed that the increase in the lubricant content was responsible for a DSC value reduction due to the fact that the lubricant was a dispersing agent reducing the filtrate volume and the filter cake thickness, and thereby decreasing the sticking risk due to differential pressure. Finally, from the analysis of point values and response surfaces for FCT and K, it was possible to observe tendencies that made clear that the differential pressure and lubricant content influenced filter cake properties.

Performance of water-based drilling fluids for deepwater and hydrate reservoirs: Designing and modelling studies

Reservoir testing is always needed to understand flow potential and to confirm hydrocarbon discoveries. In Southeast Asia, reservoirs are frequently laminated, thinly bedded, and compartmentalized. Testing every individual (main) zone with Drill Stem Test (DST) is not economical due to cost and rig time constraints. Different testing methods have been used such as Tubing Stem Testing (TST) and multi zone DST, with and without Production Logging Tool (PLT) for zonal contribution. However, these methods still need to flow hydrocarbon to surface, require a large footprint, i.e. separator units at surface, and to flare hydrocarbon to atmosphere. Interval Pressure Transient Test (IPTT) and Deep Transient Testing (DTT) have been introduced as greener alternative wireline testing methods, where each zone can be isolated and tested individually without flaring. IPTT has been used for more than 20 years to derive zonal permeability. IPTT tests single hydraulically connected layers and obtained permeability often compares well to testing derived permeability. However, IPTT feasibility is limited in combinations of permeability, thickness and reservoir fluid viscosity. With the introduction of DTT, the use of a circulating sub has enabled much larger volumes with longer period without jeopardizing well stability. With higher flowrates and improved gauge resolution, a much deeper radius of investigation can be achieved with this green testing technology, and higher permeability gas reservoir testing is feasible. This paper will show examples where DST with either IPTT or DTT have been acquired on the same well. In each case, an integrated workflow for log-to-reservoir scale model is constructed from formation testing data and high-resolution logs, which is used to generate a zonal inflow performance relationship (IPR). In the first example, a cased hole DTT was acquired in a good permeability gas reservoir, and the integrated workflow was used to derive zonal IPR and minimum connected volume. In a second well, an IPTT was conducted after quality fluid samples were acquired which was followed by a commingle DST. The IPTT is used to derive individual layer permeability within the DST interval and to characterize zonal contributions. This is of critical importance for the production and reservoir recovery strategy in this multi-zone reservoir. In the third example, both DTT and DST were run in a high-permeability gas reservoir. Results are compared in terms of fluid sampling and pressure transient data. An integrated workflow was used to upscale the DTT calibrated model to the DST zones. In this example, even with a small DTT drawdown, the pressure transient from high-resolution gauges allowed for valid transient data. This paper shows a comparison of DTT to DST in a high- and low-permeability gas reservoir together with the discussion of test selection implications such as footprint, CO2 emissions, interpretation techniques together with lessons learned and best practices.

Summary This paper shows that mud-filtrate invasion prior to drillstem testing in low-permeability gas formations can cause significant reduction of gas flow rate observed during the test. In addition, apparent gas permeabilities determined from test data can be much lower than the true values. These conclusions are supported by simulator results and field data. Introduction Interpretation of drillstem tests (DST's) in low-permeability gas formations is difficult. and this difficulty leads to uncertainty in identifying formations that, when stimulated, could become commercial completions. Operators have tong suspected that mud-filtrate invasion into these low-permeability formations could contribute to these uncertainties because of significant alterations in relative permeability and capillary pressure. These uncertainties led us to a study of the effects of mud-filtrate invasion on response in a DST; this paper reports the results of that study. In this investigation, we used a two-phase, two-dimensional, fully implicit reservoir simulator to model DST's. The input data for the simulator were obtained from special core analyses. openhole tops, and DST's from the Falher sandstone in western Canada. Model Description The two-dimensional, two-phase model used in this study has been described previously in the literature. The model simulates the flow of gas and water in the formation using a simultaneous determination of saturations and pressures from finite-difference approximations of the gas and water flow equations. Capillary pressure and relative permeability data are input into the model; the model is therefore capable of simulating imbibition, water blocking, and cleanup effects. These effects are potentially important in DST performance. To simulate a DST, uniform initial pressures and saturations were established in the model for all reservoir cells. To model the imbibition of filtrate into the formation prior to the DST, the pressure in the wellbore was set equal to (and maintained at) the hydrostatic mud pressure, and the water (filtrate) saturation was maintained at 100%. Water saturations and pressures around the wellbore increased during the imbibition period as filtrate moved into the reservoir. To model a mud filter cake, the permeabilities in the formation adjacent to the wellbore were reduced. Following the imbibition period, a flow period was simulated. During the flow period, the pressure in the wellbore was maintained at a fixed pressure and the wellbore volume was set equal to the value of a typical drillpipe open to flow. Following the flow period, a pressure buildup test was simulated, with the wellbore volume set equal to a typical volume below the shut-in valve in a DST tool assembly . JPT P. 299^

Mathematical modeling for prediction of the distribution and mixing of mud filtrates in the reservoir formation surrounding a well being drilled and the filter cake build-up and its effect on the mud filtrate invasion into the formation, as well as the resulting formation damage effects is presented. The model can simulate the single and two-phase flow situations in the formation with water or oil based drilling mud cases. External particle invasion during the early period of filter cake initiation and its effect on the formation damage by particle migration and retention is considered. An application involving radial flow is given. This model is a useful tool for accurate interpretation of oil-mud-fluid system saturations and resistivity profiles which are essential for the development of efficient well-log interpretation.

Coreflood experiments were conducted in Berea sandstone and Texas Cream limestone cores to quantify the loss in relative permeability caused by condensate accumulation. The in-situ condensate saturation was established dynamically by precise control of core inlet and outlet pressures. It is well known that retrograde condensate dropout can cause significant productivity loss in low permeability reservoirs. This paper shows that such losses can also occur in high permeability reservoirs. Gas relative permeability reductions of 91% to 97% were seen in 2-5 md limestone cores and 95% to 98% in 246-378 md sandstone cores. In light of the new data presented here, the common perception that condensate blocking around wells in high-permeability reservoirs is not significant should be re-examined. Our previous coreflood experiments showed that methanol treatments increased the gas relative permeability in low permeability carbonates, but we had not yet determined the required methanol treatment volumes as done in this study. Methanol displaces retrograde condensate and maintains improved gas relative permeability well into the post-treatment production period. Methanol also displaces water and this can also contribute to higher gas relative permeability in those cases when the initial water saturation is high enough to significantly add to the total liquid blocking of the gas. These results can be used to help reservoir engineers evaluate and treat gas-condensate wells with reduced productivity. Reservoir engineers should be especially careful to evaluate the damage done in such high-permeability reservoirs if the well's pressure drawdown is high enough to result in pressures below the dew point pressure.

During drilling operations, mud is typically circulated at pressures above the reservoir pressure, and this causes solid particles to deposit along the wellbore creating a mud cake, while the mud filtrate can invade into the formation creating a damaged zone. Near wellbore damage can result in reduced permeability, increased skin and thereby lower productivity of the reservoir, while thick mud cakes can cause issues during drilling including stuck pipe, high torque as well as excessive swab and surge pressures during tripping. These can be prevented by designing the drilling fluid to reduce the quantity of mud filtrate that enters the formation. To facilitate the drilling process, the filter cake that forms should also be thin, uniformly distributed, and stabilized. New techniques such as the use of nanoparticles in the drilling mud, as well as ultrasonication of drilling mud before circulation has demonstrated potential in reducing the filtrate loss into the productive zones, while also optimizing the mud cake formed. This current work studies the effect of adding silicon dioxide (SiO2) particles with spherical morphology and multi-walled carbon nanotubes (MW-CNT) with cylindrical morphology into a water-based drilling fluid sample to improve its filtration characteristics. Systematic ultrasonication of the drilling mud was also conducted to optimize filter cake properties, with the aim to reduce their thickness, while also reducing filtrate loss into the formation. To assess the fluid loss, measurements are made of the filtrate volume, the dry and wet weights, and the filter cake thickness. Based on the experimental results, the amount of filtrate/fluid loss can be decreased with the use of nanoparticles. The weight of the filtrate cake is found to have increased with an increase in nanoparticle loading. Based on filter cake thickness, stability, and porosity estimates of the filter cake, low-concentration SiO2-nanomud (at 1wt%) is observed to be a better candidate than MW-CNT-nanomud to control fluid loss and to maintain wellbore stability. Fluid loss is also observed to be reduced by the ultrasonication process, while the filter cake formed by ultrasonicated drilling mud is thinner and less permeable when compared to an unsonicated sample. Reducing fluid loss is a priority in drilling operations to prevent formation damage and novel techniques such as nanoparticles and ultrasonication can provide optimal results for this issue. The addition of nanoparticles is observed to increase the filtrate cake thickness and reduce the filter cake's porosity, thereby reducing fluid loss. Ultrasonication of drilling mud also produced better filter cake with reduced permeability which in turn reduced fluid loss into the formation.

Donghae-1 gas field is located in Ulleung basin at offshore Ulsan, Korea, and its recoverable reserve is expected to be 170 to 200 BCF (Billion cubic feet). The field was confirmed to have potential gas and condensate reserves from an exploration well in 1998 and two appraisal wells in 1999. This field consists of five zones, with an average reservoir depth of about 7,000 to 8,000 ft. In this study, we have performed an analysis of Gorae V DST (Drillstem test) #2 for testing B4 zone which has the biggest reserves and Gorae V-1 DST #2 for testing B3 and B4 zones simultaneously among DST data achieved in a total of 11 zones at three wells. The pressure and flow rate recorded from two tested zones were used to obtain the reservoir characteristics and the well productivity. For pressure transient test data, we carried out the analysis of reservoir permeability, skin factor, wellbore storage effect and barrier effect by using the Homer plot and type curve matching methods. Also, with the deliverability test data, we estimated the absolute open flow which is the maximum flow rate of the gas well, and extracted the correlations representing production rate with reservoir pressure. According to the analysis, Gorae V DST #2 of B4 zone has a permeability and skin factor of 37 md (Millidarcy), 4.54, and Gorae V-1 DST #2 of B3 and B4 zones has 23 md and 21.0, respectively. It was also found that the wellbore storage effect was not significant for the two wells tested. From the deliverability test analysis, the AOF (Absolute open flow) of the Gorae V DST #2 is 152.8 MMSCFD (Million standard cubic feet per day), and that of the Gorae V-1 DST #2 is calculated to be 68.2 MMSCFD.

A new generation Wireline Formation Tester (WFT) was used to perform fluid sampling in a subject field as part of an appraisal drilling campaign targeting significant undeveloped conventional oil reserves. The field consists of free gas caps with associated saturated oil intervals that appear as thin rims around anticlinal flanks. Resistivity log analysis predicated a mud filtrate invasion volume of 89L. Approximately 150% of the expected invasion volume (128L) was pumped during sampling. Laboratory results showed that the sampled fluid was still mud filtrate, despite pumping an extra 50% of the estimated volume required for hydrocarbon breakthrough. This paper presents a mathematical model for predicting filtrate invasion and post drilling WFT cleanup performance. A new methodology is developed to incorporate critical shear stress concepts into mud filter-cake thickness and filtrate invasion calculations. The mathematical model is used to provide input data for Eclipse reservoir simulator (E100) and an analysis of the field case. The model can also be applied as a predictive tool for filter-cake development, filtrate invasion and pump-out volumes required during fluid sampling. In addition, the model can be used to design optimal mud properties that minimize filtrate invasion and extra treatment of the invaded zone post-drilling. The mathematical model is integrated with reservoir simulation to model the cleanup process. The mathematical model developed in this study predicted an invasion volume of 528L, which is significantly greater than what was estimated based on resistivity logs (89L). This implies that filtrate invasion volume in the field case was underestimated. A sensitivity study showed that filter-cake permeability was the greatest determinant of filtrate invasion volume, and that radius of filtrate invasion was the greatest control on mud filtrate cleanup during sampling. Reservoir simulation provided a good match between model simulation results and field data.

A mini drillstem test (DST) with a Wireline Formation Tester (WFT) tool was performed in a low-perm, unconsolidated gas reservoir in a shallow well in offshore Malaysia to obtain high quality gas samples and to determine main reservoir properties. Single probe WFT attempts were unsuccessful in the offset well because of tightness attributed to high silt content. Consequently, the mini-DST was run in open hole, rather than the normal full-bore DST, which was an option for reservoir characterization. This paper describes a successful reservoir characterization using a mini-DST in an open hole in a shallow low permeability reservoir; it provides background information about the wireline formation tester jobs conducted in an offset well. The paper also addresses the design criteria for performing the mini-DST and delves into the factors that were considered for job planning and proper job performance. The unconsolidated sand posed some challenges, including a significant risk of sand failure during pumpout. Conversely, the low permeability requires more drawdown to flow the tested interval. The paper also includes the steps undertaken to minimize this risk by analyzing real-time data. Despite low permeability, a good radial flow was obtained and used to estimate reservoir properties by creating proper drawdown. The high mobility of the low pressure gas in the reservoir compensated for the reservoir tightness. Although the radius of investigation in a relatively short buildup is not sufficiently high, it can still assist in reservoir characterization for development purposes with the integration of core, petrophysical, and DST data. The paper also demonstrates the contribution of proper job planning and real-time monitoring to overcome operational problems expected while performing mini DSTs in low permeability and unconsolidated reservoirs, and describes methods for addressing those problems.

Pre-salt carbonates in the Pre-Caspian Basin have prolific hydrocarbon-bearing formations onshore and offshore. Recent exploration wells more than 5000 m deep in the region have had limited success, mostly due to challenging conditions for well testing. This paper summarizes key elements of one of the first successful drill stem testing (DST) campaigns in Ansagan Field. The holistic DST design for Ansagan field addressed perforating methods, brine selection, packer and DST equipments material selection for hostile environment with high-pressure, high-H2S fluids, and corrosive acid to be used for stimulation. The surface equipment design had to reliably control the well, separate fluids, measure flow rates, and dispose hydrocarbons with minimum environmental impact. Surface flow rate measurement combined of a multiphase flowmeter and three-phase separator. Downhole samples were collected with a single-phase reservoir fluid sampler. Calcium & zinc bromide brine with 1.77-SG density proved effective. The specially modified completion packer design was in the well up to 6 months and was successfully retrieved after the test. Although perforating in these deep high pressure wells was usually performed on wireline, accurate shock prediction and design adjustments managed the risk for using tubing-conveyed perforating (TCP) to perforate large intervals in underbalance conditions allowing to achieve lower skin, and flow the well immediately. The DST string enabled performing production logging, downhole fluid sampling, and acid stimulation with coiled tubing. Fluid sampling was performed on wireline to preserve gas condensate components at reservoir conditions. The highly accurate memory gauges, real-time operations, and reservoir engineer's support made it possible to acquire accurate data to characterize the fracture distribution, which is vital information in fractured carbonates. In summary, three wells have been successfully tested with a total of 16 zones at Ansagan field, achieving all well test objectives.

Gas deliverability estimation is very important in predicting effective gas-bearing regions and formulating reasonable development program. Conventional deliverability prediction method based on absolute open flow cannot be used in exploration wells due to the important input data of drill stem test (DST) data that cannot be first acquired. In this study, to establish reasonable model to predict exploration well deliverability, four core samples, drilled from the same tight sandstone reservoirs of northeast China, are applied for deliverability simulation experiment under formation condition. Gas flow rate and production data under different simulated drawdown pressures are acquired. A parameter of gas deliverability index, which is used to characterize gas production capability per well, is introduced. The relationships among gas deliverability index, reservoir physical properties (such as porosity, permeability and gas saturation) and drawdown pressure are analyzed. The results illustrate that for our target tight gas sandstone reservoirs, the optimal drawdown pressure is 5.0 MPa, and good relationship exists between gas deliverability index with the combined parameter of permeability and gas saturation. Based on this relationship, a model of predicting gas deliverability index from reservoir physical properties is established, and it is extended to field application to predict gas production. Comparison of predicted gas deliverability by using this model and acquired result from DST data illustrates the reliability of the established model.

This investigation was conducted to evaluate the beneficial reuse of post-consumer waste insulation materials in drilling and slurry applications. In particular, waste fibrous insulation was used to replace bentonite in slurry mixtures. Three civil engineering applications were considered for potential insulation waste reuse: drilled shaft/slurry trench construction, directional drilling, and vertical drilling. Effectiveness of slurries was assessed using conventional tests such as Marsh funnel viscosity, density, and filtrate loss. Filter cake thickness and filter cake permeability also were determined. Test results indicated that insulation materials could be used to replace up to 48% of bentonite in drilled shaft/slurry trench applications, up to 36% of bentonite in directional drilling applications, and up to 47% of bentonite in vertical drilling applications while maintaining acceptable engineering properties. Incorporation of waste insulation material in bentonite slurry mixtures is a viable beneficial reuse alternative.

Practical and improved ordinary differential models for compressible filter cake buildup involving small particle invasion and deposition inside the cake at static and dynamic conditions are developed by averaging particle and carrier fluid transport equations over the filter cake thickness. The models are simplified by considering that the panicles and carrier fluids involving many practical applications are incompressible. The results of radial and linear filtration cases are compared for constant rate and constant pressure drive filtrations. This thickness‐averaged ordinary differential model reproduces the predictions of the Tien et al. (1997) partial differential model rapidly with less computational effort. Parametric studies indicate that the particle screening efficiency of the filter is an important factor on the filter cake properties and filtration rate, and differences between linear and radial cake filtration performances are more pronounced, and the cake thickness and filtrate volume are smaller for constant pressure filtration than constant rate filtration. The equations of the thickness‐averaged linear and radial filter cake formation models are simple requiring less computational effort over the reported partial differential models for the analysis, design and optimization of the industrial cake filtration processes involving plate and drum filters.