Formation Test Research Articles

Quantitative mixing rules for downhole oil-based mud contamination monitoring in real time using multiple sensors

Abstract Accurate quantification of oil-based drilling mud (OBM) filtrate contamination of hydrocarbon samples is still one of the biggest challenges in formation fluid sampling with formation testers. There exist contamination quantification techniques, but they can be technique sensitive, lack a confident level of quality control and apply only to a limited combination of probe types and formation fluid types. In particular, current techniques rely on an assumed absence of mud filtrate coloration at relevant optical channels and on sufficient optical density contrast between mud filtrate and virgin fluids. Such assumed fluid properties may not materialize when, for example, drilling muds are reused in multiple wells or when virgin fluids exhibit little color due to the absence of asphaltenes. In this paper, new mixing rules have been developed for mass density and shrinkage factor and for the newly defined “ f -function” and “ q -function”. The f -function, also referred to as the modified gas/oil ratio, is essentially a combination of gas/oil ratio with shrinkage factor. Similarly, the q -function is referred to as modified composition and is a combination of composition with mass density. OBM filtrate contamination in volume fraction, optical density, f -function, mass density, shrinkage factor, and q -function at a specified downhole sampling station have been found to be mutually linearly related as predicted by the mixing rules. The mutually linear relations are further confirmed by laboratory data for different mixtures of mud filtrate and formation fluids. Application of these mixing rules enables accurate OBM filtrate contamination in hydrocarbon samples if the filtrate properties and virgin fluid properties can be determined. A new methodology has been developed to determine the properties of the virgin formation fluid and mud filtrate, which are referred to as endpoints. The mud filtrate properties are obtained by extrapolating the mutually linear relations established from the cleanup data to zero gas/oil ratio or other known filtrate values such as zero methane composition, and/or zero optical density at specified wavelengths. The virgin fluid properties are determined by the power-law fitting of cleanup data coupled with the flow regime identification which is confirmed by large number of downhole fluid analysis datasets from wireline formation testers and numerical simulation. This novel methodology enables accurate quantification of the OBM filtrate and pure virgin formation fluid. Furthermore, the self-consistency of using multiple independent sensors provides confidence and greatly improves the robustness and quality control of OBM filtrate contamination monitoring downhole. Finally, contamination results can be expressed in volume or weight percent and as live fluid or stock-tank liquid fraction for easy comparison to laboratory results. A latest generation downhole fluid analysis (DFA) tool was employed to measure fluid properties downhole in real time on more than 30 DFA stations acquired with either conventional probes or 3D radial probes. The new methodology was applied to each of the acquired datasets. All the results from the new method are in good agreement with the results of the laboratory analysis.

Introduction of sealing fault in Asmari reservoir by using FMI and RFT in one of the Iranian naturally fractured oil fields

Historically, in Iran, the borehole imaging tools are acquired to locate major structural features, such as faults, fractures, and sedimentary environment interpretation. The well GS-314 was drilled to evaluate the Asmari formation. It was drilled with an 8.5-in, vertical hole. To get a better understanding of reservoir characteristics of the Asmari formation on the Gachsaran field, to fullbore formation microimager (FMI), repeat formation tester (RFT) and a full set of open hole logs are acquired. The main objective of running FMI was to determine fracture characteristics and locate high porous layers/streaks so that points for RFT survey could be chosen for better results. In this study, it indicated a possible sealing/non-permeable fault in the Asmari reservoir in GS-314 of the Gachsaran field. The RFT pressure data indicated a change of 100 psi in the oil gradients across the fault, indicating possible reservoir compartmentalization in the area around well GS-314. The FMI images indicated a dense layer of 1 m thickness with a dip very different from the bedding around 2173.6 m in the Asmari reservoir. It was interpreted as a sealing fault based on the dense appearance of its plane. In this work, we will show you that how by using a combination of FMI and RFT can interpret a sealing fault in one of the Iranian naturally fractured oil fields.

Streamline-based inversion of formation properties from formation-tester measurements acquired in high-angle and horizontal wells

A new method is developed based on streamlines to determine the reservoir properties from formation-tester measurements. To do so, a previously developed finite-difference reservoir model is coupled with a streamline method to simulate the near-wellbore dynamic measurements in the presence of invasion and arbitrary fluid distributions. The streamline method is specifically developed to overcome technical challenges in modeling deviated wells in heterogeneous reservoirs efficiently. In this study, synthetic reservoir models are constructed based on measurements acquired in offshore well A with 15o deviation angle. The streamline-based method is then implemented to simulate packer-type formation-tester measurements and to appraise permeability of multi-layer reservoirs. In addition, transient measurements from a focused-sampling probe-type formation tester is modeled with streamline method to estimate relative permeability and anisotropy in offshore well B. Inversion results indicate that the accuracy of estimated formation properties is higher for formations with larger mobility because more streamlines trace flow into probes from large-mobility layers. For offshore well A, in the presence of 5% zero-mean Gaussian additive noise, the uncertainty of permeability varies from 6% to 38% for layers with high and low mobilities, respectively. The uncertainty increases to 8% and 41% for high and low mobility cases, respectively, when 5% skewed-Gaussian noise contaminates the measurements. The coupled finite-difference and streamline-based inversion method (FDSM) is then compared to a previously validated finite-difference reservoir model (FDM). The coupled FDSM is 8 times faster than FDM on an average when estimating properties of heterogeneous reservoirs using inversion on formation-tester measurements acquired in highly deviated wells. Computational advantage of FDSM is due to application of one-dimensional solutions of fluid saturations and concentrations along streamlines instead of three-dimensional FDM numerical calculations. Despite the efficiency, history matching of measurements indicates up to 6% difference between FDSM and FDM in results. In high-angle wells, mud-filtrate invasion causes a non-symmetric distribution of invading fluid around the wellbore perimeter. Moreover, presence of large permeability–porosity contrast among layers increases complexity of numerical computations and uncertainty. This study proposes that the streamline-based inversion method is an excellent candidate to overcome these difficulties efficiently.

Pressure Transient Solutions for Vertically Slotted-Partially Penetrated Vertical Wells in Porous Media

In this paper, we present semi-analytical pressure transient solutions for vertically slotted-limited entry or partially penetrated vertical wells. These solutions are needed for interpretation of the pressure transient tests conducted with the Wireline Formation Testing vertically slotted-packer configuration, and in wells with vertically slotted-liner completions. These slots have limited size openings and are vertically placed on a non-permeable cylindrical wellbore in a porous medium. The fluid from the formation is produced through these slots into the wellbore. Pressure transient solutions are not readily available for the uniform pressure boundary condition on the surface of the slots because such a condition creates a mixed boundary value problem, which is difficult to solve. Here we present exact pressure transient solutions obtained under the assumption that the pressure on the slot surface is uniform but a priori unknown, and the rest of the wellbore surface is non-permeable (no-flow condition). Furthermore, we generalize our solution for the case of multiple slots (open sections) on the wellbore for both well testing and Wireline formation tester packer modules. Our solutions are compared with the existing solutions. A new formula for obtaining the drawdown horizontal mobility is presented for anisotropic media.

Evolution of sediment permeability during burial and subduction

AbstractWe assembled a data set of permeability measurements from 317 subduction zone and reference site samples worldwide made over nearly 25 years of scientific drilling. This data set allowed us to examine the influence of grain size, structural domain, and measurement type on permeabilities ranging from 10−21 to 10−14 m2. We found that porosity–permeability behavior is a function of clay‐size fraction, which is consistent with previous work. Sediments within the slope, accretionary prism, and fault‐zone structural domains are strongly affected by shearing, which alters the permeability behavior with burial. Consolidation, flow‐through, and transient pulse decay measurements all provide comparable results. Measurements of horizontal and vertical permeability show significant cm‐scale permeability anisotropy (ratio of horizontal to vertical permeability >10) in the slope and accretionary prism structural domains, further indicating shear deformation in these domains. Laboratory consolidation trends match large‐scale (102 m) field trends in structural domains with negligible shear, but tend to underestimate the rate of permeability reduction with porosity loss where shear is significant. Comparison with downhole measurements shows that permeability is controlled by higher‐permeability (>10−15 m2) layers at the meter to tens of meters scale, while wireline formation tester measurements closely match laboratory results. Sediments from the underthrust and reference structural domains exhibit similar porosity–permeability trends, which suggests that shallow subduction (total burial <1 km) does not significantly alter the porosity–permeability behavior of incoming sediments. Comparison with measurements of deeper analog data from 14 passive‐margin samples show that porosity–permeability trends are maintained through burial and diagenesis to porosities <10%, suggesting that behavior observed in shallow samples is informative for predicting behavior at depth following subduction.

Formation evaluation in Dezful embayment of Iran using oil-based-mud imaging techniques

Structural delineation and fracture characterization are two of the main issues for the evaluation of carbonate reservoirs in structurally complex areas. Some of such fields are located in the southwest (Dezful embayment) of Iran. Getting to the Asmari reservoir is not so easy in some cases due to structural complexities where a thick pile of evaporites of Gachsaran Formation overly the reservoir. In such cases structural dip information plays an important role in mapping the structure in the area around the wells. In addition to structural complications, fracture characterization is quite important for Asmari carbonates and in particular for Sarvak carbonates. In most fields of the Dezful embayment, it is not feasible to drill wells with water-based mud, hence getting information on structural dip and fractures is not so easy with conventional borehole imaging tools. A combination of oil-based-mud imaging tools provided a new way of imaging the characteristics of formations drilled with oil-based-mud. Complicated structures were resolved utilizing the dip data gathered with such techniques. Fractures were characterized for their aperture (open or closed), intensity of fracturing, and directional attributes. The information helped to understand reservoir characteristics of tight carbonates of Sarvak formation. In addition to structural details, the OBM imaging provided quantitative Rxo (resistivity of invaded zone) measurement in oil-based-mud environment. It helped to understand invasion profiles, which generally is a function of permeability, in carbonate and sandstone reservoirs of Asmari Formation, and helped reservoir engineers and petrophysicists to understand response of reservoir formation tester (RFT) measurements for formation pressure and reservoir fluid mobility. The paper describes applications of OBM imaging in Asmari and Bangestan reservoirs of Dezful embayment of Iran.

The practice of graphical fluid-gradient interpretations of formation tester pressure data

This paper presents a novel graphical enhancement technique that can be easily practiced to interpret reservoir fluid gradients with formation pressure-test data. The method has various applications including mapping reservoir fluid nature and trends, identifying formation pressure changes because of facies changes, or the presence of baffles or barriers, and compartmentalization; diagnosing fluid-contact levels and transition-zone intervals; quality control of data; and judging the reliability of gradient interpretation. The scatter-plotting technique is very useful, not only for real-time decision making at the well site during both wireline- and drillpipe-conveyed formation-tester operations, but also in routine data interpretation and reservoir studies with petrophysical logs, pressure, and fluid data.

Sampling with new focused, oval, and conventional probe-type formation-tester in the presence of water- and oil-base mud-filtrate invasion for vertical and high-angle wells

Abstract Speculation about the potential of developing new fluid and pressure sampling methods with probe-type formation testers has existed since the introduction of formation pressure testing while drilling technology was introduced to the industry nearly a decade ago. To replace the existing wireline technology, a new pumping system is required to remove invasion fluids and then to fill single-phase sample chambers. To make this commercially possible, several technology enhancements are necessary in advance. Although wireline pumpout tools may require hours to retrieve representative fluid samples, it is not a practical alternative to spend hours obtaining samples in the drilling environment. Most simulations of wireline formation-tester measurements assumed that invasion ended at the time when fluid pumpout began. Additionally, previous studies assumed a time-constant rate of invasion that was the time average of invasion rate. Both of these assumptions are optimistic for a drilling tool. The objective of this study is to quantify the viability of sampling in the drilling environment by way of numerical simulations. The study considers the dynamic nature of invasion while drilling when using both new and conventional probe configurations to retrieve fluid samples. With the realistic mudcake model, there are higher rates of invasion soon after drilling. Therefore, to simulate the invasion during drilling, a mudcake model is used that continues to grow in thickness and sealing effectiveness during invasion and throughout the sampling process. Simulation results focus on scenarios in which water-base mud (WBM) and oil-base mud (OBM) invade an oil-bearing zone. Furthermore, it studied the accuracy of functions used to estimate contamination in an OBM environment. The base model consists of a typical probe-type tool in a vertical well wherein fluid samples are retrieved using a time-constant flow rate. Invasion time is varied from 1 to 48 h to compare drilling and wireline sampling tools. Simulations of fluid cleanup times for a variety of rock types and wellbore deviation angles indicate that the oval focused probe retrieves the cleanest fluid sample in the least amount of time. This study also quantifies mudcake sealing effectiveness, as well as the effect of borehole deviation. Oval (elongated) and focusing guard-style probes are compared to standard probe configurations in various petrophysical rock types.

Detection of overpressure zones and a statistical model for pore pressure estimation from well logs in the Krishna-Godavari Basin, India

Abnormally high pressures, measured by repeat formation tester (RFT) and detected by well log data from 10 wells in the Krishna-Godavari (K-G) Basin, occur in the Vadaparru Shale of Miocene and Raghavapuram Shale of Early Cretaceous age. Overpressures generated by disequilibrium compaction, and pore pressures have been estimated using the conventional Eaton sonic equation with an exponent of 3.0. The observed abnormal pore pressure gradient ranges from 11.85 to 13.10 MPa/km, whereas fracture pressure gradient varies from 17.40 to 19.78 MPa/km. The magnitude of vertical stress (Sv) has a gradient from 21.00 to 23.10 MPa/km. The minimum horizontal principal stress (Sh) magnitude is found to vary from 64 to 77% of the Sv in normally pressured to overpressured sediments. A multiple linear regression model with a squared multiple correlation coefficient (R2) of 0.94 is proposed for pore pressure prediction from gamma ray, density and sonic logs to focus on efficient drilling operations and to prevent borehole instability. The statistical model has been calibrated with the RFT data from five wells covering about 3400 sq. km area of the onshore K-G Basin. The model predicted pore pressure values are in close agreement with the actual RFT data for another four wells including a well in the offshore K-G Basin. Hence, the proposed regression model may be useful for predicting pore pressure from other well logs in the K-G Basin.

History Matching the Norne Full-Field Model Using an Iterative Ensemble Smoother

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 164902, ’History Matching of the Norne Full-Field Model Using an Iterative Ensemble Smoother,’ by Yan Chen, SPE, International Research Institute of Stavanger, and Dean S. Oliver, SPE, Uni Center for Integrated Petroleum Research, prepared for the 2013 EAGE Annual Conference and Exhibition/SPE Europec, London, 10-13 June. The paper has been peer reviewed and is scheduled for publication in the SPE Reservoir Evaluation & Engineering journal. This paper describes the application of the iterative ensemble smoother to the history matching of the Norne field in the North Sea, which has a moderately large number of wells, a variety of data types, and a relatively long production history. Particular attention is focused on the problems of identification of important variables, generation of an initial ensemble, plausibility of results, and efficiency of minimization. Introduction The Norne field produces from an oil and gas reservoir discovered in 1991 offshore Norway. The full-field model consists of four main fault blocks that are in partial communication and many internal faults with uncertain connectivity in each fault block. There have been 22 producers and nine injectors in the field. Water-alternating- gas injection is used as the depletion strategy. Production rates of oil, gas, and water of the 22 producers from 1997 to 2006 and repeat formation tester (RFT) pressure from 14 wells are available for model calibration. The full-field simulation model has 22 layers, each with dimension of 46×112 cells. The total number of active cell is approximately 45,000. The Levenberg-Marquardt form of the iterative ensemble smoother [Levenberg- Marquardt ensemble randomized maximum likelihood (LM-EnRML)] is used for history matching the Norne full-field model using production data and RFT pressure. The model parameters that are updated include permeability, porosity, and net-to-gross ratio at each gridblock; vertical transmissibility at each gridblock for six layers; transmissibility multipliers of 53 faults; endpoint water and gas relative permeability of four reservoir zones; depth of water/oil contacts; and transmissibility multipliers between a few main fault blocks. The total number of model parameters is approximately 150,000. Distance-based localization is used to regularize the updates from the LM-EnRML. The LM-EnRML is able to achieve improved data match compared with the manually history matched model after three iterations. Updates from the LM-EnRML do not introduce artifacts in the property fields as are produced in the manually history matched model. The automated workflow is also much less labor intensive than manual history matching. Ensemble-based methods use information from an ensemble of reservoir models to compute directions of change to the model. The most popular of these methods, the ensemble Kalman filter (EnKF), has been successfully applied on synthetic test cases in which well-bywell data match required many degrees of freedom.

Fertility Preference Inversely Related to ‘Legacy Drive’ in Women, But Not in Men: Interpreting the Evolutionary

This paper used finite element method to simulate the pressure response of wireline formation tester applied in fractured reservoir. At first, the interval pressure transient tests (IPTT) are used to test the pressure response for both crossing well bore and non-crossing fractures in low permeability formation. The simulation results indicate that the fractures crossing the well bore can have dramatic effect on pressure response depending on fractures conductivity, but non-crossing fractures in the vicinity of the well bore have negligible effect. Then the paper used numerical simulation to analyze the feasibility that evaluates the fractures non-crossed well bore with the method of harmonic pulse testing, the results indicate both harmonic amplitude and phase shift are sensitive to the conductivity of fractures in the vicinity of well bore and certify the method can be used to evaluate the fractures efficiently.

Interpreting Reservoir Permeabilities from Wireline Formation Test Data

In order to provide accurate permeabilities of reservoirs for productivity estimate in offshore oil fields, in this study a semianalytical model of unsteady ellipsoidal flow and a numerical simulation algorithm have been developed to interpret wireline formation test data. The model is derived from basic principles of fluid mechanics in porous medium, and the time variation of test flows and anisotropy of formations are both taken into account. The approaches had been applied successfully to interpreting the test data of a new pumpout wireline formation tester, and the results show the validity of the new method presented.

Fluid Identification in Light Hydrocarbons With Use of NMR and Downhole Fluid Analyzers—A Case Study

SummaryIn hydrocarbon reservoirs, fluid types can often vary from dry gas to volatile oil in the same column. Because of varying and unknown invasion patterns and inexact clay-volume estimations, fluid-types differentiation on the basis of conventional logs is not always conclusive. A case study is presented by use of advanced nuclear-magnetic-resonance (NMR) techniques in conjunction with advanced downhole-fluid-analysis (DFA) measurements and focused sampling from wireline formation testers (WFTs) to accurately assess the hydrocarbon-type variations.The saturation-profiling data from an NMR diffusion-based tool provides fluid-typing information in a continuous depth log. This approach can be limited by invasion. On the other hand, formation testers allow taking in-situ measurements of the virgin fluids beyond the invaded zone, but at discrete depths only. Thus, the two measurements ideally complement each other.In this case study, NMR saturation profiling was acquired over a series of channelized reservoirs. There is a transition from a water zone to an oil zone, and then to a rich-gas reservoir, indicated by both the DFA and the NMR measurements. Above the rich gas, is a dry-gas interval that is conclusively in a separate compartment. Diffusion-based NMR identifies the fluid type in a series of thin reservoirs above this main section, in which no samples were taken. NMR and DFA both detect compositional gradients, invisible to conventional logs.The work presented in this paper demonstrates how the integration of measurements from various tools can lead to a better understanding of fluid types and distribution.

Determination of Some Reservoir Characteristics of the Bahariya Formation in Bed-1 Field, Western Desert, Egypt, by Using the Repeat Formation Tester

Repeat formation tester (RFT) data are used for interpreting some reservoir characteristics such as the nature of fluids and permeability for the Bahariya formation by using five wells in the Bed-1 Field in the Western Desert of Egypt. The Schlumberger RFT is an open hole wireline device showing a continuous recording of the pressure leads to construct the pressure gradient. These gradients give information about the fluid density and then the nature of fluids (gas, oil, and water). Also the depths of contacts between water and hydrocarbon products can be located by the abrupt change in the pressure gradients. The permeabilities of Bahariya formation are evaluated qualitatively by the direct interpretation of the pressure curve recorded at each test and quantitatively by the analysis of drawdown pressure data. Moreover, the porosities of reservoir rocks were determined by using the available logs of density and neutron. These porosities were corrected for the effect of shale. Also, the saturation of hydrocarbon is determined and then these values of porosities and saturation of hydrocarbon are presented zonewise to show their vertical variation within the wells.

Formation-Tester Pulse Testing in Tight Formations

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 155037, ’Formation-Tester Pulse Testing in Tight Formations (Shales and Heavy Oil): Where Wellbore-Storage Effects Favor the Determination of Reservoir Pressure,’ by Hamid Hadibeik, SPE, The University of Texas at Austin; Mark Proett, SPE, Dingding Chen, SPE, and Sami Eyuboglu, SPE, Halliburton; and Carlos Torres- Verdin and Rooholah A. Pour, The University of Texas at Austin, prepared for the 2012 SPE Americas Unconventional Resources Conference, Pittsburgh, Pennsylvania, 5-7 June. The paper has not been peer reviewed. Tight-formation testing, when mobilities are lower than 0.01 md/cp, poses significant challenges because conventional pressure-transient buildup testing becomes impractical because of the long buildup-stabilization time. An automated-pulse-test method is introduced for testing tight formations. It reduces testing time significantly and makes determination of formation pressure and permeability possible. Based on pressure data during the shut-in period, the next drawdown or injection test is designed such that the flow rate is a fraction of the initial pulse rate, followed by another shut-in test. This procedure continues until the difference in pressure at the beginning and at the end of the shut-in period is reduced to within a specified limit of pressure change; then, an extended transient is recorded to a stabilized shut-in pressure. Introduction Reservoir properties, such as formation pressure and permeability, can be measured with formation testers. Fluid sampling in laminated reservoirs under the influence of dynamic mud-filtrate invasion was tested by use of various probe-type formation testers. A complication in testing tight formations is that the measured pressure is supercharged and is greater than the reservoir pressure. The measured shut-in pressure usually is assumed to be the formation pressure. In a permeable formation, mudcake can form quickly and normally is very effective in slowing down invasion and maintaining the wellbore-sandface pressure near the formation pressure. However, this assumption is unrealistic, especially in low-mobility formations for which there could be no sealing mudcake to isolate the reservoir from hydrostatic pressure. In tight formations, the invasion rate is slowed by the formation, and mudcake may form slowly or not at all. As a result of the lack of sealing mud-cake, the pressure measured in these cases is substantially greater than the formation pressure. A pulse-test technique was used in combination with the spherical-flow model to obtain the true formation pressure. The early transient- and spherical-flow period can be distinguished from the late-transient-flow period by calculating the stream-line evolution of flow near the source. To measure the reservoir pressure in tight-formation testing, current technologies require several hours of wait time to reach the stabilized pressure, but often it is difficult to reach stabilization or to determine when it occurs. The automated-harmonic-testing method introduced here reduces the testing time substantially when a packer- or probe-type formation tester is used, and it automatically converges to the shut-in pressure.

Generalized poroelastic wellbore problem

SUMMARYThis paper presents a novel analytical solution to the transient, z‐dependent, and asymmetric problem of an infinite wellbore drilled into a fluid‐saturated porous medium. The formulations are based on Biot's linear theory of poroelasticity, in which the dependency of poroelastic field variables to spatial coordinates as well as time domain is considered in the most general form. This gives flexibility to the solution in cases that cannot be analyzed using the conventional plane strain or symmetric models. One such case is when calculating the stress variations around an inclined wellbore where the far‐field stresses are acting over a finite vertical section. The results of our solution to this case with a three‐dimensional state of far‐field stress are used to analyze the stability of inclined wellbores passing through abnormally stressed formations.The presented solution is capable of finding expressions for fundamental solutions with stress or flow boundary conditions at the wellbore. These solutions are here adopted to analyze the pressure disturbances generated by multiprobe formation tester, a standard wireline device that is designed for downhole fluid sampling as well as estimating the directional permeabilities of subsurface earth formations. A comparison with the conventional solution for the relevant pressure diffusion equation indicates that the poroelastic effect is relatively significant in relation to the transient response of the pore pressure. Further, it is shown that the finite dimensions of sink probe would, to a great extent, contribute to the formation's pore pressure variations at its immediate proximity. Copyright © 2013 John Wiley & Sons, Ltd.

Defining net reservoir using the dual packer wireline formation tester: a case study from the Clio, Acme, and Acme West fields

The Clio, Acme, and Acme West gas fields lie in the WA-42-R permit in the Carnarvon Basin, offshore WA. The reservoirs at the Clio, Acme, and Acme West fields generally have excellent reservoir characteristics with multi-Darcy permeabilities. Some additional potential may occur in more marginal-quality reservoirs. To determine the potential of the marginal sands, a dual packer wireline formation tester (WFT) was used to constrain petrophysical cut-offs of the target Mungaroo and Brigadier formations, which consist of fluvial and deltaic reservoirs. A decision-based approach in the application of the dual packer WFT has allowed for systematic evaluation of the dynamic behavior of each depositional environment at proposed reservoir cut-offs, and has provided insight into the flow mechanisms controlling productivity in the near-well environment The controls on reservoir quality between these two depositional environments are very different. The fluvial reservoirs are characterised by large ranges of permeability variation for very small changes in porosity as a function of grain-size variation. The dual packer WFT stations conducted in the Clio–3 fluvial sands demonstrate the role of entry pressure to gas charge, and allowed for the quantification of the minimum total porosity needed for net reservoir to be present in the well The sands in the sand/shale laminae of the deltaic environment have much less reservoir quality variation than the sands in the fluvial system. Reservoir quality is controlled by the connectivity of these sands both laterally and vertically. Sand connectivity is inferred from neutron density crossover, and is tested with dual packer WFT stations at Acme West–2 The integration of data gathered at the Clio–3 and Acme West–2 dual packer WFT stations has been used to establish net-to-gross cut-offs applied to these reservoirs

Pressure transient solutions to mixed boundary value problems for partially open wellbore geometries in porous media

In this paper we present semi analytical pressure transient solutions for a limited-thickness open cylindrical production ring (often called limited entry or partially penetrated) on a non-permeable cylindrical wellbore in a porous medium which is used for fluid withdrawal (production) from the formation. Solutions are not readily available for the uniform-pressure boundary condition on the open cylindrical ring surface because such a condition creates mixed boundary value problem (MBVP) which is difficult to solve. It is well known that the approaches presented over the years for partially penetrated wells are based on the uniform-flux line source solutions for which the middle point, the equivalent-pressure point, or pressure averaging is used to approximate the uniform-wellbore-pressure boundary condition. Here we present exact pressure transient solutions obtained under assumption that the pressure on the open surface is uniform but a priori unknown and the rest of the wellbore surface is non-permeable (no-flow condition). Furthermore, we generalize our solution for the case of multiple production sections on the wellbore for both well testing and Wireline formation tester packer modules.To solve MBVP, we write it in the form of a dual-integral equation. Next, using the special set of basis functions for representing the flux density on the open surface, we reduce it to an infinite system of linear algebraic equations with a symmetric diagonally dominated matrix. These properties of the matrix together with the singular nature of basis functions ensure very fast convergence of the truncated solutions to their limit, thus only a few equations can be considered and the system can easily be solved numerically.The solutions presented in this paper are also compared with the middle point, equivalent-pressure point, and pressure-averaging solutions given in the petroleum literature.

Rock Mechanics Parameters Calculation of the Fractured Rock Based on the Effective Media Theory with Well Logging

Fractured rocks are the main oil and gas exploration objects offshore in China in recent years, which include the fractured sandstone, carbonate, volcanic rock, coal methane bed, shale gas and so on. The accurate calculation of the rock mechanics parameters (elastic modulus and Poisson’s ratio) play remarkable role in petroleum engineering operations, such as borehole stability, mud density window determination, perforation, EOR, in-situ stress predication and so on. Now the applications show that the in-situ stress estimation based on the rock parameters obtained by acoustic logging is much different from the downhole measurement with wireline formation tester. The pore space of the fractured rock contains fracture and cave and it is different from sandstone. In the paper a novel method based on the effective media theory with well logging for the rock mechanics parameters calculation of the fractured rock is introduced, and some problems and potential application are also discussed.

Effect of liquid invasion damage and supercharging on wireline formation tester measurements in tight gas reservoirs

Wireline formation testing and measurement of true formation pressure can provide essential knowledge about the reservoir dynamic characteristics. In tight formations, a reliable determination of pressure and mobility gradients is challenging because of the tight nature of formation rock. Due to the very low reservoir permeability, the mud cake across wellbore is often ineffective in preventing filtrate invasion, thus causing the measured pressure to be higher than actual formation pressure as a result of supercharging effect. Wireline formation testing measurements are also influenced by the effects of filtrate invasion and capillary pressure, as the measured pressure is pressure of drilling fluid filtrate, the continuous phase present in the invaded region around wellbore. As a result, the measured pressure might be different to true formation pressure. This effect is more noticeable in tight gas reservoirs due to capillary pressure effect. This paper looks into estimation of true formation pressure and evaluates the effect of filtrate invasion damage and supercharging on wireline formation tester measurements in tight gas reservoirs. Numerical simulation approach is used to build the reservoir model based on data acquired from a tight gas reservoir. The model undergoes water injection followed by gas production from different testing points along the wellbore, and the corresponding pressure gradients are plotted to check for pressure matching with that of the formation fluid in the virgin region. The results indicate the significant effects of supercharging, reservoir characteristics, capillary pressure and liquid invasion damage on wireline formation pressure measurements in tight gas reservoirs.