Wireline Formation Tester Research Articles

Equation-of-State-Based Downhole Fluid Characterization

Summary Downhole fluid analysis (DFA), together with focused-sampling techniques and wireline-formation-tester (WFT) tools, provides real-time measurements of reservoir-fluid properties such as the compositions of four or five hydrocarbon components/groups and gas/oil ratio (GOR). With the introduction of a new generation of DFA tools that analyze fluids at downhole conditions, the accuracy and reliability of the DFA measurements are improved significantly. Furthermore, downhole measurements of live-fluid densities are integrated into the new tools. Direct pressure and temperature measurements of the flowline ensure capture of accurate fluid conditions. To enhance these advanced features further, a new method of downhole fluid characterization based on the equation-of-state (EOS) approach is proposed in this work. The motivation for this work is to develop a new approach to maximize the value of DFA data, perform quality assurance or quality control of DFA data, and establish a fluid model for DFA log predictions along with DFA fluid profiling. The basic inputs from DFA measurements are weight percentages of CO2, C1, C2, C3–C5 and C6+, along with live-fluid density and viscosity. A new method was developed in this work to delump and characterize the DFA measurements of C3–C5 (or C2–C5) and C6+ into full-length compositional data. The full-length compositional data predicted by the new method were compared with the laboratory-measured gas chromatograph data up to C30+ for more than 1,000 fluids, including heavy oil, conventional black oil, volatile oil, rich gas condensate, lean gas condensate, and wet gas. These fluids have a GOR range of 8–140,000 scf/STB and a gravity range from 9 to 50°API. A good agreement was achieved between the delumped and gas-chromatograph compositions. In addition, on the basis of the delumped and characterized full-length compositional data, EOS models were established that can be applied to predict fluid-phase behavior and physical properties by virtue of DFA data as inputs. The EOS predictions were validated and compared with the laboratory-measured pressure/volume/temperature (PVT) properties for more than 1,000 fluids. The GOR, formation-volume factor, density, and viscosity predictions were in good agreement with the laboratory measurements. The established EOS model then was able to predict other PVT properties, and the results were compared with the laboratory measurements in good agreement. Consequently, the established EOS models have laid a solid foundation for DFA log predictions in DFA fluid profiling, which has been integrated successfully with DFA measurements in real time to delineate compositional and asphaltene gradients in oil columns and to determine reservoir connectivity. The latter results are beyond the scope of this work and have been given in separate technical papers.

Estimating Thickness-Independent Horizontal and Vertical Permeabilities With Packer/Probe Wireline Formation Testers

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 13912, ’A Novel Analysis Procedure for Estimating Thickness- Independent Horizontal and Vertical Permeabilities From Pressure Data at an Observation Probe Acquired by Packer/ Probe Wireline Forma tion Testers,’ by M. Onur, SPE, Istanbul Technical University, and P.S. Hegeman, SPE, I.M. Gok, SPE, and F.J. Kuchuk, SPE, Schlumberger, pre pared for the 2009 International Petroleum Technology Conference, Doha, Qatar, 7-9 December. The paper has not been peer reviewed. A spherical-flow cubic-analysis procedure has been developed for estimating horizontal and vertical permeabilities, kvh and kv, respectively, solely from pressure-transient data acquired at an observation probe of a dual-packer/probe wireline formation tester (WFT) for any wellbore-inclination angle. The procedure is based on an analytical spherical-flow equation and a conventional spherical-flow-analysis graph of the observed drawdown or build-up pressures. The procedure does not require knowledge of the formation thickness, h, or observing the radial-flow regime at the probe. Introduction Over the last 4 decades, wireline formation testing has become widely accepted for reservoir-pressure pro-filing, fluid sampling and identification, interval-pressure-transient tests (IPTTs), and in-situ stress testing. IPTTs conducted with packer/probe formation testers provide dynamic permeability and anisotropy information with high vertical resolution along the wellbore. Permeability is one of the most important parameters in reservoir management and well performance. Permeability and permeability anisotropy (kv /kh ratio) strongly affect all reservoir-displacement processes. Thus, it is increasingly important to determine these values as operators shift their focus from primary recovery to secondary and tertiary recovery. Fig. 1 shows a schematic of a packer/probe interference test (usually referred to as an IPTT) in a deviated well in an anisotropic formation that is bounded vertically and is laterally infinite. The schematic represents a general configuration that is valid for all inclination angles, θw, of the well-bore. For instance, if θw=0°, the IPTT is considered conducted in a vertical well, whereas if θw=90°, the IPTT is considered conducted in a horizontal well. In these tests, a dual packer is set against the formation to serve as a flow source. The pressure transients are measured at both the packer interval and the observation probe. Any pressure change at the observation probe caused by flow from the packer interval clearly indicates communication within the formation between the two locations. Interpretation of packer and probe data provides permeability values in both the vertical and horizontal direction. Furthermore, the near-wellbore heterogeneity can be characterized from IPTTs. Interpretation of packer/probe IPTT data begins with an independent analysis of each pressure data set. The first step is to identify the flow regimes on the basis of conventional pressure-derivative analysis. Then, initial estimates of parameters such as spherical and horizontal permeabilities are obtained from special straight-line (semilog and spherical) analyses based on flow regimes identified from the log-log diagnostic graphs of the draw-down/buildup and/or deconvolved responses. Construction of a formation model from existing openhole-log data is essential for the interpretation. Log data provide porosity and rock compressibility, while fluid analysis provides fluid compressibility and viscosity. All available data (including log, core, and pretests) are used for parameter initialization of the formation model before nonlinear-regression analysis. Then nonlinear-regression analysis is performed to optimize the key parameters such as horizontal and vertical permeabilities, skin, and wellbore- or tool-storage coefficient. The final step of the analysis involves verification and sensitivity analyses of the history matches of the pressure data.

Technology Focus: Reservoir Performance and Modeling (September 2010)

Technology Focus Understanding and management of subsurface uncertainties are crucial for successful development of early-phase projects. The development solution, drive mechanism, processing capacities, and number of slots needed all affect the net present value and the capital and operating expenses. Planning and execution of early-phase data acquisition and the effect these data have on late-life economics are a theme that deserves more attention. Concept selection is the most important part of an early-phase development from a subsurface point of view. Because of the high well cost, deepwater projects are sanctioned with few appraisal wells and limited dynamic information. The importance of an overall strategy to manage subsurface uncertainties is described in the paper regarding the development of the greater Plutonio area. Dynamic information, both horizontal and vertical permeability, is always on top of every reservoir engineer’s wish list. Wireline formation testing is a cost-effective way of addressing dynamic information, keeping in mind that an extended well test or a drillstem test is not always feasible for economic or practical purposes. Determination of remaining oil is key to increased oil recovery. A proactive approach to surveillance gives insight into the reservoir and has potential to mitigate unpleasant surprises. The paper describing the proactive well and reservoir management and the paper assessing fluid migration and quantifying remaining-oil saturation are both excellent examples of creating value through systematic reservoir surveillance. Reservoir Performance and Monitoring additional reading available at OnePetro: www.onepetro.org IPTC 13640 • “Successful Reservoir Monitoring With 4D Microgravity at Ras Laffan, State of Qatar” by A.F. AhmadZamri, SPE, RasGas Company, et al. IPTC 13185 • “Reservoir Modeling and Production Evaluation in Shale-Gas Reservoirs” by C.L. Cipolla, SPE, Carbo Ceramics, et al. SPE 127858 • “Perdido: The First Smart Field in the Western Hemisphere” by Robert K. Perrons, SPE, Shell. SPE 128137 • “Integrated-Production-Model Calibration Applied to a Gulf of Mexico Subsea Field” by L. Saputelli, SPE, Hess Corporation, et al.

A New Pressure/Rate-Deconvolution Algorithm To Analyze Wireline-Formation-Tester and Well-Test Data

Summary Reconstructing constant-rate drawdown-pressure response and its logarithmic time (or Bourdet) derivative by deconvolution from multirate pressure-transient data is very important for wellbore-/ reservoir-system identification and interpretation. In recent years, the use of pressure/rate deconvolution has increased considerably because of significant improvement of the algorithms. In this paper, we present a new deconvolution algorithm based on a weighted Euclidean norm in the Tikhonov (1963) regularized objective function so that one can assign weights to individual pressure- and rate-measurement points, and, thus, define different error estimates for different sections of the data. Incorporating such features into the deconvolution algorithm is very useful to mitigate the effects of unreliable pressure and rate measurements and the sections of the data not obviously consistent with the wellbore/reservoir model. We present two applications of the new algorithm using real field pressure/rate transient data sets. In addition to conventional drillstem-test (DST) well-test data, we apply the algorithm to wireline formation-tester (WFT) pressure transients, which are usually also referred to as interval pressure-transient tests (IPTTs). The results show that the new deconvolution algorithm presented in this paper is useful in interpreting pressure/rate transient data from both formation and well tests.

Fluid-Pressure Gradients in Tight Formations

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 121982, ’Fluid- Pressure Gradients in Tight Formations,’ by J.A. Larsen, SPE, Statoil/ Consultant, and H. Urkedal and A. Lonoy, Statoil, prepared for the 2009 SPE Europec/EAGE Annual Conference and Exhibition, Amsterdam, 8-11 June. The paper has not been peer reviewed. Economical production from low-permeability reservoirs is a challenge. The oil/water contact (OWC) may not be at a precise level in the reservoir, and the vertical span of the oil/water transition zone may be large in such reservoirs. Traditionally, the free-water level (FWL) and, hence, the water and oil zones are determined from the oil- and water-pressure gradients. Pressure gradients are, however, difficult to obtain in low-permeability media, and supercharging effects may be the result of mobile oil and water being at the same place in the reservoir. Introduction In the studied cases, vertical equilibrium between gravity and capillarity could imply that a large zone exists between oil and water that is frequently called the “oil/water transition zone” or “capillary-transition zone.” The fluid gradient derived from wireline-formation-tester (WFT) measurements showed a water gradient in the studied reservoir. The 130-m-thick vertical section was evaluated to have oil saturation generally higher than expected for residual-oil saturation, although the heterogeneous nature of the reservoir prohibited any direct conclusions. The main objective was, from a conceptual approach, either to verify a consistent relationship between water gradient and residual oil (paleozone) or, if no such conclusion could be made, try to quantify oil mobility. Only wells drilled with water-based mud were considered. Initial Fluid Distribution in the Transition Zone. The capillary-transition zone can be defined as regions in the reservoir in which both oil and water are present, the water saturation is higher than the connate-water saturation, and the oil saturation is higher than the residual-oil saturation (i.e., both phases are mobile). Such regions need special attention for characterizing the initial conditions and for designing special-core-analysis programs for generating input data for dynamic simulations. The precision of production forecasting for primary-, secondary-, or tertiary-recovery methods relies on the proper description of the initial conditions in the reservoir. Three types of initial fluid distributions can be defined and classified according to their distinct behavior. The main challenges are to select the correct oil/water capillary pressure function for deriving the water saturation and to find the correct position of the FWL. The OWC will, in most cases, be imprecise, and reference should always be made to the FWL, which may be above or below the OWC (deepest mobile oil).

Characterization of Reservoir Heterogeneity Through Fluid Movement Monitoring With Deep Electromagnetic and Pressure Measurements

Summary This paper presents a novel technique to characterize detailed formation heterogeneity for a carbonate reservoir using measurements from electrode resistivity array (ERA), a wireline formation tester, and a permanent downhole pressure sensor. The ERA was installed on tubing in a barefoot well rather than permanently cemented outside the casing as in previous applications. This notable difference provided flexibility for device installation and operation but also introduced particular issues in the ERA data acquisition and interpretation. Furthermore, the ERA measurements were carried out in conjunction with low-salinity water injection and oil and water production in the same well. The primary finding presented in this paper is that the time-lapse ERA voltages near a source electrode showed unique characteristics that represented local formation heterogeneity. This localized sensitivity of ERA data allows detailed characterization of the formation heterogeneity within the length of the ERA string in the vertical direction and about 100 ft laterally around the wellbore. The scale size of the investigated formation heterogeneity is comparable to typical grid sizes used in current reservoir simulations. Models were developed to identify stratified permeability heterogeneities from the time-lapse ERA voltages. The stratified heterogeneity estimated from the ERA measurements was compared to and verified by openhole logs and core analyses data. The final heterogeneous reservoir model from the ERA was subsequently applied to a numerical simulation that integrated the dynamic fluid flow, salt transport, and electrode array responses for monitoring water-front movement and estimating multiphase formation properties. The history matching of the time-lapse ERA data confirmed the first pass estimates of the identified heterogeneities.

Technology Focus: Well Testing (February 2010)

Technology Focus The advent of computer-aided analysis, derivatives, and deconvolution over the last 3 decades produced a dramatic change in the way we looked at well testing: from a mere well-performance indicator to a powerful reservoir-characterization tool. Well testing is a technical “masterpiece” when it comes to the assessment and exploitation of complex reservoir architectures and frontier assets. Yet, multiple challenges lie ahead of us, from ultradeep wells to subsea subsalt developments with increasing environmental concerns; these are indeed exciting times for the field. This brings me to the theme of this feature. Well-test analysis continues to push the boundaries of reservoir characterization on all fronts, leading to improved interpretation techniques for unconventional resources, intricate deepwater test programs, and accelerated use of high-resolution-simulation models. In the early 1960s, we would, literally, calculate permeability and skin by use of straight lines on a graph with a pencil. Nowadays, and with the help of better gauge metrology, we are opening a new chapter in the use of well testing for reservoir characterization and proactive field management. Some people have even suggested that we should expand the definition of well testing to include measurements other than pressure. Take, for instance, temperature. Technologies such as distributed-temperature sensing are maturing at a relatively rapid pace, bringing more insights into dynamic-flow description. As well testing strives to advance and overcome the enormous challenges of today, we need to take a moment and peek outside our tree to see the forest. The papers selected for this feature and those in the reading list are a clear illustration of these latest endeavors. I hope that you will find them of interest. Well Testing additional reading available at OnePetro: www.onepetro.org SPE 123982 • “A New Pressure/Rate Deconvolution Algorithm To Analyze Wireline-Formation Tester and Well-Test Data” by Evgeny Pimonov, Schlumberger, et al. OTC 19767 • “Use of Dynamic Simulation To Refine Well-Testing Procedures and Optimize the Data Required for Deconvolution Techniques” by J.C. Mantecon, SPT Group, et al. SPE 124271 • “The Value of Well Testing—Optimization of the West Brae Field” by Mike Tharagonnet, SPE, Marathon Oil

Green Methodologies to Test Hydrocarbon Reservoirs

Problem statement: The definition and the economic viability of the be st development strategy of a hydrocarbon reservoir mainly depend o n the quantity and type of fluids and on the well productivity. Well testing, consisting in producing hydrocarbon to the surface while measuring the pressure variations induced in the reservoir, has b een used for decades to determine the fluid nature and well potential. In exploration and appraisal sc enarios the hydrocarbons produced during a test are flared, contributing to the emissions of greenhouse gases. Approach: Due to more stringent environmental regulations and a general need for re duced operating expenses, the current industry drivers in today's formation evaluation methodologi es demand short, safe, cost-effective and environmentally friendly test procedures, especiall y when conventional tests are prohibitively expensive, logistically not feasible or no surface emissions are allowed. Different methods have been proposed or resuscitated in the last years, such as wireline formation tests, closed chamber tests, production/reinjection tests and injection tests, a s viable alternatives to conventional well testing. Results: While various short-term tests, test procedures an d interpretation methods are apparently available for conducting successful tests without h ydrocarbon production at the surface, clarity is lacking for specific applications of these techniqu es. An attempt to clarify advantages and limitation s of each methodology, particularly with respect to t he main testing target is pursued in this study. Specific insight is provided on injection testing, which is one of the most promising methodology to replace traditional well testing in reservoir chara cterization, except for the possibility to sample t he formation fluids. Conclusion/Recommendations: Not a single one method but a combination of more methodologies, in particular injection testing and wireline formation testing, is the most promising strategy to achieve all the targets of a convention al well testing with no surface hydrocarbon production, increased safety during operations and reduction of the testing costs

A Cost Effective and User Friendly Approach to Design Wireline Formation Tests

Problem statement: Wireline formation testing (also named Mini-DSTs) are gaining more and more popularity as a possible alternative to co nventional well testing especially where there are major environmental and economical constraints. The increased offshore exploration activity, which often implies highly risky and huge operational cos ts, makes the conventional well testing less attractive in favor of other technologies that can provide some of the key dynamic information about the well-reservoir system through relatively quick and less expensive operations. The design phase is recognized to be one of the most critical aspects i n order to guarantee an acceptable value of information in exploration scenarios where very lim ited data is available. The success of any mini- DST operation can be significantly compromised if t wo major issues are not addressed in the design phase: possibility to clearly identify the radial f low behavior and avoidance of noise in the pressure response due to the gauge resolution. Approach: The study consisted in the development of a new too l for mini-DST design to easily identify whether this technology can be successfully applied. The tool comprises dimensionless and dimensional charts, which are of general validity because they can be applied to any lithological environment and for any type of hydrocarbon. Results: Field applications proved the reliability of the charts: First of all the test durations were optimized to collect interp retable bottomhole pressures and to obtain valid reservoir characterizations. Besides, a cost saving effectiveness was achieved avoiding the acquisition of useless extra-data affected by noise due to gauge resolution. Conclusion/Recommendations: The use of the charts is strongly suggested at the early stage of decision making for new exploration/ appraisal operations; they are a user-friendly tool for assessing the feasibility of a mini-DST test. A dditionally, the charts are more versatile with res pect to available commercial software in managing uncertainties of the major input parameters.

A Dual-Grid Automatic-History-Matching Technique With Applications to 3D Formation Testing in the Presence of Oil-Based-Mud-Filtrate Invasion

Summary Probe-type formation testers are often used to estimate permeability and anisotropy from pressure-transient measurements. The interpretation of these measurements is not trivial in the presence of oil-based-mud (OBM) -filtrate invasion because of miscibility with formation oil and gas. Simple analytical expressions of spherical and linear single-phase flow may not give correct estimates of permeability in miscible or partially miscible flow regimes. Because pressure transients are nonlinearly dependent on permeability, repeated 3D numerical simulations become necessary to honor measured pressure transients. We describe the development and successful implementation of a new inversion method that efficiently estimates permeability and anisotropy with a cascade sequence of least-squares minimizations. Measurements consist of pressure transients acquired at the sandface with a probe-type wireline formation tester (WFT). The new inversion method executes the forward 3D problem only in an outer loop. In the inner loop, we perform fast minimizations with an equivalent 2D cylindrical grid. Transient measurements of pressure at the sandface simulated with the 2D cylindrical grid are correlated to the corresponding measurements simulated with the 3D grid. Once the 2D minimization is completed, we perform a 3D simulation of transient pressure to update the 2D/3D correlation parameter and a new 2D minimization is initialized until convergence is reached. The process repeats itself until the simulated 3D pressure transients reproduce the field measurements within prestipulated error bounds. We perform tests of the new inversion algorithm on synthetic and field data sets acquired in the presence of OBM-filtrate invasion. Results confirm that our coupled 2D/3D hybrid inversion approach enables significant savings in computer time and provides reliable and accurate estimates of permeability and anisotropy. In most cases, we are able to estimate permeability under 2% error within 20% of the computational time required by 3D minimization. Sensitivity analysis indicates that permeability estimates may be biased by noisy measurements as well as by uncertainty in flow rates, relative permeability, radial extent of invasion, formation damage, and location of bed boundaries.

Replacing Wireline Formation Pressure With Formation Pressure While Drilling in Long Horizontal Wells

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 12103, "Replacing Wireline Formation Pressure With Formation Pressure While Drilling in Long Horizontal Wells," by J.K. Larsen, SPE, Maersk Oil Qatar; C.J. Maeso, SPE, and F. Liu, SPE, Schlumberger; and R. Narayanan and R. Noman, SPE, Qatar Petroleum, prepared for the 2008 International Petroleum Technology Conference, Kuala Lumpur, 3-5 December. The paper has not been peer reviewed. A case history presents how formation-pressure-while-drilling (FPWD) technology effectively has replaced traditional pipe-conveyed wireline technology in long horizontal wells. The Al Shaheen field, offshore Qatar, in the Middle East, is developed with 20,000- to 30,000 ft-long horizontal wells, drilled in radial and line-drive patterns in one sandstone and two carbonate reservoirs. Eleven FPWD jobs were performed within the first year, and FPWD now is the preferred option for formation-pressure acquisition in Al Shaheen. Introduction Knowledge of the reservoir pressure is essential for understanding the behavior of the reservoir fluids. Fluid gradients are used to establish fluid contacts in the reservoir, and pressure data obtained during the production phase reveal important information about drive mechanisms and the geology. Traditionally, wireline formation testers have been used to obtain formation pressures. FPWD tools have advantages and disadvantages compared to wireline formation testers, depending on the type of well and the objectives of the logging program. Understanding these advantages and disadvantages and the objectives of the logging program is required, and is best achieved through a joint effort by the operator and the service company. The full-length paper details the transition of, and the considerations associated with, introducing FPWD in the Al Shaheen field. Al Shaheen Field The Al Shaheen field is a low-relief structure with an areal extent of approximately 40×60 km and is developed in three main reservoirs: Nahr Umr, Shuaiba, and Kharaib (known as Thamama B elsewhere in the region). The Nahr Umr formation is a thin sandstone reservoir normally less than 15 ft thick, with a target zone less than 3 ft thick. The high-permeability target zone often is unconsolidated. The Shuaiba formation is a highly heterogeneous carbonate reservoir with large permeability contrasts associated with facies changes. The Kharaib formation is a tight carbonate reservoir with uniform reservoir properties across the field. The Kharaib permeability ranges from 1 to 10 md. The 20,000- to 30,000 ft-long horizontal wells are drilled with geosteering to control the position of the wells in the reservoir. Optimal well spacing ranges from 600 ft in the tight Kharaib formation to 2,000 ft in the high-permeability Nahr Umr sandstone. Fig. 1 shows the well placement in the three reservoirs in the northeastern part of the Al Shaheen field. Water injection is used extensively for pressure maintenance in all three reservoirs.

Moving From Vision to Reality - Optimal-Value Testing

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 114870, "Moving From Vision to Reality - The State of Optimal-Value Testing," by Hani Elshahawi, SPE, Robert H. Hite, SPE, and Melton P. Hows, SPE, Shell, prepared for the 2008 Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 20-22 October. The paper has not been peer reviewed. Optimal-value testing (OVT) could replace conventional drillstem tests (DSTs) for in-situ measurement of dynamic reservoir properties such as permeability and drainage volume. OVT is any pressure-transient test in which live hydrocarbons are not produced directly to surface. Although OVT is safer, less costly, and environmentally friendly, the OVT-results quality might be inadequate for some development decisions. The technology is immature, and there are issues to resolve. However, with increasing experience, future value-of-information (VOI) decisions about performing in-situ dynamic measurements will, more often, include OVT. Introduction The focus of this paper is the use of dynamic well testing in exploratory and appraisal wells. Historically, the industry called this testing a DST. This type of test, in which hydrocarbons flow directly to surface while measuring rate and pressure, is a major tool in deciding how to develop a hydrocarbon resource. Cost along with health, safety, and environmental (HSE) concerns encourages seeking better ways of obtaining similar reservoir and fluid data. OVT is any fit-for-purpose well testing with minimal cost and HSE effect in which no significant volume of live hydrocarbons is produced to the surface. Three types of tests are wireline formation tests (WFTs), closed-system tests, and injection tests. Background Any assessment of OVT must include an understanding of resource-development uncertainties and the reliability of the technology. The types of technologies considered for OVT are not new, but certainly are not as mature as conventional DSTs. WFT. These tests are performed by use of an electrically controlled formation-testing and -sampling tool anchored at depth (usually on wireline and in open hole) while reservoir communication is established through one or more probes or packers. Modern WFTs can collect a massive amount of data at multiple depths, helping to quantify changes in rock and fluid properties along the wellbore, to define hydraulic flow units, and to understand reservoir architecture. These tests are used routinely in many applications including pressure and mobility profiling vs. depth, fluid sampling, downhole-fluid analysis, pressure-transient testing, and microfracturing. Wireline testers have reached a maturity level at which their performance often can match that of production tests such as those carried out with a DST.

Pressure gradient computation and application of the wireline formation tester

Abstract One function of the wireline formation tester is to calculate pressure-depth gradient line (pressure gradient) from testing data. Its application is limited resulting from the uncertainties in the computational method, which often results in a big deviation. The effect of the reservoir thickness, the effective measuring point number, and the measurement error distribution of pressure-measuring points on the computational precision of pressure gradient was studied by numerical simulation: the thicker the measured reservoir, the more the measuring-point number, and the closer the measurement errors of all measuring points are, the higher the computation precision is. The selection of measuring points should take into account fluid character, formation pressure coefficient, reservoir connectivity, and so on. Pressure gradient can be applied in the analysis of the fluid property, the oil and water interface, the vertical connectivity of reservoirs, the pressure systems, the vertical change of formation fluid in single wells, and in the assistant evaluation of reservoirs in multiwells.

Estimation of in-situ petrophysical properties from wireline formation tester and induction logging measurements: A joint inversion approach

We introduce a novel inversion algorithm for the in-situ petrophysical evaluation of hydrocarbon-bearing formations. The algorithm simultaneously honors a set of multi-physics data: (a) Pressure-transient, flowline fractional flow, and salt production rate measurements as a function of time acquired with a wireline-conveyed, dual-packer formation tester, and (b) borehole array induction measurements. Both time evolution and spatial distribution of fluid saturation and salt concentration in the near-borehole region are constrained by the physics of mud-filtrate invasion. The inverse problem consists of the simultaneous estimation of the near-borehole permeability and parametric saturation functions of relative permeability and capillary pressure. A two-dimensional axisymmetric petrophysical model is assumed for the near-borehole region. Both horizontal and vertical permeabilities are subject to inversion. Saturation functions of relative permeability and capillary pressure are parametrically represented using a modified Brooks–Corey model. We simulate the response of borehole logging instruments by reproducing the multi-phase, multi-component flow that takes place during mud-filtrate invasion and formation test. A fully implicit finite-difference black-oil reservoir simulator with brine tracking extension is used to simulate fluid-flow phenomena. Induction measurements are coupled to the physics of fluid flow using a rapid integro-differential algorithm. Inversion experiments consider both noise-free and noise-contaminated synthetic data. Joint inversion results provide a quantitative proof-of-concept for the simultaneous estimation of transversely anisotropic spatial distributions of permeability and saturation-dependent functions. The stability and reliability of the inversions are conditioned by the accuracy of the a priori information about the formation porosity and fluid PVT properties. We develop an alternative sequential inversion technique for cases where multi-physics measurements lack the degrees of freedom necessary to accurately estimate all the petrophysical model parameters. The first step involves estimation of horizontal and vertical permeabilities from late-time transient-pressure measurements. Subsequently, the entire set of measurements is jointly inverted to yield saturation-dependent functions.

Compositional Modeling of Oil-Based-Mud-Filtrate Cleanup During Wireline Formation Tester Sampling

Summary Miscible oil-based-mud (OBM) filtrate contamination poses a major challenge to the acquisition of representative fluid samples using wireline formation testers (WFTs). A sound understanding of the OBM-filtrate cleanup process and identification of first-order impact parameters are of paramount importance for the design of next-generation WFT probes that can operate in OBM-filtrate environments with enhanced efficiency. We have constructed a numerical model for OBM-filtrate cleanup using an equation-of-state (EOS) compositional fluid-flow simulator. The numerical cleanup model honors the physics of multicomponent-fluid flow and the thermodynamics of phase behavior. Simulation results exhibit close agreement with analytical predictions and with field data for the time dependence of contamination during sampling. First-order impact parameters were identified through a sensitivity study using the numerical model. It has been found that the clean-up function is predominantly governed by permeability anisotropy, porosity, cleanup flowrate, viscosity ratio, depth of invasion, distance between the WFT probe and a sealing boundary, formation thickness, and wellbore radius. A response-surface-based contamination model (RSCM) was developed using the above-described simulation investment with additional runs. RSCM constitutes a rapid approximate model and can serve as a prejob-planning or real-time-analysis tool. Our simulation and rapid-modeling results compare well with empirical observations made in the field. In particular, the rate of change of miscible contamination with time has been found to vary between t0.3 and t0.6, with t0.45 representing a good average value. For the first time, modeling has been shown to give essentially the same results as empirical observations.

Focused Sampling of Reservoir Fluids Achieves Undetectable Levels of Contamination

Summary A new generation of sampling technology is introduced that allows a wireline formation tester (WFT) to sample reservoir fluids in open hole with levels of filtrate contamination that are, in many cases, below measurable limits. Also, the time required on station to clean up before sampling is significantly reduced in comparison to conventional sampling methods. Formation-fluid sampling has always been adversely affected by mud-filtrate contamination, which introduces errors into the laboratory measurements of fluid properties and requires analytical methods to back-calculate the measured properties to approximate the uncontaminated reservoir fluid. The ability to secure a totally clean sample of formation fluid at reservoir conditions is a significant advance that provides accurate fluid information for characterization of the reservoir, flow assurance, facility design, production strategies, and defining reserves. The application of this new focused sampling technology is presented in four case studies from wells drilled on the Norwegian continental shelf. A wide range of formation fluids and permeabilities are examined, in both oil-based and water-based drilling fluids. Results from focused sampling are compared directly with conventional sampling in the same reservoir zones. This study also gives insight into the cleanup dynamics of invaded filtrate and explores the different factors that affect performance of the focused sampling technique. An important consequence of achieving negligible contamination is the ability to accurately measure fluid properties in-situ. Reduced cleanup time allows for efficient reservoir fluid profiling, whereby multiple zones can be scanned sequentially in real time to quantify the fluid properties at a much higher resolution than traditional sampling methods. Downhole fluid analysis (DFA) can thus provide an additional source of information in the process of revealing complex reservoir architectures.

Combining Continuous Fluid Typing, Wireline Formation Testers, and Geochemical Measurements for an Improved Understanding of Reservoir Architecture

Summary Identifying compartmentalization and understanding reservoir structure are of critical importance to reservoir development. Traditional methods of identifying reservoir compartmentalization, such as drillstem tests and extended well tests, often become impractical in deepwater settings, with costs approaching the costs of new wells and emissions becoming increasingly undesirable. Thus, compartments often have to be identified by some other means. Individual formation-pressure measurements, downhole fluid analysis (DFA), and geochemistry are known to provide important information about reservoir architecture. When these powerful methods are combined systematically and applied to data sets, the resulting synergy delivers a much more accurate and robust picture of the reservoir. In this paper, we review a number of case studies in which we have successfully combined continuous fluid/facies mapping, pressure-gradient measurements, DFA, and geochemistry for a reservoir-continuity assessment in a diverse range of geological settings, including a wide range of field sizes, structural environments, reservoir lithologies, and oil types. Particular emphasis is placed on comparing the strengths and limitations of the different techniques in revealing reservoir architecture, especially vertical-permeability barriers. We present a number of unambiguous cases, for which multiple data streams might be viewed as being somewhat redundant. More-ambiguous cases, in which the multiple data streams are required to make a robust assessment of key reservoir properties, are also presented.

Three-dimensional finite element modelling of oil–water two-phase profiles in the wireline formation test

A mathematical model for simulating the oil–water two-phase wireline formation test is developed in this paper. The model is solved by the finite element method with high accuracy by adopting the Galerkin and least-squares forms to construct different finite element forms for the pressure and saturation fields, according to the type of field. Responses of pressure and saturation in time and space are computed and analysed here, providing not only the pressure response during the test, but also the starting time of sampling. These studies provide theoretical foundations for tool design and field data interpretation.

Permeability From Production Logs—Method and Application

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Abstract Estimating effective permeability at the reservoir scale has been a long-standing challenge in carbonate fields. The carbonate depositional and diagenetic history can be very complex, which can lead to permeability that is difficult to characterize. Vuggy or fractured intervals can have permeability significantly higher than the matrix permeability measured in core plugs. This "excess permeability" may control reservoir flow paths but is difficult or impossible to predict from static well-log transforms that are calibrated to matrix permeability. In the Tengiz field, a giant carbonate reservoir in western Kazakhstan, a method has been developed to calculate apparent permeability on the basis of flow rate from production-logging tools (PLTs). Incorporating this flow-calibrated permeability into the Earth model offers an elegant solution to the long-standing problem of the best method to incorporate dynamic PLT data into a reservoir model. Recently, a reservoir model built with apparent permeability resulted in more-realistic heterogeneity and a step-change improvement over previous methods in which only static log-based permeability transforms were used to populate the Earth model. Fewer changes were required to calibrate the full-field reservoir model. History matching to pulse tests showed that this model has a much-improved prediction of the interwell connectivity. Models containing apparent-permeability data have provided higher-confidence estimates of the future movement of gas injection from the Tengiz platform. The apparent permeability is calculated by solving Darcy's law on an interval basis, using our knowledge of flowing and static pressures as input along with well, reservoir, and fluid properties, and then calibrating with the pressure-buildup transient permeability-thickness product, kh. Accuracy of the method is enhanced by the derivation of coarse-scale zonal layer pressures with multirate PLTs. Selecting an appropriate skin factor to use in the calculation is important. The acid effect on pulsed-neutron-capture (PNC) logs works well in Tengiz and has been helpful in addressing this problem. Introduction The fundamental building blocks of a reservoir model are porosity, permeability, and fluid saturation. Porosity and fluid saturation can be computed from wireline logs with reasonable confidence, but often, the same confidence is not possible for permeability. Permeability can be measured directly from core material or determined with well tests by use of pressure-transient tests (PTTs), pulse tests between wells, and wireline formation tests. Scale differences in these sources of permeability data complicate the permeability estimation in a reservoir model (Al-Henshiri et al. 2005; Ahmed et al. 1991). In most reservoirs, the amount of core available for direct permeability measurement is limited, and permeability estimates usually are made by proxy by use of wireline-log responses. The science of permeability prediction has evolved into a high degree of sophistication, with each additional level resulting in an incremental gain in predictive accuracy (Skalinski and Sullivan 2001). Despite the available sophisticated tools, permeability prediction in carbonates remains problematic. The widely varying pore structures (Lucia 1995) and their potential lack of connectivity result in a highly variable porosity/permeability relationship. Vuggy porosity and fractures, if they are connected, can result in extremely high layer flow rates or very low rates, if not connected, for the same value of porosity.

Reservoir fluid differentiation case study from Oredo field in the Niger Delta Nigeria

The formations in the Niger Delta-Nigeria consist of sands and shales with the former ranging from fluvial (channel) to fluviomarine (Barrier Bar), while the latter are generally fluviomarine or lagoonal. These Formations are mostly unconsolidated and it is often not feasible to take core samples or make drill stem tests. Formation evaluation is consequently based mostly on logs, with the help of sidewall samples and wireline formation tests. From the comparison between the FDC/CNL (Formation Density/Neutron Logs spell out) separation and SWS (sidewell sample) petrophysical data, it is possible for fluid differentiation to be done from SWS measurement with a good measure of reliability, in the absence of production data and FDC/CNL logs. This may not apply to liquid – rich gas and condensate reservoirs. The FDC/CNL log responses are better defined in thick clean sands as against thin marginal sands in this case study. Key words: Formations, Gas/Oil, Sands and Shales, Hydrocarbon, Porosity, Resistivity.