Effect of an Invaded Zone on Pressure-Transient Data From Multiprobe and Packer-Probe Wireline Formation Testers

2006 ◽  
Vol 9 (01) ◽  
pp. 39-49 ◽  
Author(s):  
Ihsan M. Gok ◽  
M. Onur ◽  
Peter S. Hegeman ◽  
Fikri J. Kuchuk
Keyword(s):  
Pressure Data ◽  
Pressure Transient ◽  
Pressure Transients ◽  
Water Based ◽  
Gravity Effects ◽  
Transient Data ◽  
Invaded Zone ◽  
Water Cut ◽  
Vertical Probe ◽  
Mud Filtrate

Summary This paper examines the effect of a mud-filtrate-invaded zone on pressure transients from multiprobe/packer-probe wireline formation testers (WFTs). Invasion zones are modeled as composite zones concentric with the wellbore that have different rock and fluid properties (permeability, porosity, viscosity, and compressibility) from those of the native uninvaded formation. The results show that for multiprobe wireline testers, the sink- (production) and horizontal-probe pressure responses are highly affected by the invaded-region properties, while the vertical-probe pressures are influenced mainly by the properties of the uninvaded zones. For the packer-probe configuration, similar results are obtained (i.e., the vertical-probe pressures are influenced mainly by the properties of the uninvaded zones, while the packer-interval pressures at early times are influenced by the invaded-zone properties). It is shown that if the invaded zones are incorporated into the interpretation process with a 3D r-???-z single-phase, finite-difference model like the one developed in this work, simultaneous matching of spatially available WFT pressure-data sets using nonlinear regression can provide estimates of both invaded- and uninvaded-zone parameters. A synthetic example of a multiprobe test is presented to confirm the theory and procedures developed in this work. Introduction The multiprobe and packer-probe WFTs are used to conduct controlled local production and buildup tests as well as horizontal- and vertical-interference tests (interval pressure transient tests, or IPTT). These tools provide formation-fluid samples and estimates of horizontal and vertical permeabilities and wellbore damage. Further details about WFTs, equipped with packers and multiple probes, can be found in Zimmerman et al. (1990), Goode et al. (1991), Goode and Thambynayagam (1992), Head and Bettis (1993), Pop et al. (1993), Kuchuk et al. (1994), and Onur et al. (2004). It has always been a concern how the pressure transients from these formation testers are affected by the presence of invaded regions around the wellbore. When an oil/gas well is drilled, some of the borehole fluid (mud filtrate) can leak into the formation, displacing the native formation fluid and creating an invaded zone around the wellbore. The invading fluid usually has a viscosity and compressibility that differ from those of the formation fluid. All WFT drawdown and buildup tests and IPTTs are conducted in an openhole environment, in which formation invasion takes place until the mudcake buildups, after which invasion becomes negligible. The invasion depth may vary from a few inches to a few feet, depending on formation and mud properties, as well as drilling parameters. Therefore, one must know how the invaded zone affects parameter estimates from WFT drawdown and buildup tests and IPTTs. Second, can we estimate some of the parameters of invaded zones? For instance, if we can obtain the permeabilities of both invaded and uninvaded zones, this can give us the endpoint effective permeabilities for both water and oil on a much larger scale than that from cores. In general, the process of drilling-fluid invasion is quite complicated because it involves solid and solute (and solvent, in the case of oil-based mud) transport and precipitation as well as multiphase flow, capillary pressure hysteresis, wettability alterations, chemical adsorption, and gravity effects (Ferguson and Klotz 1954; Bailey et al. 2000; Civan 2002). One of the main difficulties is how to model the initial condition set by the invasion process before sampling and pressure transients from WFTs. In addition, modeling the effects of invasion zone(s) on fluid sampling during production and on pressure-transient data from WFTs during pumpout and buildup periods is challenging, where we are faced by two distinct problems. However, if one assumes that capillary and gravity effects are negligible and that permeability and porosity impairments caused by solid and solute invasion and precipitation are minimal, then one may tackle the invasion problem by modeling it as miscible or two-phase immiscible flow. Several researchers (Phelps et al. 1984; Hammond 1991; Akram et al. 1999; Zeybek et al. 2001; Wu et al. 2002) have taken this approach to include the effect of invasion on fluid sampling and pressure-transient data from WFTs. However, all work given in Phelps et al. (1984), Hammond (1991), Akram et al. (1999), Zeybek et al. (2001), and Wu et al. (2002) is limited to a single-layer system. In addition, these references do not address the parameter-estimation problem (mainly permeability) in the presence of invasion. For instance, Akram et al. (1999) numerically simulated the invaded zone by injecting water to create a sharp interface (or shock front) between filtrate and oil in the simulator and then studied the effect of invasion on sampling quality (water cut) vs. time during the pumpout (production) period, which is production from the formation into the wellbore by means of a pump. In the presence of water-based-mud invasion, Zeybek et al. (2001) presented an inversion methodology using a numerical simulator to refine oil/water relative permeabilities by integrating dual-packer pressure and water-cut measurements with openhole array resistivity measurements. During their inversion process, they also updated the absolute horizontal and vertical permeability in the simulator. However, they did not consider vertical-observation probe pressure data in their inversion methodology. Wu et al. (2002) presented miscible and immiscible multiphase sampling modeling for oil- and water-based muds for a dual-probe configuration. Assuming that the capillary pressure and relative permeability curves (and the mud-filtrate characteristics) are known, they presented an inversion methodology of horizontal and vertical permeabilities by matching sampling quality and pressure measurements acquired in the presence of oil- and water-based invaded zones. Their inversion method is based on a neural-network approach coupled with a numerical simulator.

Estimating petrophysical parameters and average mud-filtrate invasion rates using joint inversion of induction logging and pressure transient data

Geophysics ◽  
2011 ◽  
Vol 76 (2) ◽  
pp. E21-E34 ◽  
Author(s):  
Lin Liang ◽  
Aria Abubakar ◽  
Tarek M. Habashy
Keyword(s):  
Fluid Flow ◽  
Finite Difference ◽  
Water Saturation ◽  
Joint Inversion ◽  
Invasion Process ◽  
Invasion Rate ◽  
Pressure Transient ◽  
Induction Logging ◽  
Transient Data ◽  
Mud Filtrate

We introduce an inversion approach for determining the water-based mud-filtrate invasion profile, as well as the formation porosity and horizontal permeability, from the induction logging data. The inversion is constrained by a multiphase fluid flow simulator that simulates the mud-filtrate invasion process to obtain the spatial distributions of the water saturation and the salt concentration, which are in turn transformed into the formation resistivity using a resistivity-saturation formula. By ignoring the diffusion effect, we assume that the mud-filtrate invasion process is mainly convective so that it can be equivalently simulated by providing an average invasion rate and the duration of invasion. The average invasion rate can be directly inverted from the fluid-flow-constrained inversion of induction logging data. We also obtain the mud-filtrate invasion profile, which is consistent with the fluid flow physics. The reconstructed mud-filtrate invasion profile benefits the interpretation of the formation test. When the pressure transient data are available, this approach can be also used to jointly invert both induction logging data and pressure transient data to obtain the mud-filtrate invasion profile, as well as a parametric distribution of the TI-anisotropic formation permeability and porosity. Assuming a vertical well penetrating horizontal formations, the fluid flow problem is solved using an implicit black oil finite-difference simulator with brine tracking option based on a cylindrical, axially symmetric grid, whereas the response of the induction logging tool is simulated using a frequency-domain finite-difference solver based on a Cartesian grid. A Gauss-Newton inversion scheme using the multiplicative regularization technique is used for either the fluid-flow-constrained inversion or the joint inversion. The reliability of the inversion results depends on the accuracy of a priori knowledge of the reservoir, which needs to be confirmed via sensitivity analysis.

Interpretation of Permanent Well Monitoring Data to Improve Characterization of a Giant Oil Field

2021 ◽  
Author(s):  
Hans Christian Walker ◽  
Anton Shchipanov ◽  
Harald Selseng
Keyword(s):  
Reservoir Characterization ◽  
Time Lapse ◽  
Interference Analysis ◽  
Pressure Transient ◽  
Pressure Transients ◽  
Reservoir Simulations ◽  
Production History ◽  
Fault Leakage ◽  
Fit For Purpose

Abstract The Johan Sverdrup field located on the Norwegian Continental Shelf (NCS) started its production in October 2019. The field is considered as a pivotal development in the view of sustainable long-term production and developments on the NCS as well as creating jobs and revenue. The field is operated with advanced well and reservoir surveillance systems including Permanent Downhole Gauges (PDG), Multi-Phase Flow-Meters (MPFM) and seismic Permanent Reservoir Monitoring (PRM). This provides an exceptional basis for reservoir characterization and permanent monitoring. This study focuses on reservoir characterization to improve evaluations of sand permeability-thickness and fault transmissibility. Permanent monitoring of the reservoir with PDG / MPFM has provided an excellent basis for applying different methods of Pressure Transient Analysis (PTA) including analysis of well interference and time-lapse PTA. Interpretation of pressure transient data is today based on both analytical and numerical reservoir simulations (fit-for-purpose models). In this study, such models of the Johan Sverdrup reservoir regions have been assembled, using geological and PVT data, results of seismic interpretations and laboratory experiments. Uncertainties in these data were used to guide and frame the scope of the study. The interference analysis has confirmed communication between the wells located in the same and different reservoir regions, thus revealing hydraulic communication through faults. Sensitivities using segment reservoir simulations of the interference tests with different number of wells have shown the importance of including all the active wells, otherwise the interpretation may give biased results. The estimates for sand permeability-thickness as well as fault leakage obtained from the interference analysis were further applied in simulations of the production history using the fit-for-purpose reservoir models. The production history contains many pressure transients associated with both flowing and shut-in periods. Time-lapse PTA was focused on extraction and history matching of these pressure transients. The simulations have provided reasonable match of the production history and the time-lapse pressure transients including derivatives. This has confirmed the results of the interference analysis for permeability-thickness and fault leakage used as input for these simulations. Well interference is also the dominating factor driving the pressure transient responses. Drainage area around the wells is quickly established for groups of the wells analyzed due to the extreme permeability of the reservoir. It was possible to match many transient responses with segment models, however mismatch for some wells can be explained by the disregard of wells outside the segments, especially injectors. At the same time, it is a useful indication of communication between the regions. The study has improved reservoir characterization of the Johan Sverdrup field, also contributing to field implementation of combined PTA methods.

Pressure Transient Data Acquisition and Analysis Using Real Time Electromagnetic Telemetry

1996 ◽  
Author(s):  
L.E. Doublet ◽  
J.W. Nevans ◽  
M.K. Fisher ◽  
R.L. Heine ◽  
T.A. Blasingame
Keyword(s):  
Data Acquisition ◽  
Real Time ◽  
Pressure Transient ◽  
Transient Data

Interpretation of Injection Well Pressure Transient Data in Thermal Oil Recovery

1980 ◽  
Author(s):  
Abdurrahman Satman ◽  
Mauricio Eggenschwiler ◽  
Henry J. Ramey
Keyword(s):  
Oil Recovery ◽  
Injection Well ◽  
Pressure Transient ◽  
Transient Data ◽  
Thermal Oil

Characterization of a Carbonate Reservoir With Pressure-Transient Tests and Production Logs: Tengiz Field, Kazakhstan

2001 ◽  
Vol 4 (04) ◽  
pp. 250-259
Author(s):  
K.T. Chambers ◽  
W.S. Hallager ◽  
C.S. Kabir ◽  
R.A. Garber
Keyword(s):  
Flow Behavior ◽  
Carbonate Reservoir ◽  
Dual Porosity ◽  
Rate Data ◽  
Pressure Data ◽  
Pressure Transient ◽  
Reservoir Flow ◽  
Black Oil ◽  
Fluid Properties ◽  
Tengiz Field

Summary The combination of pressure-transient and production-log (PL) analyses has proved valuable in characterizing reservoir flow behavior in the giant Tengiz field. Among the important findings is the absence of clear dual-porosity flow. This observation contradicts an earlier interpretation that the reservoir contains a well-connected, natural fracture network. Fracturing and other secondary porosity mechanisms play a role in enhancing matrix permeability, but their impact is insufficient to cause dual-porosity flow behavior to develop. Flow profiles measured with production logs consistently show several thin (10 to 30 ft) zones dominating well deliverability over the thick (up to 1,040 ft) perforation intervals at Tengiz. A comparison of PL results and core descriptions reveals a good correlation between high deliverability zones and probable exposure surfaces in the carbonate reservoir. Contrary to earlier postulations, results obtained from pressure-transient and PL data at Tengiz do not support rate-sensitive productivity indices (PI's). Inclusion of rate variations in reconciling buildup and drawdown test results addressed this issue. We developed wellbore hydraulic models and calibrated them with PL data for extending PI results to wells that do not have measured values. A simplified equation-of-state (EOS) fluid description was an important component of the models because the available black-oil fluid correlations do not provide reliable results for the 47°API volatile Tengiz oil. Clear trends in reservoir quality emerge from the PI results. Introduction A plethora of publications exists on transient testing. However, only a few papers address the issue of combining multidisciplinary data to understand reservoir flow behavior (Refs. 1 through 4 are worthy of note). We used a synergistic approach by combining geology, petrophysics, transient tests, PL's, and wellbore-flow modeling to characterize the reservoir flow behavior in the Tengiz field. Understanding this flow behavior is crucial to formulating guidelines for reservoir management. Permeability estimation from pressure-transient data is sensitive to the effective reservoir thickness contributing to flow. Unfortunately, difficulties associated with the calibration of old openhole logs, sparse core coverage, and a major diagenetic overprint of solid bitumen combine to limit the identification of an effective reservoir at Tengiz based on openhole log data alone. Consequently, PL's have been used to identify an effective reservoir in terms of its flow potential. A limitation of production logs is that they only measure fluid entering the wellbore and are not necessarily indicative of flow in the reservoir away from the well. Pressure data from buildup and drawdown tests, on the other hand, provide insights into flow behavior both near the well and farther into the reservoir. The combination of pressure-transient analysis using simultaneous downhole pressure and flow-rate data along with measured production profiles provides an opportunity to reconcile near-wellbore and in-situ flow behavior. Expansion of reservoir fluids along with formation compaction provides the current drive mechanism at Tengiz because the reservoir is undersaturated by over 8,000 psia. As the field is produced, reservoir stresses will increase in response to pressure decreases.5 Increased stresses can significantly reduce permeability if natural fractures provide the primary flow capacity in the reservoir. Wells producing at high drawdowns provide an opportunity to investigate the pressure sensitivity of fractures within the near-wellbore region. Early interpretations of pressure-transient tests at Tengiz uncovered a significant discrepancy between buildup and drawdown permeability, despite efforts to carefully control flow rates during the tests. Drawdown permeabilities typically exceeded the buildup results by 20 to 50%. Although this finding appears counterintuitive to the expectation that drawdowns (that is, higher stresses) would lead to lower permeability, it indicated a possible stress dependence on well deliverability. The method proposed by Kabir6 to reconcile differences between drawdown and buildup results proved useful in addressing this issue. The opportunities to collect PL and downhole pressure data at Tengiz are limited by mechanical conditions in some wells and by the requirement to meet the processing capacity of the oil and gas plant. On the other hand, accurate wellhead-pressure and flow-rate data are routinely available. Wellbore hydraulic calculations provide a basis for calculating flowing bottomhole pressures (FBHP's) with the available surface data. Calculated FBHP's can be combined with available reservoir pressure data to determine PI's for wells lacking bottomhole measurements. The ability to compute accurate fluid properties is critical in applying this approach. Unfortunately, the black-oil correlations routinely used in wellbore hydraulic calculations7–9 do not provide reliable results for the volatile Tengiz oil. We obtained good agreement between laboratory measurements of fluid properties and calculated values using a simplified EOS.10 Surface and bottomhole data collected during PL operations provide a basis for validating wellbore hydraulic calculations. Networks of natural fractures can dominate the producing behavior of carbonate reservoirs such as Tengiz. Early identification of fractured reservoir behavior is critical to the successful development of these types of reservoirs.11 We present an approach for resolving reservoir flow behavior by combining production profiles, pressure-transient tests, and wellbore hydraulic calculations. Furthermore, we discuss the PL procedures developed to allow acquisition of the data required for all three types of analyses in a single logging run. Field examples from Tengiz highlight the usefulness of this approach.

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