Well-test Responses Research Articles

Simultaneous effect of geological heterogeneity and condensate blockage on well test response of gas condensate reservoirs

Condensate dropout around a wellbore causes many practical difficulties. It complicates the prediction of fluid flow around a wellbore, especially during well test interpretations. Many researchers have explored the impact of gas condensing on the transient behavior of well-test responses. However, much less attention were paid to the analysis of the combined effect of geological heterogeneity and condensate drop out. In this study, a geostatistical approach (ordinary Kriging) is used to build reservoir models with different amount of heterogeneity. These models are simulated by a compositional reservoir simulator to generate pseudo-pressure data versus time of these heterogeneous models. The common method of the single-phase gas pseudo-pressure approach is used to evaluate the static and dynamic parameters of these reservoir models during well test interpretations. It is revealed that the intensity of the condensate formation around the wellbore is a strong function of the reservoir heterogeneity. The results show that increasing of the model heterogeneity can entirely complicate the well-test responses when condensate drops near the wellbore region. Implementing two well tests (one above and another below the dew point pressure) can enable us to distinguish the geological heterogeneity from the liquid condensation effect when both of them coexist in the formation.

Catalog of Well-Test Responses in a Fluvial Reservoir System

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 180181, “Catalog of Well-Test Responses in a Fluvial Reservoir System,” by J.L. Walsh and A.C. Gringarten, Imperial College London, prepared for the 2016 SPE Europec featured at the 78th EAGE Conference and Exhibition, Vienna, Austria, 30 May–2 June. The paper has not been peer reviewed. Well-test analysis in fluvial reservoirs remains a challenge because of the depositional environment conducive to significant internal heterogeneity. Analytical models used in conventional analysis are limited to simplified channel geometries and, therefore, fail to capture key parameters such as sand-body dimensions, orientations, and connectivity, which can affect control-fluid flow and pressure behavior. The complete paper aims at a better understanding of the effect of channel content in complex fluvial channel systems on well-test-derivative responses. Methodology Geological Modeling. 3D geological models with a centrally located well were generated and populated with varying fluvial geologies. A 6950-m×6950-m×300-ft geological model was set up that allowed the averaging effects of the heterogeneities and the reservoir boundaries to be visible on the derivative at late times. Modeling the geology of a fluvial system is challenging because of changes in channel amplitude, amalgamation, and other processes through geological times, which yield highly variable distribution and shapes of fluvial deposits. Field X was modeled as isolated elliptical sand bodies and channel bodies, with sand-body dimensions of 105 m (width)×420 m (length)×5 ft (thickness) for the base case. The sand and channel bodies are schematically represented in Figs. 1 and 2. Object-oriented modeling was used instead of stochastic, sequential indicator simulation and Gaussian simulation to retain control over the modeling parameters. Numerical Simulation. The corresponding pressure and derivative dynamic responses were generated using a proprietary finite-element simulator with a uniform grid and a fine local grid refinement (LGR) around the wellbore. The fluid was black oil at a reservoir pressure greater than the saturation pressure, and the relative permeability to water was low enough to limit water movement within the model. Results and Discussion of Base-Case Model A drawdown of 115 years was simulated for a geological model 6950 m×6950 m×300 ft with a cell size of 50 m×50 m×5 ft in the x, y, and z directions, respectively (total cell count without LGR=1,159,260), with a fine Cartesian LGR around the wellbore to reduce numerical artifacts around the wellbore (total cell count with LGR=1,327,200). The model consists of two facies. All simulations were performed without including wellbore dynamics or mechanical skin.

Using geological well testing for improving the selection of appropriate reservoir models

Analytical well-test solutions are mainly derived for simplified and idealized reservoir models and therefore cannot always honour the true complexity of real reservoir heterogeneities. Pressure transients in the reservoir average out heterogeneities, and therefore some interpretations may not be relevant and could be misleading. Geological well testing refers to the numerical simulation of transient tests by setting up detailed geological models, within which different scales of heterogeneity are present. The concept of geological well testing described in this paper assists in selecting from multiple equi-probable static models. This approach is used to understand which heterogeneities can influence the pressure transients. In this paper, a low-energy multi-facies fluvial reservoir is studied, for which data from a well test of exceptionally long duration are available. The pervasive low reservoir quality facies and restricted macro cross-flow between the reservoir layers give rise to an effective commingled system of flow into the wellbore (i.e. zero or very low vertical cross-flow between the reservoir units). In our model, facies transitions produce lateral cross-flow transients that result in a ‘double-ramp-effect’ signature in the test response. A sophisticated multi-point statistical (MPS) facies modelling approach is utilized to simulate complex geological heterogeneities and to represent facies spatial connectivity within a set of generated static models. The geological well-test model responses to a real well-testing cycle are then evaluated using dynamic simulation. The pressure match between simulated and recorded data is improved by generating multiple facies and petrophysical realizations, and by applying an engineering-based hybridization algorithm to combine different models that match particular portions of the real well-test response. In this example, the reservoir dynamics are controlled by subtle interaction between high-permeability channels and low-permeability floodplain deposits. Effective integration of geology and dynamic data using modern methods can lead to better reservoir characterization and modelling of such complex reservoir systems.

Well-test response in stochastic permeable media

Abstract In this paper, different approaches are employed to study the ramifications of various statistical and geostatistical parameters (i.e. mean and variance, vertical and horizontal correlation lengths and covariance function types) on the well-test results. These approaches include analytical, numerical, and semi-analytical methods, each of which explains the ensemble and/or volume average permeability of heterogeneous reservoirs from transient tests. In particular, in the numerical method, a few thousand pixel-based geostatistical permeability realizations, with various parameters, are generated; and the single-phase flow simulations are performed for each realization. The extracted permeability from the ensemble well-test response is then related to the underlying statistical and geostatistical parameters of permeability distribution. In this paper special attention is paid to a well-test response (i.e. a ramp effect) in a particular heterogeneous reservoir, that is manifested as a steep increase of the well-test derivative curve. A real test example is also presented to give an intuition as to how the permeable heterogeneity is reflected in a real problem. This paper provides the necessary practical insight for constructing a link between the static geological model and the dynamic test data found in highly heterogeneous stochastic reservoirs.

Modeling the Interfering Effects of Gas Condensate and Geological Heterogeneities on Transient Pressure Response

Summary Numerous publications have investigated the effect of gas condensate fluid on the transient pressure well-test (WT) response. However, to the best of our knowledge, its combined effect with geology has rarely been studied. Our findings in the present report demonstrate that geology can complicate the WT response and make it difficult for interpretation. In this study, the impact of geological heterogeneities on the WT response of a commingled braided fluvial gas condensate reservoir has been investigated. Numerical WT data were generated for a single-well model with a commercial compositional reservoir simulator. Several sensitivity simulations were performed to explore the effects of correlation length, vertical permeability, production rate, and drawdown time on the pseudopressure-derivative curves. The WT weighting kernel function and the calculated well-pressure sensitivity coefficients were implemented to demonstrate different trends of drawdown and buildup responses encountered in this study. The results clarified the idea that some geological heterogeneities and production parameters can alter pressure distribution and condensate saturation and mask the native model WT signatures. In this exercise, it was demonstrated that ramp effect, a geologically complex phenomenon in high-net/gross commingled reservoirs, is affected by the condensate formation. This interfering phenomenon is reflected on the derivative curves and is magnified in the presence of the shorter correlation lengths, the lower vertical communications, and the higher production rates. We also examined the stepwise stripping of the reservoir heterogeneity, demonstrating the significant impact of some facies on the buildup and drawdown transient pressure response. The time-dependent sensitivity coefficients were calculated to show that the drawdown test is sensitive to effective permeability in near-wellbore regions, in which condensate is prone to build up with time. In the buildup, on the other hand, the condensate saturation is almost invariant with time and affects the early-time region. This work leads toward better understanding of the influence of geology in gas condensate WT interpretation of fluvial reservoirs.

The effect of hydraulic-fracture parameters on the welltest response of multi-fractured tight-gas reservoirs

With the reduction of conventional reserves, the demand and exploration of unconventional sources becomes increasingly important in the energy supply system. Low permeability, low porosity, and the complexities of rock formation in unconventional gas reservoirs make it difficult to extract commercially viable gas resources. Hydraulic fracture is the most common technique used for commercial production of hydrocarbon resources from unconventional tight-gas reservoirs. Due to the existence of an extremely long transient-flow period in tight-gas reservoirs, the interpretation of welltest data based on conventional welltest analysis is quite challenging, and could potentially lead to misleading results. This peer-reviewed paper presents a new approach based on a log-log reciprocal rate derivative plot. Emphases are given on the identification of factors affecting the welltest response in multiple hydraulic-fractured wells in unconventional gas reservoirs based on numerical simulation. The objective is to investigate the sensitivity of various reservoir and hydraulic-fracture parameters, such as multiple hydraulic-fracture size, fracture number and fracture orientation on welltest response, and the effect of the pressure derivative curve on the slopes of welltest diagnostic plots, as well as on well productivity performance. The results can be used to understand the welltest response for different hydraulic-fracturing scenarios for the efficiency and characteristics of hydraulic fractures.

Generalized Radial Flow in Synthetic Flow Systems

Traditional analysis methods used to determine hydraulic properties from pumping tests work well in many porous media aquifers, but they often do not work in heterogeneous and fractured-rock aquifers, producing non-plausible and erroneous results. The generalized radial flow model developed by Barker (1988) can reveal information about heterogeneity characteristics and aquifer geometry from pumping test data by way of a flow dimension parameter. The physical meaning of non-integer flow dimensions has long been a subject of debate and research. We focus on understanding and interpreting non-radial flow through high permeability conduits within fractured aquifers. We develop and simulate flow within idealized non-radial flow conduits and expand on this concept by simulating pumping in non-fractal random fields with specific properties that mimic persistent sub-radial flow responses. Our results demonstrate that non-integer flow dimensions can arise from non-fractal geometries within aquifers. We expand on these geometric concepts and successfully simulate pumping in random fields that mimic well-test responses seen in the Culebra Dolomite above the Waste Isolation Pilot Plant.

The third porosity system

Well testing is a critical part of any evaluation of a carbonate reservoir discovery. Well-test interpretation in carbonate reservoirs poses additional challenges to those normally faced in the interpretation process in clastic reservoirs. The range of different boundary and crossflow relationships that are generated during well testing by the complex porosity systems are often poorly quantified and understood. The volume over which the pressure response is effective is also a source of great uncertainty and could be critical at the exploration/appraisal stage in any project. In this paper, which describes a generic modelling approach, we consider carbonate reservoirs which contain three pore sytems (or porosity types): (1) microporosity (end-member) with low permeability and high porosity; (2) macroporosity (end-member) with high permeability and high porosity; and (3) fracture porosity with high permeability and low porosity. These occur in various nested geometrical distributions and varying contrasts. The observed well-test responses (i.e. fracture flow, fracture–matrix interactions) tend to ‘obscure’ one of these systems when compared with theoretical models. Micro- (meso-) and macroporosity can merge into a single matrix porosity system where the permeability contrasts are not great and the correlation lengths short (which can often be the case in carbonates). Macroporosity can also appear in well testing to ‘merge’ with the fracture response, i.e. the contributions of flow in the fractures and (high-permeability) porous matrix are indistinguishable. As a result of the homogenizing attributes of pressure dissipation away from the well, it is not generally possible to see the effects of a ‘triple-porosity’ response (i.e. where three different pore systems have a separate and identifiable signature on the well-test response) and a classical double-porosity response in the well test, despite three different pore systems being present, is possible. The apparent double-porosity response, which might obscure a triple-porosity system, therefore needs careful interpretation in order to attribute the appropriate properties during reservoir characterization in carbonates. In this work we use ‘geological’ well testing (i.e. well testing through numerical simulation of hypothetical geological models) to systematically analyse the effects of microporosity, macroporosity and fracture porosity on pressure dissipation and their apparent homogenization. While recent studies have proposed that a triple-porosity system should result in a ‘W-shaped’ response, we do not observe this behaviour in our simulations, although we specifically designed our geological models with a triple-porosity system. Instead we observe how macroporosity merges with the fractures or micro- and macroporosity merge, creating a ‘sub-dominant’ matrix or a ‘dominant’ fracture system, respectively and follow a traditional ‘V-shaped’ double-porosity response.

Hydraulic fractures productivity performance in tight gas sands—a numerical simulation approach

The increasing global demand for energy along with the reduction in conventional gas reserves has lead to the increasing demand and exploration of unconventional gas sources. Hydraulically-fractured tight gas reservoirs are one of the most common unconventional sources being produced today and look to be a regular source of gas in the future. Hydraulic fracture orientation and spacing are important factors in effective field drainage and gas recovery. This paper presents a 3D single well hydraulically fractured tight gas model created using commercial simulation software, which will be used to simulate gas production and synthetically generate welltest data. The hydraulic fractures will be simulated with varying sizes and different numbers of fractures intersecting the wellbore. The focus of the simulation runs will be on the effect of hydraulic fracture size and spacing on well productivity performance. The results obtained from the welltest simulations will be plotted and used to understand the impact on reservoir response under the different hydraulic fracturing scenarios. The outputs of the models can also be used to relate welltest response to the efficiency of hydraulic fractures and, therefore, productivity performance.

Integrated Modeling of the Fractured Carbonate Midale Field and Sensitivity Analysis Through Experimental Design

Summary We used an integrated solution by combining "direct" and "inverse" approaches to fracture network characterization in a stochastic numerical model. Static geological data obtained from cores and well logs were used together with dynamic data such as well-test responses to build 3D discrete fracture-network (DFN) models. We used the data obtained from the fractured carbonate Midale field in Canada. The fractured-reservoir model was constructed from static and dynamic (drawdown and pulse-interference tests) data. Matrix and several fracture parameters including fracture length, density/ spacing, aperture, connectivity, and orientation were evaluated in a quantitative sensitivity study to determine which characteristics have a higher influence on the accurate match to well-test response. We used experimental design to optimize the number of simulations needed for a sensitivity study and history match. The sensitivity analysis revealed a strong influence of matrix quality on the pressure response, suggesting that the history match can be specific to the simulated process and not necessarily unique. The results emphasize the contribution of matrix in the Midale reservoir and the need to simulate a broader range of processes for an accurate description of the fracture/matrix system dynamics. In a general sense, the approach used in this study proved to be useful in integrating fracture data from different sources and assessing its reliability and relative importance.

Complex geology and pressure tests

The focus of this work is on the evaluation of well-test (single well and interference) responses in systems with complex geology where the assumption of statistical homogeneity does not hold. A 3D array (ordered set) of values for the properties of the porous medium (porosity cube) as a function of the coordinates is used to understand well-test responses. This array of values contains all relevant information available from prior geological and geophysical interpretations, core and outcrop measurements and rock physics. As this model is constrained by geological considerations, the underlying permeability field is nonGaussian. Characteristics of interference-test responses in the context of the reciprocity principle are discussed. Evaluations of transmissivity and storativity by various measures are given. Quantitative evaluations of tests along classical lines by the methods suggested by Theis or Jacob are compared with estimates obtained by the flow-based, upscaling technique. In the specific examples considered here, it is shown that estimates of transmissivity from pressure tests are much different from the upscaled estimate. For systems with complex geology, we show that measures of point values of permeability such as the median must account for connectivity within the reservoir before such measures may be used to reflect permeability. Both well-test and upscaled estimates of transmissivity are significantly higher than the median value corresponding to point values of permeability within the porosity cube. Estimates of the storativity product are also different from the upscaled estimate. Such differences are problematic in that the conservation of mass principle is violated. The results emphasize that it is essential to use geological models to obtain a realistic estimate of reservoir properties.

Well Testing: Analysis of Well-Test Responses in Gas/Condensate Reservoirs

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 81039, "A Novel Methodology for the Analysis of Well- Test Responses in Gas/Condensate Reservoirs," by K. Barrios (now with PDVSA), G. Stewart, SPE, (also with Edinburgh Petroleum Services), and D.R. Davies, SPE, Heriot-Watt U., Edinburgh, prepared for the 2003 SPE Latin American and Caribbean Petroleum Engineering Conference, Port-of-Spain, Trinidad, 27-30 April.

Transient Pressure Behaviour Of A Heavy Oil Reservoir Undergoing Steam Injection In The Presence Of A Bottom-Water Zone

Abstract There are numerous heavy oil reservoirs in Canada which are underlain by bottom-water zones and are undergoing steam injection. Steam may be injected in the reservoir or the bottomwater zone, depending on the injectivity considerations. Due to gravity override effects, zones swept by steam in these reservoirs may have irregular shapes. Using a new analytical solution for a multi-layer, composite reservoir model, this study investigates transient pressure responses for partially-penetrating, steam injection wells with irregularly-shaped fronts in the presence of infinite or finite bottomwater zones. Pseudosteady-state crossflow is allowed among adjacent layers to model the vertical flow of fluids. Pressure and pressure derivative responses have been studied to determine the effects of penetration ratio, crossflow parameters, mobility ratio, storativity ratio, and dimensionless front radii in different layers. Results of this study demonstrate the variety of well-test responses expected in such complex scenarios. Also, this study outlines the difficulties associated with the traditional pseudosteady-state approach to estimate the swept volume in the presence of bottom-water zone effects. However, this analytical transient-pressure model should prove helpful in automated (or automatic) type-curve matching analysis of well-test data obtained from thermal recovery operations with and/or without bottom-water zone effects. Introduction Steam injection process is widely used in heavy oil recovery operations. As a result of steam injection, at least two regions of different fluid properties are created and the reservoir resembles a composite reservoir. Because of gravity override effect, an inclined fluid front is created between the hot and the cold zones. Many times, heavy oil reservoirs are accompanied by a bottomwater zone. The purpose of this study is to investigate the transient pressure behaviour of a steam-stimulated heavy oil reservoir under bottom-water conditions. A reservoir undergoing a thermal recovery process has been idealized as a composite reservoir for a long time(l-6). But most of the studies consider-piston-like movement of the fluid front, neglecting the gravity override effect. Satman(7) used the concept of a tilted (inclined) front in pressure transient analysis of a two layer, composite reservoir. He proposed that fluid front would propagate at different rates in different layers. For steam flooding, Satman and Oskay(8) considered the discontinuity boundary as a tilted front to account for the gravity override effect and modelled the reservoir as a multi-layer, composite reservoir without crossflow. They concluded that the tilted-front model is a better representation of the actual reservoir. According to published reports on steam-drive projects(9,10), gravity override effect is a common phenomenon which results in a tilted front between the swept and the unswept zones. If gravity override effect is not taken into consideration, the predicted performance of the steam flooding project may be quite different than the actual performance. Singhal(l1) conducted some scaled physical model studies of steam-flood in a pool containing heavy oil. He presented some temperature profiles obtained from his model which showed very strong gravity override effect. Blevins et al.(9) discussed the application of steam-flooding for light oil reservoirs.