Reservoir Characterization Purposes Research Articles

A Coupled Model of Two-Phase Fluid Flow and Heat Transfer to Transient Temperature Distribution and Seepage Characteristics for Water-Flooding Production Well with Multiple Pay Zones

Temperature is one of the most prominent factors affecting production operations, predicting the accurate wellbore-formation temperature in a water-flooding production well is of great importance for multiple applications. In this paper, an improved coupled model of oil–water two-phase fluid flow and heat transfer was developed to investigate the transient temperature behavior for a producing well with multiple pay zones. Firstly, a novel method was derived to simulate the water saturation and the water breakthrough time (WBT) for tubing, which are key monitoring parameters in the process of water flooding. Then, we incorporated water saturation and an equation set for immiscible displacement to calculate the seepage velocity and the pressure of the two-phase fluid in the pay zones. Next, the upward seepage velocity of the tubing fluid change with depth was focused on, and the proper coupled initial and boundary conditions are presented at the interfaces, therewith the implicit finite difference method was used to compute the transient temperature with the input of the seepage characteristics for the reservoirs. Meanwhile, the validity of the proposed model has been verified by the typical model. Finally, a sensitivity analysis delineated that the production rate and the production time had a significant impact on the tubing fluid temperature. The overburden was hotter with a lower volumetric heat capacity or a higher thermal conductivity. In addition, the sensitivity of the porosity and the irreducible water saturation to formation temperature was significantly different before and after the WBT. The coupled model presented herein helps to advance the transient seepage characteristics analysis of pay zones, the precise temperature prediction is very useful for reservoir characterization and production analysis purposes and provides insight for designing the exploitation scheme in deep reservoirs and geothermal resources.

Improved natural state simulation of Arjuno-Welirang Geothermal field, East Java, Indonesia

Arjuno-Welirang Geothermal Field is a green field located across Mojokerto Regency, Malang Regency, Pasuruan Regency and Batu City in East Java Province, Indonesia. Geothermal system in Arjuno-Welirang Geothermal Field is estimated to be liquid dominated and has a reservoir temperature of about 260°C based on CO2 gas geothermometry method. Several manifestations are found at the surface; consist of hot springs, fumaroles and alterations. The field is now managed by Geo Dipa Energi. Geological, geophysical, and geochemical studies have been conducted in the field but exploration drilling has not been carried out yet until recently. For reservoir characterization and resource estimation purposes, several conceptual models have been developed based on available geoscience data. Previously, a natural state modelling attempted to match existing conceptual models has been carried out by Wardana. An entirely new natural state numerical model is made in this study to improve the result from previous model by using smaller grid blocks (40% finer). In return, the result shows more accurate temperature matching of surface manifestations than the previous model. The numerical model is developed using TOUGH2 simulator to obtain natural state condition. The objectives of this study are to develop an improved natural state numerical model; to validate temperature of the manifestations in the model with measured manifestation data; to characterize geothermal reservoir including area, thickness, pressure, temperature and permeability distribution; and to determine resource potential using probabilistic method. All data used in this paper are based on published papers.

Analytical Model to Detect Fault Permeability Alteration Induced by Fault Reactivation in Compartmentalized Reservoirs

AbstractUnderground fluid injection induces changes in in situ stress condition of the target formation and local faults that can potentially lead to fault reactivation, which may result in the leakage of injected and/or native fluids into neighboring formations. In this paper, we introduce an analytical method to detect fault reactivation caused by fluid injection into deep faulted aquifers considering across‐fault leakage. The fundamental assumption made in our model is that fault permeability will be altered upon fault slip. Therefore, we model fault reactivation as a sudden change in fault permeability at the onset of fault slip. The fault is modeled as a linear interface between two permeable formations with equal rock and fluid properties. The governing equations are coupled through the fault interface and are solved using the Laplace‐Fourier integral transform technique. Based on the analytical solution, we find the characteristic bottomhole pressure and pressure derivative responses that enable detecting fault reactivation using diagnostic plots. We observe that pressure derivative undergoes a rapid change at the onset of fault slip followed by a late‐time trend to attain a new equilibrium governed by the altered fault permeability. Furthermore, we discuss the evolution of the across‐fault leakage rate upon and after fault slippage. Results from this study are presented in the form diagnostic plots and type curves that may be used for reservoir and fault characterization purposes.

Temperature transient analysis for bounded oil reservoir under depletion drive

The significant pressure and temperature signals at wellbores associated with hydrocarbon production can be very useful for reservoir characterization and production analysis purposes. Temperature transient analysis is emerging partly due to the advancement of the downhole temperature monitoring system. Among different flow regimes encountered during the production of a vertical well, the long-lasting boundary dominated flow is crucial since most oil in conventional reservoirs are recovered during this period. The production induced temperature response behaves transient for boundary dominated pressure response and can be analyzed for reservoir property estimation. In this work, we derive a novel temperature transient analytical solution to model sandface temperature signal under boundary dominated flow. Our approach to obtaining the analytical solution from the governing energy balance equation uses Laplace transform with the input of pseudo-steady state pressure equation. This solution can be integrated with previous temperature transient analytical solutions to model the temperature signal from a depletion drived production well. The temperature modeling results acquired from this analytical solution are validated against those from numerical simulation in multiple cases and present distinct behavior under boundary dominated flow. Compared to the heating Joule-Thomson effect in the transient period near the production well, a cooling effect is observed throughout the reservoir after pressure transient reaches the reservoir outer boundary. The magnitude of this cooling effect is proportional to production time. This finding shows the potential of using temperature data at observation wells away from the production well during boundary dominated flow. Further parametric analyses are conducted on eight reservoir, production, and fluid properties to investigate their impacts on the temperature modeling results. These parameters are categorized based on their sensitivities on periods of transient and boundary dominated flow, in which total compressibility and production drainage area are sensitive to the temperature signals under boundary dominated flow only. Unlike the drawdown test, we find that the buildup temperature behavior under boundary dominated flow is identical to that during the transient period. After presenting the forward temperature modeling results, we extend existing reservoir characterization procedures to incorporate the boundary dominated flow. Drainage area and the distance to the closest boundary from the production well can be estimated from the measured temperature data acquired at both production and observation wells. Decent accuracies of the estimations are achieved for the examples presented in this work. The effects of thermal conduction and heat loss may not introduce significant errors in both forward and inverse thermal modeling for the long-lasting boundary dominated flow period.The temperature transient analytical solution under radial boundary dominated flow introduced in this paper considerably extends the scope for temperature transient analysis. This solution enables observation well temperature transient analysis, which seems promising for field application during the boundary dominated flow period. The analytical solution presented herein helps to advance the temperature transient analysis over the whole well production period and forms a basis for future studies on variable rate temperature transient analysis (rate-temperature transient analysis).

Reservoir properties prediction integrating controlled-source electromagnetic, prestack seismic, and well-log data using a rock-physics framework: Case study in the Hoop Area, Barents Sea, Norway

We have developed an example from the Hoop Area of the Barents Sea showing a sequential quantitative integration approach to integrate seismic and controlled-source electromagnetic (CSEM) attributes using a rock-physics framework. The example illustrates a workflow to address the challenges of multiphysics and multiscale data integration for reservoir characterization purposes. A data set consisting of 2D GeoStreamer seismic and towed streamer electromagnetic data that were acquired concurrently in 2015 by PGS provide the surface geophysical measurements that we used. Two wells in the area — Wisting Central (7324/8-1) and Wisting Alternative (7324/7-1S) — provide calibration for the rock-physics modeling and the quantitative integrated analysis. In the first stage of the analysis, we invert prestack seismic and CSEM data separately for impedance and anisotropic resistivity, respectively. We then apply the multi-attribute rotation scheme (MARS) to estimate rock properties from seismic data. This analysis verified that the seismic data alone cannot distinguish between commercial and noncommercial hydrocarbon saturation. Therefore, in the final stage of the analysis, we invert the seismic and CSEM-derived properties within a rock-physics framework. The inclusion of the CSEM-derived resistivity information within the inversion approach allows for the separation of these two possible scenarios. Results reveal excellent correlation with known well outcomes. The integration of seismic, CSEM, and well data predicts very high hydrocarbon saturations at Wisting Central and no significant saturation at Wisting Alternative, consistent with the findings of each well. Two further wells were drilled in the area and used as blind tests in this case: The slightly lower saturation predicted at Hanssen (7324/7-2) is related to 3D effects in the CSEM data, but the positive outcome of the well is correctly predicted. At Bjaaland (7324/8-2), although the seismic indications are good, the integrated interpretation result predicts correctly that this well was unsuccessful.

Multiwavelet prestack Kirchhoff migration

The problems of stretching and aliasing usually occur in prestack Kirchhoff migration. A multiwavelet-based approach is proposed to provide an alternative approach to resolve these problems. Two steps are involved in the multiwavelet-based algorithm: The first step is the decomposition of the seismic traces with a series of wavelets of different dominant frequencies. This step is based on the principle of basis pursuit and is enhanced for more accurate and sparse decomposition by adding an adaptive subdictionary that is associated with the minima and maxima of a seismic trace. The second step is wavelet migration based on the Kirchhoff formulation using a novel approach. The outer iteration is the wavelets of the input seismic traces, which ensures that an input wavelet is only used once in the entire migration process. This enables output of multiple migrated images of different wavelets of dominant frequency ranges, elimination of noisy images, and composition of images for specific interpretation and reservoir characterization purposes with very little extra computational cost. The stretching and aliasing problems are naturally resolved because interpolation on the seismic trace is not required in the migration. We tested the algorithm using a synthetic model with a dipping layer and a 2D real seismic section. We compared our results with results obtained by conventional Kirchhoff migration.

Identifying watershed-scale groundwater flow barriers: the Yoqne’am Fault in Israel

Geological faults may serve either as groundwater conduits or barriers, depending on their hydraulic properties. Determining fault characteristics is therefore important when deciding inputs for numerical models developed for watershed-scale groundwater studies. Cutting-edge methods for determining fault characteristics have been widely applied for oil and gas reservoir characterization purposes, whereas water-resource studies simply use a priori values. This study evaluates the hydraulic properties of the Yoqne’am Fault (YF) in northern Israel, which impacts groundwater flow within the Judea Group Aquifer (JGA). The YF has a vertical throw of several hundred to one thousand meters accompanied by pronounced lateral throw. Detailed examination of hydrological and geochemical data from nearby wells, structural maps and numerical modeling results, suggests that the YF acts as a semi-impermeable feature with a hydraulic conductivity of less than 4 × 10e−2 m/d. The YF hydraulic conductivity is four orders of magnitude below that of the surrounding Judea Group rocks, and only a limited volume of water can leak through the fault. For that reason, it is concluded that the YF acts as a boundary between two large groundwater basins.

An overview of developments related to the characterization and significance of high molecular weight paraffins/hydrocarbons (>C 40 ) in crude oils

Abstract Over the past 10 years, investigations into the characteristics of the high molecular weight hydrocarbon (HMWHC) fraction in crude oils and, to a lesser extent, source rock extracts have continued to reveal novel information concerning the distribution of hydrocarbons >C 40 . The major impetus for this work has come from the fact that HMWHCs can cause significant production problems in certain geographical regions and particularly deepwater frontier areas. Since these HMWHCs appear to be ubiquitous in crude oils, the primary questions that need to be addressed are: what are these compounds, where do they come from, and how do they affect physical properties of oils? Here, we review our work over the past decade and discuss the significance of these results and their potential application to reservoir and production problems involving paraffins and asphaltenes. It was commonly believed for many years that only oils derived from source rocks containing higher plant source material would have a high paraffin content. However, it is now abundantly clear that oils derived from lacustrine and marine source rocks also contain relatively high concentrations of higher molecular weight hydrocarbons. In addition to developing methods for the qualitative and quantitative separation of HMWHCs from asphaltenes, progress has been made in identifying individual components of the high molecular weight fraction. This fraction is not a simple mixture of n -alkanes but a complex mixture of seven or eight homologous hydrocarbon series, each with significantly different physical properties. A knowledge of these structures is important in predicting crude oil properties such as cloud point and pour point. Series identified to date include alkylcyclopentanes, alkylcyclohexanes, alkylbenzenes and various branched hydrocarbons. In summary, since the 1970s most of the geochemical research emphasis has been placed on compounds below C 40 . Whilst compounds above C 40 may not have the same degree of structural specificity as the traditional biomarkers, the amount of information available from these compounds could be extremely beneficial in the long term, particularly for reservoir characterization and production purposes and other problems involving high molecular weight hydrocarbons.

Model‐based prediction of porosity and reservoir quality from P‐ and S‐wave data

We present a deterministic methodology for mapping the lithology, pore fluid, and porosity from seismic data. The input is the P‐ and S‐wave data volumes that may come, e.g., from acoustic and elastic inversion or cross‐well measurements. The output is the pore fluid type (hydrocarbon versus water), total porosity, and clay content. The key element of this methodology is a site‐specific rock physics model that provides the needed transforms from the elastic rock properties to the reservoir properties. This model is established by comparing model‐based predictions, such as impedance versus porosity, to the relations present in well log data. Once selected, the model is used to identify the presence of hydrocarbons from a combination of the P‐wave impedance and Poisson's ratio. Then the P‐wave impedance is used to map porosity and clay content assuming that a deterministic relation exists between the latter two properties. All deterministic equations are calibrated at a well and then are applied to upscaled well log data to confirm their validity at the seismic scale. This methodology is applied to log data from a fluvial environment. The results indicate that the relative error in porosity determination is 14%, which is acceptable for reservoir characterization purposes.

Surrogate modeling-based optimization for the integration of static and dynamic data into a reservoir description

This paper presents a solution methodology for the inverse problem of estimating the distributions of permeability and porosity in heterogeneous and multiphase petroleum reservoirs by matching the static and dynamic data available. The solution methodology includes, the construction of a “fast surrogate” of an objective function whose evaluation involves the execution of a time-consuming mathematical model (i.e., reservoir numerical simulator) based on neural networks, DACE (design and analysis of computer experiment) modeling, and adaptive sampling. Using adaptive sampling, promising areas are searched considering the information provided by the surrogate model and the expected value of the errors. The proposed methodology provides a global optimization method, hence avoiding the potential problem of convergence to a local minimum in the objective function exhibited by the commonly Gauss–Newton methods. Furthermore, it exhibits an affordable computational cost, is amenable to parallel processing, and is expected to outperform other general-purpose global optimization methods such as, simulated annealing, and genetic algorithms. The methodology is evaluated using two case studies of increasing complexity (from 6 to 23 independent parameters). From the results, it is concluded that the methodology can be used effectively and efficiently for reservoir characterization purposes. In addition, the optimization approach holds promise to be useful in the optimization of objective functions involving the execution of computationally expensive reservoir numerical simulators, such as those found, not only in reservoir characterization, but also in other areas of petroleum engineering (e.g., EOR optimization).

Facies and Architecture of Deep-Water Sandstone Lobes: Comparison of a Shale-Rich and a Sand-Rich System

Two different foreland-basin deep-water sandstone systems have been studied for reservoir characterization purposes: the Broto lobes of the Eocene Hecho group, spain, and two sand bodies of the Oligocene-Miocene Arakintos Sandstone, Greece. The shale-rich Broto lobes are characterized by distinct vertical developments in terms of facies and expression of heterogeneity. Bed-thickness trends, lateral extent of sand beds, and facies variability are related to overall sand/shale ratio. A feature common to most of the sandstone packages is the occurrence of a basal slump and/or pebbly mudstone. The dominant sediment source is considered fluvial. Variation in sand quality within and between lobes is high. Deposition is considered to be strongly controlled by tectonics. The sand-rich Arakintos Sandstone consists of massive and pebbly sandstones, forming thick, sandy sheets alternating with relatively coarse-grained, thin-bedded turbidites. Facies, geometries, vertical organization, and the relation between grain size and bed thickness indicate a constrained development of the lobes, partly influenced by preexisting topography. A coastal sediment source is inferred. Little variation exists in sand quality within and between the lobes. The overall regularity in terms of facies, and the absence of slumps, suggest that fluctuations in relative sea level may have formed a major control on deposition.more » The two lobe systems illustrate the effect of tectonics, sediment type, topographic confinement, and possible sea level on facies and sand body architecture of deep-water sandstone lobes.« less

Pressure Transients Characterize Fractured Midale Unit

Summary The Midale Unit is a naturally fractured carbonate reservoir in the Williston basin of southeastern Saskatchewan. Recently, the Midale working-interest owners initiated a CO2-flood pilot project with several closely spaced wells. A comprehensive interwell pressure-transient test program was conducted for reservoir-characterization purposes before pilot program was conducted for reservoir-characterization purposes before pilot operations began. The combination of conventional, pulse, and interference tests resulted in a detailed local description of this naturally fractured reservoir. Selected pressure-transient data from the reservoir-characterization program are presented. The data dramatically illustrate the program are presented. The data dramatically illustrate the pressure-transient characteristics of an anisotropic, naturally fractured pressure-transient characteristics of an anisotropic, naturally fractured reservoir. Analytical techniques are reviewed briefly, and an interpretation technique for multiwell pressure-transient tests in wells with negative skins is included. A discussion of the pressure-transient behavior that is observed in wells with typical field spacing is also included. Introduction A significant proportion of the world's oil reserves exists in naturally fractured rocks. As a result, the pressure-transient behavior of naturally fractured reservoirs has been studied widely. These reservoirs, referred to as dual-porosity or dual-permeability systems, can be modeled with matrix blocks of various shapes separated by continuous fracture networks. Typically, the system permeability is largely associated with the fractures, while the tighter matrix contains most of the reservoir-storage volume and acts as a fluid source for the fracture network. Initial production from dual-porosity reservoirs is from the more permeable fracture network, which results permeable fracture network, which results in pressure decline in the fractures. Depletion of the fracture system causes pressure gradients to develop between the matrix blocks and the fractures, which results in fluid flow from the blocks into the fractures. This transitional flow period controls the reservoir-pressure behavior until the matrix fracture pressure regime equilibrates, after which the reservoir acts as a uniform system with composite properties. Pressure-transient testing is an important technique used to describe naturally fractured reservoirs. Each flow period (fractures, transitional, and composite) has distinctive pressure-transient characteristics. Pressure-transient behavior in real Pressure-transient behavior in real dual-porosity reservoirs, however, can be subtle and ambiguous, especially in normal situations with typical well spacing. For example, pressure transients controlled by depletion of the fracture network are rarely seen in the field because of the fast onset of the transitional flow period. Transitional- and composite-system pressure transients can be attributed to such other causes as layers, skin, faults, or boundaries. Wellbore storage can obscure key parts of the pressure-transient curve. For these and other pressure-transient curve. For these and other reasons, few comprehensive pressure-transient data bases exist for naturally fractured reservoirs. The scarcity of good data impedes refinement and validation of precise pressure-transient models. The Midale field (Fig. 1) produces oil from relatively tight, naturally fractured carbonates. The field was discovered in 1953 and produced competitively under primary depletion until unitization for waterflooding in 1962. Secondary performance is dominated fieldwide by the oriented-fracture system, which causes a permeability anisotropy of about 25:1. Recent implementation of a tertiary miscible CO2-flood pilot project in the Midale Unit, with 10 wells on 4.4 acres [1.8 ha], has allowed for very detailed reservoir characterization. Conditions in the Midale CO2-flood pilot are amenable to both single- and multiwell pressure-transient programs. An extensive, precise pressure programs. An extensive, precise pressure transient data base was acquired during pilot-testing operations. The reservoir pilot-testing operations. The reservoir model that was obtained from pressure-transient analyses is consistent with geological, petrophysical, and operational data, and it petrophysical, and operational data, and it provides significant refinement over earlier provides significant refinement over earlier reservoir models.