In this paper we demonstrate the successful identification of a new flow problem of an intersected natural fracture connected to (or near) a finite conductivity fault. In a previous paper, finite conductivity faults in connection with high permeability layers were identified in mature parts of Ghawar field(1). Four field cases are presented in this paper; a slanted well intersecting a fracture, a well close to a finite conductivity fault and a combination of the two. In the latter case, two examples of a fracture behavior at early times and a finite conductivity fault behavior at late times were identified. Because of the complex nature of these flow problems, numerical simulation along with all available data was integrated including 3D seismic to match the pressure response. Introduction This work is part of a study to characterize faults and fractures in the Ghawar field. Fractures and faults play a significant role in reservoir recovery and performance. While fractures can enhance the recovery of hydrocarbons from tight formations, the highly permeable conduits they form could also lead to a pre-mature breakthrough of water or gas. The identification and characterization of these faults/fractures network and their bhavior have become increasingly important with increased horizontal and multilateral wells drilling in this field. Thus, early identification of these geological features is a great challenge to reservoir engineers. The Ghawar field is located in the eastern part of the Arabian Peninsula. It is an anticline extending north-south of approximately 225 km in length and 35 km in width. It is divided into six operating areas. These areas are, from north to south, Fazran, Ain Dar, Shedgum, Uthmaniyah, Hawiyah and Haradh. There are ten different hydrocarbon-bearing stratigraphic horizons the Ghawar field. The two lower-most are of Devonian and early Permian clastics. The rest are carbonate deposits of late Permian and Jurasic age (Fig. 1)(2). From hundreds of field cases in heavily faulted areas, three examples were selected to illustrate some typical patterns of reservoir pressure response observed in the Ghawar field. These patterns include a slanted well intersecting a fracture (or fault) and a well close to an active finite conductivity fault(1). The third example represents a new flow system of a combined behavior of the above two examples; a well that intersects a natural fracture/fault and is connected to (or near) a finite conductivity fault (Figs 2 & 3). Well Intersecting a Natural Fracture - Case 1 This well was drilled and completed as slanted openhole oil producer to a total depth of 7270 ft across Arab-D reservoir. A flowmeter run across the entire openhole section indicates that 96% of the total oil is produced from an 8-feet interval (7080- 7088 ft). The analysis of the image log indicates the presence of a sub-seismic fracture at 7085 ft with an apparent enlargement in hole size. Openhole logs show low permeability and porosity in that zone, where the fracture is detected. Correlating all these data cofirms the presence of a fracture or a fault (Fig. 4). The derivative plot of the build up test (Fig. 5) confirms the observation made from the openhole and production logs analysis. It shows a very short wellbore storage period, followed by a long linear flow regime that dominates the rest of the test. An infinite conductivity fracture well model was used to match the pressure build up data and to obtain the reservoir parameters. Well Near a Finite Conductivity Fault - Case 2 This well was drilled and completed as a deviated openhole producer to a total depth of 7374' in July 1995, across the whole Arab-D reservoir.
A reservoir system with two neighboring layers, the tested and the adjacent layers being separated by impermeable strata, is considered. Fluid may still migrate from the adjacent layer to the tested layer if the zonal isolation behind casing is compromised or flow channels exist in the vicinity. A method is presented to diagnose the fluid contribution to the tested layer from the adjacent layer, and to quantify the transient rate of cross flow by utilizing the transient-pressure data.During transient tests on the tested layer, the cross flow from the adjacent layer has to be accounted for to ascertain reasonable characterization of the tested layer. A new analytical solution for a two-layer system with cross flow behind casing has been employed to understand the effects of cross flow on the transient behavior in the tested layer. Matching of type curves with measured pressures helps diagnose the presence of cross flow behind casing and estimate parameters. The cross-flow rate as a function of time is also estimated by quantifying the hydraulic conductivity of the compromised zonal isolation.This study shows that the magnitude of the hydraulic conductivity of the compromised zonal isolation or flow channels has a strong effect on the rate of cross flow with the flow capacities of individual layers. There is an upper limit of the conductivity of the zonal isolation beyond which the cross-flow rate is limited by the layer flow capacities. For a given two-layer system, the cross-flow rate increases with time for a constant rate drawdown in the tested layer due to the increasing pressure differential across the compromised zonal isolation. The test duration is another important aspect which lets the cross-flow rate reach a critical value to be detected in the log-log plot of the pressure derivative. This means that a long transient test is likely to be affected substantially by the cross flow behind casing.Field examples with build-up test data are presented to illustrate the methodology. These show that ignoring the flow behind casing may lead to an over-estimated flow capacity of the tested reservoir layer. Matching of the transient-test data also provides estimates of the conductivity of the zonal isolation, which leads to computing the transient cross-flow rates.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper presents a successful multi-well test analysis approach to identify and locate the geological feature(s) responsible for inter-reservoir communication between Lower and Upper reservoirs in ABQQ field. The study resulted in locating and identifying the nature of conduit(s) responsible for the direct communication between Lower and Upper reservoirs. Conductive fault(s) is/are observed repeatedly by five offset wells and clearly running between the two reservoirs. The location of the fault/faulted zone was predicted via an integrated approach including analyzing all the wells in the vicinity of the area under study and reviewing the drilling, logging and production data.An interference test was conducted after producing Lower injected water from Upper reservoir. The test indicated a direct communication through five hundred feet of nonreservoir formation between the two reservoirs.Many hydrocarbon bearing reservoirs are faulted, yet little information is available about the actual physical characteristics of the faults. Loss circulation while drilling horizontal wells, along with production logs provided tangible evidence of existing conductive faults. Drilling horizontal wells also indicated the existence of sub-seismic faults which cannot be detected by the 3D seismic resolution.Better reservoir management decisions and more focused development strategies can be achieved through the utilization of the quantitative pressure transient analysis of those tests.
The Unayzah-A in field T is an Aeolian sandstone formation with high sanding tendency requiring stimulation using the frac pack technique. Modified Isochronal Tests (MIT) and pressure buildups (PBU) were conducted on several wells in field T, to assess the reservoir and to evaluate the frac pack technique. During the analysis of the MITs and PBUs, several consistent trends were observed in the pressure derivative plots of field T wells, such as the absence of the fracture signature and the decrease of reservoir quality away from the wellbore. This consistency in the behavior of the pressure derivative was investigated in this study. Analytical and numerical well testing models, reservoir characterization, and fracturing analysis assisted in investigating the observations in PBUs. The investigation showed that to capture a fracture in the pressure derivative plot of high permeability formation, the fracture half length has to be extremely long, and there should be significant contrast between the fracture and the formation conductivities. The investigation also showed that the created fracture and the reservoir heterogeneity due to changes in geologic facies dictate the shape of the pressure derivative plot. This paper will discuss how the reservoir characterization and the fracturing analysis were used to help in analyzing the pressure transient response of frac packed wells. Two pressure buildups (PBUs) and four MITs were used in this study. This paper will also shed some light on the frac pack results, and the non-Darcy flow effect.
The objective of this study was to investigate a workflow where well test data could be used more effectively in history matching of full-field reservoir simulation models and also in situations where existing simulation models could be used in well test interpretation. The need to effectively use information available from well test analysis in full-field simulation has long been recognized. However, only limited benefit could be obtained by reconciliation of the analytical well test model with the numerical full-field model. We present a more complete approach where a more integrated approach using a common model is advocated.. The benefits of such a workflow can be summarized as follows: Existing commercial well test and near wellbore modeling software packages, were used to carry out this task. These packages provide engineering interfaces to the simulator that make their respective workflows easy. However, there were a number of situations where manual intervention and workarounds were necessary. We would like to propose an easy to use software that can provide a complete workflow for regular use. Introduction The link between reservoir simulation and well testing has been growing steadily for several years. Raghavan, et al1. have reviewed its development in their work. They found that there are three broad areas where there are growing industry interests: The first has been the subject of interest for some time. Most well testing software with numerical option focus on this aspect. There are a number of papers that has been published in the last few years 2,3,4 Currently, we are interested in a consistent and integrated workflow for the latter two areas. Corbett et. al.5. used a numerical model of braided fluvial reservoirs to calculate well test responses. A "geo-skin concept" was developed from these data to be used in a full-field model. He and Chambers6 presented a methodology to verify and update geostatistically-based full-field reservoir simulation models using numerical well testing. The authors pointed out the difficulty in history matching during a simulation study due to the large uncertainties associated with reservoir properties in flow simulation models particularly for permeability. This is because of limited core sampling from the reservoir and difference in scale between grid block and core permeability. Well test data is ideal for bridging the gap between core and grid block permeabilities because it samples the reservoir on the scale of the grid block size. The authors recognized that well tests would not fully cover the full field model. Therefore, they found it useful to calculate property multipliers around each well and then interpolate multipliers to untested areas in the reservoir.
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