Early Water Breakthrough Research Articles

Effect of bioturbation on petrophysical properties: Insights from geostatistical and flow simulation modeling

As observed in many outcrops and cores, Thalassinoides burrow networks (TBN) within Glossifungites surfaces can be important for permeability enhancement, because the coarse-sediment infill provides permeable pathways in otherwise less permeable media. To explore the effect of bioturbation on reservoir quality, this study uses geostatistical models and fluid-flow-simulation models of TBN and burrow medium (matrix) of hypothetical TBN-bearing strata. Analysis of these models reveals a well-connected burrow network can occur in strata of as little as 12% burrow intensity, and burrow connectivity increases nonlinearly with increases in burrow intensity. Numerical flow simulations of TBN models indicate that gas production cumulative (GPC) is controlled primarily by TBN connectivity and matrix permeability. With an impermeable matrix, production comes through TBN (50 mD average permeability), starts only at burrow intensity of 30%, and GPC increases linearly with burrow intensity. With a permeable matrix (5 mD average permeability), and low permeability contrast between matrix and TBN (one order of magnitude) production starts at relatively low TBN intensity (4%), and GPC increases nonlinearly with burrow intensity. The interaction between matrix and TBN seems to connect more isolated TBN bodies, and increase GPC, and likely help the gas diffusion from matrix through TBN. The fluid flow simulation also illustrates the likelihood of the presence of permeability that drives early water breakthrough (super k) at burrow intensity > 50%. The results advance quantitative understanding of the impact of burrow connectivity on fluid flow properties of TBN-bearing strata and provide a workflow that can be used to model other burrow morphologies to understand their impact on flow properties of bioturbated reservoirs.

Multi-Level and High-Resolution Fracture Modeling, Simulation and History Matching in Field-scale Reservoir Study

Carbonate formations are usually highly fractured. The fractures exist at all length scales ranging from microscopic fissures to kilometer-size structures. Consequently, it is vitally important to rigorously characterize the multi-scale fracture system and to accurately model the fluid flow in such highly fractured porous media. In this paper, we will present an integrated workflow for characterization of natural fracture system and accurate numerical modeling of fluid flow in fractured rocks.The fracture characterization usually involves the integration of multiple data sources including core analysis, image logs and seismic interpretations etc., at different scales. The fracture mappings are thus required to perform at different length scales and resolutions. In this study, we present a systematic approach that characterizes the actual fracture distribution with seismic and log interpretations. Firstly, the small-scale fractures are interpreted using image logs and seismic anisotropy analysis with a co-Kriging and stochastic modeling approach. The small-scale fractures are initially constructed in an explicit fashion, and are then incorporated in the matrix medium using a flow-based upscaling procedure. Secondly, the large-scale fractures are mapped out from post-stack seismic data with ant-tracking and maximum curvature analysis. The reservoir is then gridded into unstructured tetrahedral or prism meshes to fully resolve these large fractures. This discrete fracture model (DFM) is employed in a reservoir simulation study based on such grid system.We applied the procedure for simulation study and history match on a portion of a carbonate gas reservoir in Longwangmiao formation in Southwest China. Currently, there are 7 horizontal and 2 vertical wells in operation. Due to the connection of some large-scale fractures to edge water, early water breakthrough and drastic water invasion were observed. We partitioned the reservoir block into 0.6 million cells, in which 153 large-scale and thousands of small-scale fractures are fully resolved. The simulation study was performed and automated history match was successfully achieved using our extended Ensemble Karman Filter algorithm based on a parameterized description of the fractures that are explicitly represented in DFM. This proposed overall procedure is able to efficiently capture such extreme flow dynamics and achieve significantly better history match results.

Predicting Performance of High Deliverability Horizontal Gas Wells and Control of Water Cresting in Tertiary Sands East Africa

The field-A1 is an offshore gas field located about 56 km from the coast of East Africa with the water depth of 1153 m. The permeability distribution varies across different layers with an overall permeability of 680 m and porosity distribution for the reservoir field-A1 varies 0.21-023. The reservoir thickness also varies up to 50 m thick. This research work identifies parameters that will contribute to the impact of water coning. Simulation sensitivities are run to observe the effect of water coning/cresting in horizontal gas wells and predicting the performance of these wells using Petrel simulator. Results have shown that put horizontal well in East-west will have early water breakthrough and not recommended due to the impact of edge aquifer due to less recovery compared to north-south and original wells orientation (northwest-southeast). The varying height of perforation and standoff as identified is at the standoff between 30-40 m in the field-A2 will delay water coning high recovery with more extended plateau length period. The gas recovery may happen to be low, due to the distribution of permeability layer for the horizontal wells and low productivity index that is the performance of the well. Rate-dependent skin and mechanical skin evolution in time show that increasing non-Darcy /turbulence factor reduces the performance of the well and decreases gas recovery the high drawdown tendency is observed before water breakthrough time however there is early water breakthrough, thus use of deep penetration. Horizontal gas wells have a constant horizontal length for all cases of 300 m increasing tubing head pressure from 40-100 bars result to decrease plateau length period of the gas production, low water production rate, and low gas recovery. Varying the kv/kh ratio from 0.1, 0.6 to 1 shows early water breakthrough by 6 months earlier from the base case with 0.1 hence will not delay water coning. The gas recovery is reduced by 5%. Gas recovery is increased with an increase in gas rates constrain, and early water breakthrough is observed when producing at high rates. Producing at low rates may delay water coning. However, it is not economical since there is less gas recovery and may take a more extended period for production to reach to its total maximum gas production of which is less compared when producing at high gas rates. There is a stronger of the aquifer from the west side, which is predictable to cause water coning than on the east side. This aquifer impacts the gas recovery reduction by 19%, with water coning radial extension of 1.7 km and peak water production rate for 16 years. The aquifer influx rate is seen to be increased by 69% when the aquifer volume is double. Therefore, from the results producing at a high rate that has high recovery before the impact of aquifer or water has occurred to the wells, known as outrunning of the aquifer. To avoid water coning, using advance completion technique such as inflow control devices (ICD), installing a down hole gauge. Also, it is essential not to perforate if well is near to gas water contact the horizontal wells should be located at maximum distance from gas water contact to maximize gas recovery. Not only that but also use of fully open choke allows much water production rate increase, which leads to water coning.

Predicting Performance Of High Deliverability Horizontal Gas Wells And Control Of Water Cresting In Tertiary Sands East Africa

The field-A1 is an offshore gas field located about 56 km from the coast of East Africa with the water depth of 1153 m. The permeability distribution varies across different layers with an overall permeability of 680 m and porosity distribution for the reservoir field-A1 varies 0.21-023. The reservoir thickness also varies up to 50 m thick. This research work identifies parameters that will contribute to the impact of water coning. Simulation sensitivities are run to observe the effect of water coning/cresting in horizontal gas wells and predicting the performance of these wells using Petrel simulator. Results have shown that put horizontal well in East-west will have early water breakthrough and not recommended due to the impact of edge aquifer due to less recovery compared to north-south and original wells orientation (northwest-southeast). The varying height of perforation and standoff as identified is at the standoff between 30-40 m in the field-A2 will delay water coning high recovery with more extended plateau length period. The gas recovery may happen to be low, due to the distribution of permeability layer for the horizontal wells and low productivity index that is the performance of the well. Rate-dependent skin and mechanical skin evolution in time show that increasing non-Darcy /turbulence factor reduces the performance of the well and decreases gas recovery the high drawdown tendency is observed before water breakthrough time however there is early water breakthrough, thus use of deep penetration. Horizontal gas wells have a constant horizontal length for all cases of 300 m increasing tubing head pressure from 40-100 bars result to decrease plateau length period of the gas production, low water production rate, and low gas recovery. Varying the kv/kh ratio from 0.1, 0.6 to 1 shows early water breakthrough by 6 months earlier from the base case with 0.1 hence will not delay water coning. The gas recovery is reduced by 5%. Gas recovery is increased with an increase in gas rates constrain, and early water breakthrough is observed when producing at high rates. Producing at low rates may delay water coning. However, it is not economical since there is less gas recovery and may take a more extended period for production to reach to its total maximum gas production of which is less compared when producing at high gas rates. There is a stronger of the aquifer from the west side, which is predictable to cause water coning than on the east side. This aquifer impacts the gas recovery reduction by 19%, with water coning radial extension of 1.7 km and peak water production rate for 16 years. The aquifer influx rate is seen to be increased by 69% when the aquifer volume is double. Therefore, from the results producing at a high rate that has high recovery before the impact of aquifer or water has occurred to the wells, known as outrunning of the aquifer. To avoid water coning, using advance completion technique such as inflow control devices (ICD), installing a down hole gauge. Also, it is essential not to perforate if well is near to gas water contact the horizontal wells should be located at maximum distance from gas water contact to maximize gas recovery. Not only that but also use of fully open choke allows much water production rate increase, which leads to water coning.

Research and application on simulation of oilfield 3D in-situ stress field by multi-information co-processing

When designing an oilfield development program and deploying well patterns, it is often assumed that the maximum principal stress is along a single direction. A wrong determination of the principle stress may cause early water breakthrough and thereby abate production results. In-situ stress field has significant impacts on well pattern design and hydraulic fracturing. To obtain the distribution of a 3D in-situ stress field for a research area, the single-well in-situ stress curves were built by synthesizing laboratory experiments, fracturing results, and experienced formula and logging information. A 3D in-situ stress model was built by stochastic modeling. First, the relationship between vertical compressional wave velocity and longitudinal compressional wave velocity was established. Then, a calculated model of corrected rock mechanical parameters model was built with a triaxial rock mechanics testing system, and a modified tectonic stress coefficient was established according to fracturing data. In accordance with the calculated model and correction coefficient, the single-well in-situ stress variation curve is then determined. Base on the obtained single-well curve, a logging curve, a 3D in-situ stress model of the area was built by applying the stochastic modeling method. Further applications of the 3D in-situ stress field model were finally demonstrated through comparison of simulated results with field monitoring data in Ordos Basin. The results demonstrated high accuracy of the new model and therefore provided guidance to reservoir simulation and well pattern design for low-permeability reservoirs.

A novel approach to assessing the anisotropic permeability parameters of fractured media

The fracture permeability in is very high and directional, which brings a series of problems for the petroleum reservoir development, such as earlier water breakthrough and low sweep efficiency. It is vital to accurately characterize fractures and acquire the parameters of fracture permeability to alleviate these issues, which are favorable for well pattern design and flow modeling. Permeability tensor is employed to comprehensively and expediently reflect the effect of fracture anisotropy on the fluid diversion. Based on information of fracture log and production, the complete permeability tensors of single group fractures and multiple group fractures are identified, where the coordinate transformation theory and tensor property are used. With the simplified form of the derived full permeability tensor, the anisotropic parameters, principal values and principal directions of permeability for the fractured reservoir, can then be calculated. The proposed method integrates the static characterization and percolation feature of fractures and can be applied merely into field practices of naturally fractured reservoir. This work is beneficial for the management of fractured reservoir and optimization of field development.

Is it worth the effort? — why state-of-the art reprocessing of old seismic data was an indispensable tool for a reservoir simulation study in the Murzuq Basin (Libya)

Field development and reservoir simulation studies are usually performed relatively late in the life of an oil or gas field. At this time, specific questions such as mitigating early water breakthrough, infill well locations, fracture behaviour and so on need to be addressed. Typically, this is done through reservoir simulation studies. Commonly, the available 3D seismic data was acquired early in the field life for exploration or appraisal purposes. In many reservoir simulation studies the question arises as to whether it is worth the effort to reprocess vintage seismic data, or use only available fault and horizon interpretation of the original or previous processing for building the static model and simulation grid. Unfortunately, the latter approach is often followed, since seismic reprocessing is time-consuming and often perceived as awkward. We cannot deny the fact that seismic processing has made significant progress in recent years. However, the application to relatively old data is often regarded as suspect. The applicability of methods developed for high density, wide azimuth/large offset surveys, to poorly sampled data, is questioned.

Numerical simulation of mineral precipitation in hydrocarbon reservoirs and wellbores

Mineral precipitation or scale formation in reservoirs, injection, and production wells is recognized as an obstacle for hydrocarbon recovery. Significant production drops and injection losses can occur as a result of mineral precipitations during water flooding. Several attempts have been made to better understand the underlying mechanisms of mineral precipitation through experimental and numerical simulation studies. In this study, we have investigated the impact of mineral precipitation on oil recovery and injection performance of a synthetic reservoir through numerical simulations. Additionally, we studied the scaling (scale formation) tendency and precipitation amount of various minerals in wellbore based on water compositions from the Gulf of Mexico. We also studied the impact of mineral precipitation on water flooding efficiency by analyzing saturation profiles of the injected water. Our results indicate that the reservoir experiences severe damage with respect to ultimate recovery, and injectivity loss due to the scale formation. Water saturation profiles reveal that mineral precipitation in reservoirs not only leads to non-ideal displacement of the in-situ hydrocarbon, but also causes earlier water breakthrough. The results of mineral precipitation in wellbore show that while some minerals (e.g., calcite) precipitate in large amounts, other minerals (e.g., gypsum) remain in equilibrium with the flowing brine in wellbore under the same pressure and temperature conditions.

An experimental study for carbonate reservoirs on the impact of CO2-EOR on petrophysics and oil recovery

The injection of CO2 into deep geological structures for the purpose of CO2 storage and/or enhanced oil recovery (CO2-EOR) may trigger a series of consecutive chemical reactions (e.g. mineral dissolution and asphaltene precipitation) and physical effects (e.g. mechanical compaction and permeability variation). These reactions can significantly impact carbonate reservoirs, due to the presence of highly reactive minerals (e.g. dolomite and calcite), as well as the solvent/precipitation effects of supercritical CO2 on complex crude oil mixtures potentially containing heavy fractions such as wax and asphaltene. A core flooding study has been carried out to evaluate changes in the petrophysical properties of a number of heterogeneous carbonate samples (i.e. limestone and dolostone) after undergoing EOR activities under in situ reservoir conditions. In this study, a number of different measurement techniques are conducted to obtain a comprehensive view of the role that mineral dissolution, mechanical compaction and asphaltene precipitation plays during CO2-EOR in carbonate reservoirs.The results show that CO2 injection results in higher oil recovery in all the samples evaluated as part of this study. However, early water breakthrough was observed for most samples suggesting a high degree of heterogeneity in the carbonate core samples. In all samples, a decrease in permeability was observed presumably due to asphaltene/resin precipitation and mineral dissolution/precipitation. Chemical analyses of the produced crude oil and scanning electron microscopy images confirmed the precipitation of asphaltene and mineral dissolution that caused permeability reduction. Furthermore, as CO2 concentration in the oil/CO2 mixture increased more asphaltene/resin precipitation was observed. More asphaltene precipitation was observed in higher permeability and more vuggy core samples than in those with intermediate or low permeabilities. This observation can be possibly attributed to relaxation of fluids as they enter the relatively large vugs (with large surface area) from the pore-throats resulting in the flocculation and/or precipitation of asphaltenes. A slight reduction in porosity and pore size was observed in most samples presumably caused by a combination of mineral/asphaltene precipitation and physical compaction.Overall, the results obtained in this study further highlight the complexities associated with the application of CO2-EOR in underground oil reservoirs where both the crude oil and the rock formation may be expected to interact with the injected fluids. Further research into the underling mechanisms is required.

An experimental investigation of polyacrylamide and sulfonated polyacrylamides based gels crosslinked with cr(III)-acetate for water shutoff in fractured oil reservoirs

Water injection as one of the most efficient and worldwide extensively employed approach in homogenous oil reservoirs suffers from early water breakthrough time as well as low oil sweep efficiency values in fractured oil reservoirs. This study investigates the potential application of Cr(III)-acetate based gel polymer system in a typical water injection process using one fractured micromodel. For this purpose, three sulfonated polyacrylamides, different in solfunation degree, and one hydrolyzed polyacrylamide were studied regarding gelation time, gel strength and stability to find the optimized conditions in terms of polymer type and concentration, and polymer/Cr(III)-acetate ratio, which were subsequently used for one dynamic test. Results illustrated the optimized conditions as AN 105 polymer with concentration of 5000 ppm and polymer/Cr(III) ratio of 5. Moreover, results showed that implementing such gel system yields an increased oil recovery value of 24.46% OOIP at 1.55 PV and delays the breakthrough time from 0.47 PV to 0.51 PV.

Correlation for Predicting Water Breakthrough Time in Thin Oil Rim Reservoirs in the Niger Delta

In the Niger Delta, available correlations to predict water breakthrough time in thin oil rim reservoirs are based on generic reservoir models and/or experimental design approach. This approach had not considered the heterogeneity of the reservoir. Thus, the prediction of these available correlations for thin oil rim reservoirs in the Niger Delta is in doubt, considering the sensitive nature of developing thin oil rim reservoirs. Then, a correlation for water breakthrough time (tbt) was developed based on integrated reservoir model of thin oil rim reservoir in the Niger Delta. The obtained result indicated that the developed correlation predicted 1652.72 days compared to the actual Oilfield breakthrough time of 1653 days (about 4.53 years). Also, sensitivity study showed that the developed correlation and the integrated reservoir model predictions of oil production rate (qo), fractional well penetration (hp/h) and height above perforation-oil column (hap/h) on the water breakthrough time (tbt) were close and resulted in coefficient of determination (R2) of 0.9697, 0.8597 and 0.9553, respectively. Furthermore, the results depicted that water coning breakthrough time (tbt) depends directly on oil production rate (q) and well completion parameters: fractional well penetration (hp/h) and height above perforation (hap). Hence, to delay early water breakthrough in thin oil rim reservoirs, these completion parameters are consideration in vertical wells to achieve optimum oil recovery. Also, the developed correlation can be used as a quick and robust tool to predict water breakthrough time of thin oil rim reservoirs in the Niger Delta.

A new hybrid production optimization algorithm for the combined CO2-cyclic solvent injection (CO2-CSI) and water/gas flooding in the post-CHOPS reservoirs

In this paper, a new hybrid production optimization algorithm, namely, the steepest ascent‒particle swarm optimization (SA‒PSO), is developed to optimize the combined CO2-cyclic solvent injection (CO2-CSI) and waterflooding (WF) or gasflooding (GF) in the post cold heavy oil production with sand (CHOPS) reservoirs. The field-scale CO2-CSI, CO2-CSI + WF, and CO2-CSI + GF performances are predicted by upscaling the laboratory tests and using the numerical simulations with the considerations of the wormholes propagation and foamy-oil flow. The net present value (NPV) is chosen as an objective function and maximized by adjusting the well controls, such as the bottom-hole pressure (BHP) and water/gas injection rate. The efficacies of the following three optimization methods are evaluated and compared: the steepest ascent (SA) method, particle swarm optimization (PSO), and SA–PSO. It is found that the SA‒PSO gives a higher global optimum NPV than the SA algorithm and requires fewer numerical simulation runs than the PSO. It combines the fast convergence of the SA algorithm and the global search of the PSO. It is also found that the CO2-CSI + GF has the highest NPV in the post-CHOPS reservoir among the three enhanced oil recovery (EOR) processes. For the CO2-CSI + GF, the gas injector should inject CO2 at the highest injection rate during the early cycles to displace the foamy oil but should be shut in during the late cycles to control the gas channeling. The optimum NPVs of the CO2-CSI, CO2-CSI + WF, and CO2-CSI + GF are achieved when the BHPs of the producers are maintained at the lowest pressure. It is uneconomical to apply the WF immediately after the CO2-CSI due to the early water breakthrough.

Micro-particle gel transport performance through unconsolidated sandstone and its blocking to water flow during conformance control treatments

High-permeability streaks, fractures, conduits, and fracture-like features can expedite an undesirable water channeling and early water breakthrough during water flooding. Micro-preformed particle gel (PPG) is one of the commercial gels invented exclusively to plug such features to reduce excess water production and increase oil production. This paper reports the results of laboratory experiments that studied the PPG’s injection and placement mechanism through unconsolidated sandstone cores. Extensive experiments were conducted to examine the effect of the sand permeability, PPG size, concentration, and water salinity on the PPG injection process, passing criteria, and plugging efficiency to water flow. A two foot sand pack model with four pressure taps was designed to monitor PPG transport and plugging performance. The results showed that the PPG propagated deep into the unconsolidated sandstone. Fully swollen gel particles had better injectivity than partially swollen particles with a larger diameter size; particle strength was more dominant in influencing particle movement than was particle size. The injection pressure increased as the PPG concentration, water salinity, and gel particle size increased. High gel particle injection pressure was measured in the front part of the unconsolidated sandstone as a result of gel particle retention. The retention was controllable by selecting proper gel particle strength, concentration, and size. PPG transport through unconsolidated sand exhibited four patterns of injection processes: low gel particle retention and pass; high gel particle retention and pass; high gel particle retention, breaking, and pass; and gel particle accumulation and plug. The micro-gel particle’s blocking efficiency to water flow increased as the PPG strength, size, and concentration increased. The PPG placement mechanism, such as washout, was also found to considerably affect the water injection flow processes. The results of this laboratory experiment will aid in the selection of future conformance control candidates and also optimize the particle gel treatment design for large-scale field projects.

Fracture characterization in sigmoidal folds: Insights from the Siah Kuh anticline, Zagros, Iran

Fieldwork and remote-sensing data from the Siah Kuh anticline, simply folded belt, Zagros, Iran indicate that specific structures and fracture systems formed during the development of its sigmoidal shape, and that conceptual fracture models developed for cylindrical folds are inadequate for the correct evaluation and development of hydrocarbon accumulations in this type of anticline. The sigmoidal shape of the Siah Kuh anticline was achieved in the Pliocene due to vertical axis rotations of an already existing anticline. These rotations promoted the development of (1) two systems of normal faults in the outer arcs of the sigmoidal shape, (2) a low-angle thrust, and (3) the north–south Danan anticline in the inner arc of its easternmost bend. The passive margin to syn-folding structures, typically observed in nearby cylindrical and periclinal anticlines, predated the development of the sigmoidal shape and were passively rotated into the segments of the anticline. The sigmoid-related structures are spatially, geometrically, and kinematically related to the bends of the anticline trend, hence they can be predicted and modeled in the subsurface. The sigmoid-related normal faults have a great potential to preserve porosity and promote localized high flow rates or early water breakthrough. However, if they cut through thin reservoir and seal units, sigmoid-related thrusts and normal faults might compromise lateral reservoir continuity and seal integrity. The results of this study can help in reducing risks and uncertainty in the evaluation and development of business opportunities in secondary sigmoidal anticlines within the Zagros or any other fold-thrust belt.

The history of hydrocarbon exploration and development in North Yorkshire

Abstract Hydrocarbon exploration in North Yorkshire began in 1937, targeting Triassic and Permian reservoirs below the surface expression of the Cleveland Anticline. D’Arcy drilled the successful well Eskdale-2, marking the first gas discovery in the Zechstein carbonates in the UK. Since then approximately 100 wells have been drilled in the basin with exploration success relatively high. Out of the 25 pure exploration wells in the region, 13 have found hydrocarbon accumulations (flowed gas) and eight of the discoveries have been developed to date. The primary reservoir is the Permian-aged Zechstein carbonate sequence and, more specifically, the Z2, Kirkham Abbey Formation (KAF), which is a tight carbonate reservoir overprinted by a high permeability fracture system. Despite considerable investment and effort over the years, the historical development story of these fields has been very much one of repeated technical and investment failure, with approximately 39 Bcf (billion cubic feet) of the mapped gas initial in-place (GIIP) of c . 326 Bcf produced to date, an estimated recovery factor of 12%. Historical production data show that all the Zechstein reservoirs have experienced early water breakthrough, leading to impaired gas rates and low recoveries. The water influx is due to a highly mobile, but finite aquifer, which under field production conditions preferentially flows through the high permeability fracture system, bypassing the gas stored in the tighter matrix. Third Energy is aiming to resolve the issue of water influx by using artificial lift to encourage the gas to flow. A trial is currently being undertaken at the Pickering gas field and, if this programme is successful, this will provide sufficient confidence for a phased redevelopment programme of surrounding fields. Whilst North Yorkshire has experienced only limited exploration and production (E&P) activity in the last decade, solving the issue of premature water influx in the KAF fields, combined with the search for unconventional resources in the Bowland section of the Mid and Lower Carboniferous strata will herald a new and exciting phase of E&P activities for this province.

An Analysis Model for Water Cone Subsidence in Bottom Water Drive Reservoirs

Water coning in bottom water drive reservoirs, which will result in earlier water breakthrough, rapid increase in water cut and low recovery level, has drawn tremendous attention in petroleum engineering field. As one simple and effective method to inhibit bottom water coning, shut-in coning control is usually preferred in oilfield to control the water cone and furthermore to enhance economic performance. However, most of the water coning researchers just have been done on investigation of the coning behavior as it grows up, the reported studies for water cone subsidence are very scarce.The goal of this work is to present an analytical model for water cone subsidence to analyze the subsidence of water cone when the well shut in. Based on Dupuit critical oil production rate formula, an analytical model is developed to estimate the initial water cone shape at the point of critical drawdown. Then, with the initial water cone shape equation, we propose an analysis model for water cone subsidence in bottom water reservoir reservoirs. Model analysis and several sensitivity studies are conducted.This work presents accurate and fast analytical model to perform the water cone subsidence in bottom water drive reservoirs. To consider the recent interests in development of bottom drive reservoirs, our approach provides a promising technique for better understanding the subsidence of water cone.

O-231 中東の油田での炭酸塩岩油層における早期水付き現象とその地質学的要因

O-231 中東の油田での炭酸塩岩油層における早期水付き現象とその地質学的要因

4D seismic close-the-loop impacts business decisions at the Okume Complex, Equatorial Guinea

Time-lapse seismic “4D” close-the-loop (CtL) technology can play a significant role in creating robust static and dynamic models for deepwater reservoirs, as demonstrated by a case study in Equatorial Guinea, West Africa. Initial static and dynamic models for the field were built using well data and seismic attribute volumes, from prestack 3D and 4D simultaneous angle versus offset (AVO) inversions, in conjunction with rock-physics analysis. We then used seismic inversion technology to estimate static and dynamic reservoir properties over the field's life, including porosity, net-to-gross (NTG), and changes in both fluid saturations and pressures. To model changes, we used a baseline and two high-repeat 4D seismic surveys as input to the inversion work. The study shows how the many competing production effects and their combined nonunique 4D signatures posed a serious challenge to achieving history-matched dynamic models consistent with 4D seismic data. However, 4D CtL technology served as a guide for reservoir engineers updating the dynamic model simulations by providing direction and constraints for matching pressures, waterfronts, and gas breakout areas. Moreover, 4D CtL helped refine existing mental sweep models based on historic field performance and available tracer data. Previous models largely matched this data but used some undesirable manual edits in the simulation model. This has allowed for more geologically sound model adjustments, especially to the water-injection strategy, which obtained promising results. A number of targets were dropped based on 4D matched simulation models that showed elevated water saturations with a high chance for early water breakthrough and reduced well recovery. On the other hand, new targets similar to the one in this case study were identified and/or derisked. This successful case study demonstrates the potential of rock physics, especially when integrated with prestack AVO inversion techniques, to produce a set of attributes that accurately explain the time-lapse production effects observed on seismic.

Faults as barriers or channels to production-related flow: insights from case studies

This paper presents case studies of producing fields where faults heavily influence fluid-flow behaviour. In a first case, faults show no evidence of barrier behaviour prior to production but, nevertheless, demonstrate strongly compartmentalized field behaviour once production starts. Analytical modelling suggests that short-term pressure differences between faulted panels can be predictable owing to the permeability contrast between fault zone and reservoir: fault permeability, however, is not low enough to prevent dissipation on the geological timescale. Faults in a second case acted as baffles during production, supporting significant pressure differences, with salinity data suggesting that, as a network, they channelled sweep through relays and around fault tips. The third case examines a fault acting as a vertical drain, causing early water breakthrough through proven intermediate seals and depleting non-produced aquifers above. The fault permeability required to explain these depletion rates is estimated from an analytical model. Estimates of 0.02 – 0.2 mD compare well with predictions from a new algorithm calibrated using measurements on natural fault rocks from seismic-scale faults. Experience from case studies such as these can improve the way in which we use limited data from exploration wells when considering fault behaviour in development scenarios and in conditioning reservoir models for production forecasting.

A Full-Field Interwell Tracer Program on a Giant Carbonate Oil Field

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 177527, “The Design and Implementation of a Full-Field Interwell Tracer Program on a Giant UAE Carbonate Oil Field,” by D. Wang, A.B. Al-Katheeri, S.M. Al-Nuimi, and A. Dey, Abu Dhabi Company for Onshore Petroleum Operations, prepared for the 2015 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 9–12 November. The paper has not been peer reviewed. This paper reviews the design and implementation of a full-field interwell tracer program for a giant onshore oil field in Abu Dhabi. The field is under peripheral waterflooding in order to maintain reservoir pressure and provide a mechanism to sweep the oil. However, the existence of strikeslip fault planes juxtaposed across the reservoirs added a variable to the complexity of waterflood management. To improve the understanding of reservoir heterogeneity and reduce the uncertainties associated with major faults, a full-field water-tracer program has been designed. Introduction On the basis of the streamline model, unique chemical tracers have been injected in 21 water injectors covering all the peripheral areas; dozens of associated offset producers across the field were selected to monitor the tracer movement. The design of the program is explained in the complete paper in terms of tracer selection and capability tests, chemical-volume calculation, injection-well and monitoring-well selection (made on the basis of the streamline model), and design of the comprehensive monitoring plan. Ultimately, the results of this tracer program will be used in combination with other reservoir-surveillance tools to facilitate better management of the reservoir. Background The subject field is located approximately 110 km to the southeast of Abu Dhabi Island. The field was discovered in 1965, with first production in 1973 and first water injection in 1976. The main oil-bearing zones are X, Y, and Z. These zones are in communication through faults. Each zone is bounded at the top and base by a dense argillaceous limestone and further subdivided by the occurrence of stylolite-bearing dense intervals. Of these, Zone Y, the subject of this study, contains more than two-thirds of the field’s original oil in place. Zone Y is an undersaturated, heterogeneous, and highly stratified reservoir with an average porosity of 30%. It is divided into five subzones. The Upper Y contains the higher-permeability zones in excess of 700 md, while the Lower Y has a lower permeability of approximately 10 md. The current development scheme, with selective injection and production under peripheral water injection, was implemented in 1982. The existence of major faults in Zone Y resulted in splitting the reservoirs into 12 main sectors. Among the major monitoring tools and techniques, tracer injection is one of the most important for monitoring the effectiveness of a waterflood project because of the lack of direct information on flow from individual injection wells. Tracer injection can be used to determine early water breakthrough in different areas, crossflow between zones, and the degree of water slumping caused by reverse coning.