Browsing by Subject "Reservoir"

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Analysis of the factors influencing the performance of segregation drive reservoirs
(1962) Abib, Osmar, 1933-; Pirson, Sylvain J. (Sylvain Joseph), 1905-1983
The performance of a large number of hypothetical segregation drive reservoirs has been computed and analyzed. Valuable results were obtained and useful conclusions have been drawn. Several factors were found to be extremely important in the prediction of the performance of segregation drive reservoirs. Some of them can be controlled; others cannot. Thus, the rate factor and the well distribution relative to the reservoir structure, were found to bear considerable influence on the final recovery to be expected from the reservoir. It is therefore apparent that a judicious operation program can be formulated to take advantage of these factors. There is, however, a large number of variables which, although important, cannot be regulated, as for example, the irreducible oil saturation, the irreducible water saturation, the gas cap size, and the properties of the reservoir fluids. On the other hand, some factors were found not to bear any important influence on the performance of segregation drive reservoirs, as for example, the equilibrium gas saturation, the counterflow of fluids (except for reservoirs having a very small initial gas cap), the reservoir geometry, and gas reinjection. It is finally concluded that further studies are still needed before a better understanding of the mechanism of production of segregation drive reservoirs be acquired. Such studies would include the analysis of the influence of factors such as reservoir stratification, crossflow, and gas coning
Application of dynamic optimization methods for foam floods in stratified reservoirs
(2018-08-17) Tang, Brandon Chok-Yie; Nguyen, Quoc P.
Efficient recovery of oil from heavily stratified carbonate reservoirs can be very technically challenging, even when applying waterflood, gasflood, or WAG (water-alternating gas) processes. To date, relatively few field or pilot applications of foam flooding have been conducted due to an incomplete understanding of how foam will behave in the field. The reservoir of interest studied in this work is oil-wet and consists of a stratified upper high-permeability zone overlaying a lower low-permeability zone. This study seeks to assess the performance of the foam flooding process in oil recovery and develop an optimum field injection strategy based upon various objective functions. In the process, the impact of initial waterflooding and varying foam strength on the optimum project termination time, as well as the sensitivity of foam parameters on the optimum field injection strategy is investigated. Two main optimization techniques are tested: static optimization, where the injection parameters are set once at the beginning of the simulation, and dynamic optimization, where injection parameters are optimized in five-year intervals over the life of the well. The dynamic optimization was performed in two ways: a local dynamic optimization and an early-time weighted optimization. In general, the dynamic optimization outperformed the static optimization with respect to all objective functions. Over the course of the study, a variety of objective functions were utilized. The objective functions began with maximizing cumulative oil recovery and evolved to maximizing oil recovery while minimizing gas utilization ratio, and finally maximizing net present value (NPV). From the results, it was ultimately shown that the global dynamic optimization of NPV was the most useful way of obtaining a field injection strategy. The optimal process design parameters indicated that high volumes of surfactant as well as gas in the lower zone needed to be injected early in the life of the project to best maximize NPV. From the optimal termination time study, it was found that the optimal termination time for the project was around ten years. Varying extents of initial waterflooding and alteration of foam strength did not have an impact on the suggested termination time. From the foam strength sensitivity, it was found that among the factors (water saturation, oil saturation, surfactant concentration) considered, the maximum dry-out water saturation had the most profound impact on the NPV. Ultimately, this work develops the framework necessary to create a field injection strategy for foam flooding in the stratified oil-wet reservoir used in this study, but can be extended to other types of reservoirs.
Comparison of models for numerical simulation of low salinity waterflood
(2021-08-12) Santra, Ritabrata; Sepehrnoori, Kamy, 1951-; Delshad, Mojdeh
Accurately modeling Low Salinity Water Injection (LSWI) is essential for reliable predictions of oil recovery which affects exploration project planning and investment decisions. During LSWI, we modify the ions present in water before injection into an oil reservoir which helps maintain reservoir pressure and recover more oil from the reservoir, as compared to untreated regular water injection. Thus, understanding the primary mechanism and their effect of improved oil recovery due to wettability alteration during LSWI, and accurately modeling it, is essential to reliably predict and maximize oil recovery. However, there are several proposed models for numerical simulation of this novel method of LSWI and there exists no comparison for choosing the best model for an accurate simulation study. This study uses two simulators: (1) coupled reservoir simulator with geochemistry capabilities, UTCOMP-IPhreeqc and (2) commercial simulator, CMG’s GEM. We compare three models for numerical simulation of LSWI: (1) calcite dissolution, (2) total ionic strength, and (3) Extended Derjaguin, Landau, Verwey, and Overbeek (EDLVO). Most importantly, we also perform comparisons at both field and core scale. We describe the modeling capabilities of the two simulators and perform literature review to summarize the proposed mechanisms and the theory behind existing models. Finally, we simulate on (1) a synthetic carbonate field case, (2) a sandstone coreflood from a published literature, and (3) another sandstone coreflood, each with distinct mineralogy and petrophysical properties, to compare the three models. Results show that only the EDLVO model implemented in UTCOMP-Iphreeqc was able to accurately model the wettability alteration by estimating the change in contact angle during LSWI for all cases. While predicted recoveries from some of the models were similar, further investigation into the results uncovered the shortcomings of the other two models which resulted in incorrect calculation of the interpolating parameter. We concluded that the EDLVO model in UTCOMP-IPhreeqc works for all minerology while the other two models are scale, mineralogy, and case dependent. In future, we aim to develop a screening guide to choose model depending on the case, for simulating LSWI in commercial simulators which lack some of the mechanistic modeling capabilities of UTCOMP-IPhreeqc.
Creating a Quick Screening Model for CO2 Flooding and Storage in Gulf Coast Reservoirs Using Dimensionless Groups
(2006-08) Wood, Derek James; Lake, Larry W.; Johns, Russell T.
Concerns over global warming have led to interest in removing C02, from the atmosphere. Sequestration of C02 in oil reservoirs as part of enhanced oil recovery (EOR) projects is one method being considered; therefore, it is necessary to identify the most attractive candidate reservoirs for C02 oil recovery and storage. Models from the literature proved inadequate for the purposes of screening reservoirs for C02 flooding; therefore, it was necessary to create a new model. The first step in creating the model was the scaling of continuous C02 flooding. The five dimensionless groups derived for an immiscible waterflood served as the basis for the scaling. When these proved insufficient, the groups were modified and five new groups, including two pressure groups and three saturation groups, were added to the scaling. These 10 groups - the effective aspect ratio, the dip angle group, the water-oil mobility ratio, the C02-oil mobility ratio, the buoyancy number, the injection pressure group, the producing pressure group, the initial oil saturation, the residual oil saturation to water, and the residual oil saturation to gas - were validated and proved to be the necessary groups to completely scale continuous C02 flooding. Using a combination of Box-Behnken and factorial experimental designs, a total of 322 simulations were run with different values of these groups. The results were used to generate response surface fits for the five output model parameters (four for oil recovery and one for C02 storage). The group values were normalized to assist in reducing the number of coefficients in each fit. The final versions of the screening model equations have only 6-8 coefficients, which indicate the groups that are most important in the response surfaces, but still have an acceptable level of accuracy. Only seven of the ten dimensionless groups proved to be important for screening for C02 flooding. These equations can be used by operators to quickly estimate the oil recovery and C02 storage potential for any given reservoir and are ideal for screening large databases of reservoirs to identify the most attractive C02 flooding candidates.
Design of a Single-Well Wettability Tracer Test in the Sulimar Queen Reservoir
(1996-12) Sverrisson, Hannes; Pope, Gary A.
A single-well wettability tracer test (SWWTT) was designed with The University of Texas at Austin Chemical Flooding Simulator (UTCHEM) and an in-situ test based on this design was performed in the Sulimar Queen Reservoir. Wettability controls distribution and characteristics of the flow of fluids through a reservoir rock. A sensitivity study was done on the design that involved different relative permeability models. A SWWTT consists of the injection of either a brine slug followed by a brine buffer, or an oil slug followed by an oil buffer or both depending on what is needed to cause two phase flow in the reservoir near the injection well. The slugs contain material balance (non-reactive) tracers and reactive tracers. After injection there is a shut-in time to allow the reactive tracers to react with the water and form product tracers. The same well is produced and the tracer concentrations measured along with phase cuts and optionally bottomhole pressure. The sensitivity study showed that both the water slug and buffer could be eliminated because of high initial water saturation in the Sulimar Queen Reservoir. The reactive tracers used were ethyl formate and propyl formate with their product tracers ethanol and n-propanol, respectively. A core flood experiment was done to prepare for the field test. The in-situ test involved injecting 10 STB of oil preflush, then a 40 STB oil slug with reactive tracers, and a 10 STB oil buffer was injected into the formation. Both the reactive and product tracers were then produced back in the same well and analyzed after they had hydrolyzed by half in the formation. The information obtained from the test was used to estimate the in-situ relative permeabilities of the formation by history matching with UTCHEM. The results of the history match indicated that the reservoir was mixed-wet.
Detection of production-induced time-lapse signatures by geophysical (seismic and CSEM) measurements
(2011-05) Shahin, Alireza; Tatham, R. H. (Robert H.), 1943-; Stoffa, Paul L., 1948-; Sen, Mrinal; Goff, John; Smith, Brackin
While geophysical reservoir characterization has been an area of research for the last three decades, geophysical reservoir monitoring, time-lapse studies, have recently become an important geophysical application. Generally speaking, the main target is to detect, estimate, and discriminate the changes in subsurface rock properties due to production. This research develops various sensitivity and feasibility analyses to investigate the effects of production-induced time-lapse changes on geophysical measurements including seismic and controlled-source electromagnetic (CSEM) data. For doing so, a realistic reservoir model is numerically simulated based on a prograding near-shore sandstone reservoir. To account for the spatial distribution of petrophysical properties, an effective porosity model is first simulated by Gaussian geostatistics. Dispersed clay and dual water models are then efficiently combined with other well-known theoretical and experimental petrophysical correlations to consistently simulate reservoir model parameters. Next, the constructed reservoir model is subjected to numerical simulation of multi-phase fluid flow to replicate a waterflooding scenario of a black oil reservoir and to predict the spatial distributions of fluid pressure and saturation. A modified Archie’s equation for shaly sandstones is utilized to simulate rock resistivity. Finally, a geologically consistent stress-sensitive rock physics model, combined with the modified Gassmann theory for shaly sandstones, is utilized to simulate seismic elastic parameters. As a result, the comprehensive petro-electro-elastic model developed in this dissertation can be efficiently utilized in sensitivity and feasibility analyses of seismic/CSEM data with respect to petrophysical properties and, ultimately, applied to reservoir characterization and monitoring research. Using the resistivity models, a base and two monitor time-lapse CSEM surveys are simulated via accurate numerical algorithms. 2.5D CSEM modeling demonstrates that a detectable time-lapse signal after 5 years and a strong time-lapse signal after 10 years of waterflooding are attainable with the careful application of currently available CSEM technology. To simulate seismic waves, I employ different seismic modeling algorithms, one-dimensional (1D) acoustic and elastic ray tracing, 1D full elastic reflectivity, 2D split-step Fourier plane-wave (SFPW), and 2D stagger grid explicit finite difference (FD). My analyses demonstrate that acoustic modeling of an elastic medium is a good approximation up to ray parameter (p) equal to 0.2 sec/km. However, at p=0.3 sec/km, differences between elastic and acoustic wave propagation is the more dominant effect compared to internal multiples. Here, converted waves are also generated with significant amplitudes compared to primaries and internal multiples. I also show that time-lapse modeling of the reservoir using SFPW approach is very fast compared to FD, 100 times faster for my case here. It is capable of handling higher frequencies than FD. It provides an accurate image of the waterflooding process comparable to FD. Consequently, it is a powerful alternative for time-lapse seismic modeling. I conclude that both seismic and CSEM data have adequate but different sensitivities to changes in reservoir properties and therefore have the potential to quantitatively map production-induced time-lapse changes.
An experimental and simulation study of the effect of geochemical reactions on chemical flooding
(2010-12) Chandrasekar, Vikram, 1984-; Delshad, Mojdeh; Pope, Gary A.
The overall objective of this research was to gain an insight into the challenges encountered during chemical flooding under high hardness conditions. Different aspects of this problem were studied using a combination of laboratory experiments and simulation studies. Chemical Flooding is an important Enhanced Oil Recovery process. One of the major components of the operational expenses of any chemical flooding project, especially Alkali Surfactant Polymer (ASP) flooding is the cost of softening the injection brine to prevent the precipitation of the carbonates of the calcium and magnesium ions which are invariably present in the formation brine. Novel hardness tolerant alkalis like sodium metaborate have been shown to perform well with brines of high salinity and hardness, thereby eliminating the need to soften the injection brine. The first part of this research was aimed at designing an optimal chemical flooding formulation for a reservoir having hard formation brine. Sodium metaborate was used as the alkali in the formulation with the hard brine. Under the experimental conditions, sodium metaborate was found to be inadequate in preventing precipitation in the ASP slug. Factors affecting the ability of sodium metaborate to sequester divalent ions, including its potential limitations under the experimental conditions were studied. The second part of this research studied the factors affecting the ability of novel alkali and chelating agents like sodium metaborate and tetrasodium EDTA to sequester divalent ions. Recent studies have shown that both these chemicals showed good performance in sequestering divalent ions under high hardness conditions. A study of the geochemical species in solution under different conditions was done using the computer program PHREEQC. Sensitivity studies about the effect of the presence of different solution species on the performance of these alkalis were done. The third part of this research focused on field scale mechanistic simulation studies of geochemical scaling during ASP flooding. This is one of the major challenges faced by the oil and gas industry and has been found to occur when sodium carbonate is used as the alkali and the formation brine present in situ has a sufficiently high hardness content. The multicomponent and multiphase compositional chemical flooding simulator, UTCHEM was used to determine the quantity and composition of the scales formed in the reservoir as well as the injection and production wells. Reactions occurring between the injected fluids, in situ fluids and the reservoir rocks were taken into consideration for this study. Sensitivity studies of the effect of key reservoir and process parameters like the physical dispersion and the alkali concentration on the extent of scaling were also done as a part of this study.
From outcrop to functional reservoir model : using outcrop data to model the tidally dominated esdolomada sandstone, NE Spain
(2012-05) Pinkston, Daniel Patrick; Steel, R. J.; Wood, Lesli J.; Olariu, Cornel
The Esdolomada Sandstone member 2 crops out in the Tremp-Graus Basin of north-central Spain and forms the uppermost part of the Eocene Roda Formation. The second Sandstone unit within the Esdolomada member (ESD2) consists of bioturbated and shell-rich, very-fine sandstones as well as stacked sets of fine- to coarse-grained cross-stratified sandstones. The overall upward trend in the member is commonly upward thickening and coarsening of beds into and through the cross-stratified interval, though at some few locations there is no obvious trend or even upward thinning of beds. The internal architecture of the member is one in which groups of beds lie between master surfaces that dip highly obliquely to the migration direction of the individual cross strata. The ESD2 is interpreted to be a shelf tidal sand bar within the overall transgressive Esdolomada Sandstone member. It is likely that these bars migrated in a coast parallel fashion, as suggested by the cross-bed orientations, but also accreted laterally away from the coast along the seaward-dipping master surfaces. LIDAR (light detection and ranging) data collection for the Esdolomada member was attempted along the Isábena River near the village of Roda de Isábena, with a total lateral coverage of approximately 3 kilometers. Detailed outcrop measurements were made in accessible areas along the same transect. Outcrop analogs are the best source of data to understand reservoir heterogeneities and to build reservoir analogs for fluid flow simulations. Sand-rich, offshore tidal sandbodies are usually surrounded by marine mudstones, and are recognized from their very orderly stacking of cross-stratified sets (more orderly than in fluvial settings) , their complex internal architecture of master surfaces dipping obliquely to the direction of migration of the contained cross strata and their significant sandstone/mudstone heterogeneities. Tidal bar systems such as the ESD2 are appealing hydrocarbon prospects for several reasons. Primarily, they are relatively coarse grained, have a high degree of lateral continuity, and are relatively clean sands. In places where sand beds are stacked, they create enough thickness to offer good vertical permeability; however, mud-draped cross-beds can create heterogeneities in this type of system that buffer fluid flow. Due to a fairly unsuccessful attempt to obtain LIDAR coverage of the ESD2, in order to build an analog reservoir model, surfaces were instead based on measured sections and outcrop photomosaics. Using Schlumberger’s Petrel software, facies logs were created from measured section data, and then interpolated to make a facies and porosity model.
History Matching Using Probabilistic Approach in a Distributed Computing Environment
(2005-12) Yadav, Sharad; Bryant, Steven L
A novel methodology for delineating multiple reservoir domains for the purpose of history matching in a distributed computing environment has been proposed. A fully probabilistic approach to perturb permeability within the delineated zones is implemented. The combination of robust schemes for identifying reservoir zones and distributed computing significantly increases the accuracy and efficiency of the probabilistic approach. The information pertaining to the permeability variations in the reservoir that is contained in dynamic data is calibrated in terms of a deformation parameter rv. This information is merged with the prior geologic information in order to generate permeability models consistent with the observed dynamic data as well as the prior geology. The relationship between dynamic response data and reservoir attributes may vary in different regions of the reservoir due to spatial variations in reservoir attributes, well configuration, flow constraints etc. The probabilistic approach then has to account for multiple rv values in different regions of the reservoir. In order to delineate reservoir domains that can be characterized with different rn parameters, principal component analysis (PCA) of the Hessian matrix has been done. The Hessian matrix summarizes the sensitivity of the objective function at a given step of the history matching to model parameters. It also measures the interaction between the parameters affecting the objective function. The basic premise of PCA is to isolate the most sensitive and least correlated regions. The eigenvectors obtained during the PCA are suitably scaled and appropriate grid block volume cut-offs are defined such that the resultant domains are neither too large (which increases interactions between domains) nor too small (implying ineffective history matching). The delineation of domains requires calculation of the Hessian, which could be computationally costly and also restricts the current approach to some specific simulators. Therefore a robust technique to evaluate a covariance matrix, which is analogous to the 'Hessian matrix', from a set of equi-probable realizations has also been developed. This technique is easy to implement. It yields the domains, which could be intuitively justified. Since the domain delineation process yields zones that are least correlated with each other, each rn parameter can be optimized independently and simultaneously using individual nodes of a cluster of computers. Further, the least correlation criterion helps in retaining the simplicity of 1-D optimization during the history matching. Upon convergence, the perturbed regions are put together and the history match is verified. The proposed approach results in a set of independent tasks of equal magnitude and thus is particularly suited for distributed computing. The methodology has been successfully tested on various synthetic cases.
Integrated stratigraphic and petrophysical analysis of the Wolfcamp at Delaware Basin, West Texas, USA
(2022-04-12) Ramiro-Ramirez, Sebastian; Flemings, Peter Barry, 1960-; Bhandari, Athma R; Daigle, Hugh C; Kerans, Charles; Tisato, Nicola
Hydrocarbons stored in low-permeability reservoirs, also known as ‘unconventional reservoirs’, represent important energy resources worldwide. Although current technology allows their production at economic rates, there still are numerous production challenges and unknowns regarding their flow behavior. A better understanding on how fluids stored in these reservoirs are drained by the hydraulic fractures after stimulation may help to optimize completion designs and field development plans. This research is an attempt to describe such drainage behavior in the largest oil producing unconventional formation in the World. I investigated the drainage behavior in Wolfcamp reservoirs at the completion scale by integrating stratigraphic and petrophysical analyses with flow modeling. I interpreted the depositional and diagenetic processes that generated three Wolfcamp cores recovered in the central-eastern Delaware Basin, measured the porosity and permeability of distinct lithofacies, and developed simple models to describe flow in these strata. I found that most fluids (~95% of the pore volume) are stored in low-permeability (e.g., < 60 nD) mudstones that I interpreted as hemipelagics and siliciclastics turbidites. Interbedded with these deposits are the low-porosity (~5% of the pore volume) and low-permeability (e.g., < 50 nD) carbonate lithofacies that I interpreted as gravity flow deposits and diagenetic dolomudstones. The carbonate gravity flow deposits, when dolomitized, are up to 2000 times more permeable than the other deposits and represent preferential flow pathways that drain fluids from the low-permeability strata during production. This drainage behavior increases the reservoir upscaled permeability, and therefore production rates, multiple times higher compared to a reservoir consisting of only low-permeability strata. Hence, the presence of these permeable, dolomitized, gravity flow deposits plays a critical role when producing from Wolfcamp reservoirs as they accelerate drainage. These findings are also applicable to other low-permeability formations exhibiting significant permeability heterogeneity
A life cycle optimization approach to hydrocarbon recovery
(2010-12) Parra Sanchez, Cristina, 1977-; Lake, Larry W.; Bickel, James E.
The objective of reservoir management is to maximize a key performance indicator (net present value in this study) at a minimum cost. A typical approach includes engineering analysis, followed by the economic value of the technical study. In general, operators are inclined to spend more effort on the engineering side to the detriment of the economic area, leading to unbalanced and occasionally suboptimal results. Moreover, most of the optimization methods used for production scheduling focus on a given recovery phase, or medium-term strategy, as opposed to an integrated solution that allocates resources from discovery to field abandonment. This thesis addresses the optimization of a reservoir under both technical and economic constraints. In particular, the method presented introduces a life cycle maximization approach to establish the best exploitation strategy throughout the life of the project. Deterministic studies are combined with stochastic modeling and risk analysis to assess decision making under uncertainty. To demonstrate the validity of the model, this document offers two case studies and the optimal times associated with each recovery phase. In contrast with traditional depletion strategies, where the optimization is done myopically by maximizing the net present value at each recovery phase, our results suggest that time is dramatically reduced when the net present value is optimized globally by maximizing the NPV for the life of the project. Furthermore, the sensitivity analysis proves that the original oil in place and non-engineering parameters such as the price of oil are the most influential variables. The case studies clearly show the greater economic efficiency of this life cycle approach, confirming the potential of this optimization technique for practical reservoir management.
Modeling the architecture and dynamic connectivity of deep-water channel systems using a forward stratigraphic model
(2022-07-01) Morris, Paul David; Covault, Jacob A.; Mohrig, David; Sylvester, Zoltan; Goudge, Timothy; Sech, Richard
Deep-water channels are important conduits of terrigenous material to continental margins, and they act as significant reservoirs of natural resources in the subsurface. This dissertation investigates the evolutionary development of deep-water channel systems and their deposits through use of a simple forward stratigraphic model and a seismic-reflection dataset. We apply our learnings to subsurface modeling to ascertain the impact of these architectures on dynamic connectivity. Firstly, we study a high-resolution 3D seismic-reflection dataset of a 25 km reach of the Joshua deep-water channel system in the eastern Gulf of Mexico. We document features analogous to meandering fluvial systems where an initial relatively straight channel underwent systematic bend expansion and downstream translation that resulted in a cutoff at one bend. Channel sinuosity continually increased throughout channel aggradation and correlates to a decrease in the average channel slope through time. We propose this may have promoted increasingly depositional turbidity currents and been a control on the system's aggradation. We use a forward stratigraphic model where vertical channel movements are linked to a modified stream power law via channel slope and show how this honors trends in sinuosity, slope and aggradation observed in the Joshua. Next, we employ a forward stratigraphic model that honors our observations from the Joshua, comprising a meandering channel that migrates vertically through time (i.e., its trajectory). We find that three types of channel trajectory, when combined with realistic meandering processes, can capture common styles of deep-water stratigraphic architecture observed on the seafloor and subsurface. We document the overarching processes controlling the stratigraphic evolution of our channel-belt models and demonstrate how they provide dynamic, three-dimensional insights that can elude static cross-sectional perspectives, such as those observed in outcropping sedimentary rocks. Finally, we apply our learnings to models of the subsurface. Systematic channel migration and bend architectures are not typically captured in conventional modeling approaches. Using a simple well pair, we show how sweep behavior over production timescales can be controlled by bend-cutoff architectures. An increasing number of bend-cutoff architectures between a well pair typically increases the variability in potential flow path lengths, reflected in an increase in measures of dynamic heterogeneity. Though the models are entirely statically connected, it is the interaction of reservoir architecture and well geometry that controls sweep behavior over typical development timescales
The Future Of Water In San Antonio: An Evaluation Of Ways To Meet Demand By 2070
(2019-05-01) Hudock, Mathias; Lieberknecht, Katherine
As climate change progresses, the city of San Antonio, Texas is likely to face increasing stress on its water supplies. While the city’s water utility, the San Antonio Water System, has planned several projects to bolster the city’s supplies, these are unlikely to be enough in the face of San Antonio’s growing population and the future reduction of the Edwards Aquifer’s recharge. As such, this article evaluates three additional options for meeting San Antonio’s projected 2070 water demand according to their cost-efficiency, additional benefits and drawbacks, and likeliness of gaining public acceptance. Making San Antonio’s drought-period water restrictions permanent would only satisfy a fraction of the future water deficit, while either city-wide rainwater harvesting or a new reservoir project would more than compensate for the deficit. A reservoir project would be a far more cost- efficient option, while city-wide rainwater harvesting would provide flood mitigation, avoid disrupting riparian habitat, and would be more likely to be accepted by the residents of San Antonio, particularly in light of the earlier failed Applewhite Dam and Reservoir Project. As such, city-wide rainwater harvesting was evaluated as the most viable option, with a reservoir still being possible if San Antonio’s leaders could successfully convince the public of its utility.
Three-dimensional geological modelling of the lithofacies of Caddo Limestone in Stephens County, North-Central Texas
(2019-05) Wang, Wentao, M.S. in Geological Sciences; Janson, Xavier; Fu, Qilong
The Pennsylvanian (early Desmoinesian) Caddo Limestone in Stephens County, Texas hosts important reservoirs and hydrocarbon resources. Therefore, constructing a three-dimensional geological model of the Caddo Limestone is of great significance. The Caddo Limestone Formation comprises shelf carbonate build-ups in which the major allochems are phylloid algal and Komia. This study focuses on the uppermost two cycles of the Caddo Limestone. This study integrated geological, geophysical and petrophysical analysis to build a three-dimensional geological model of the Caddo Limestone. The model is based on 18 cores (totalling 700 ft long), wireline logs from 173 wells and 3-dimensional seismic data. A 3D structure model derived from 3D seismic data and 3D geocellular model of lithofacies are the two key products of this study. Five lithofacies have been differentiated: (1) Komia wackestone and mud-dominated packstone, (2) Phylloid-algal wackestone and packstone, (3) Bioclastic wackestone to packstone, (4) Komia grainstone and grain-dominated packstone, and (5) Komia boundstone. An artificial Neutral Network (ANN) algorithm was applied to predict lithofacies in wells without core samples. The lithofacies were extrapolated within the geocellular model using indicator Kriging. This work demonstrated a viable workflow to build 3D reservoir models of Paleozoic carbonate mound reservoirs.
The Use of Multilinear Regression Models in Patterned Waterfloods: Physical Meaning of the Regression Coefficients
(2005-08) Gentil, Pablo Hugo; Lake, Larry W.
One of the reservoirs engineer's mission is to predict the behavior of hydrocarbon producing assets. Once this ability is developed he/she will try to manage tbe ''today" to maximize the future economic return of the asset. However, the techniques to predict future performance vary from an educated guess of an appropriate analogy to very complex numerical approximations. But what they all have in common is that they are analyzing performance in the past to say something about the future. Hence, most models rely on fitting or matching to historic data. Albertoni (2002) proposed yet another approach using well rate fluctuations in waterfloods to predict interwell connectivity. He expressed the total fluid production at a producer as a weighted linear combination of the injection rates at different injectors located in the same reservoir. The relationship between the weights and the formation geological characteristics were not clear. For example, injection wells with no hydraulic connection to a producer may still exhibit a significant or even a negative weight. This work explores the physical meaning of the weights and proposes a new way to interpret them. In addition, the original model has been expanded and is now able to incorporate flowing bottomhole pressure fluctuations. These insights are used to better understand the underlying assumptions of the model used by Albertoni (2002) and to construct a procedure for incorporating production data into geostatistical permeability distribution models. The new interpretation of the weights arises as an analogy between constrained regression and parallel flow from each injector to all the producers. The procedure shows that the weights can be interpreted as the ratio of inverse distance weighted average permeabilities of well pairs associated with each injector (transmissibilities). They can also be interpreted as individual injector-producer water allocation factors that would result if there were no other injectors. This has been confirmed with flow simulation. Finally, a new water allocation model is proposed that, in combination with a water-oil ratio power-law model, has been used to regress oil rates with encouraging results in synthetic and real datasets.
Well Productivity of Gas Condensate Reservoirs
(1998-08) Narayanaswamy, Ganesh; Pope, Gary; Sharma, Mukul Mani
The objective of this work was to provide more accurate models for predicting well and reservoir performance for gas condensate reservoirs by investigating near-wellbore effects and to explore ways of improving well productivity. Specifically, the effects of non-Darcy flow, changes in relative permeability due to interfacial tension, gravity and flow rate (modeled based on capillary number) and heterogeneity on well productivity were investigated. These effects are shown to be important factors affecting the productivity index (PI) of gas condensate wells. Remediation strategies for improving the PI of a well impaired by condensate dropout using injection of dry gas were also investigated. An analytical method for calculating an effective non-Darcy flow coefficient for a heterogeneous formation is presented. The method presented here can be used to calculate an effective non-Darcy flow coefficient for large gridblocks in reservoir simulators. Based on this method, it is shown that the non-Darcy flow coefficient for a heterogeneous formation is larger than the non-Darcy flow coefficient for an equivalent homogeneous formation. This result was confirmed using numerical simulations with fine grids. Sensitivity studies of non-Darcy flow effects on the productivity of a single gas condensate well indicate that when only non-Darcy effects are considered, the condensate bank near the well can cause an order of magnitude reduction in the PI. Hence, immediate remediation steps might be necessary for formations with a high non-Darcy flow coefficient. The reduction in PI with increasing non-Darcy flow coefficient is non-linear. Careful comparisons of relative permeability data at various capillary numbers with a capillary trapping model show that these data can be matched with a simple two-parameter model. A compositional simulation study of a single well with a capillary number included was done. The relative permeability improvement obtained at high capillary numbers counteracts the PI reduction due to non-Darcy flow effects. This effect reduces the drop in PI due to condensate buildup and makes the drop in PI more gradual. Hence, both effects should be considered while studying the production performance of a gas condensate reservoir. The capillary number effect is often found to completely overshadow the two-phase non-Darcy effects. A case study of a lean-gas well similar to those in the Arun field was considered and a history match of the production data was performed. Simulation results are presented which clearly show that accurate prediction of PI based on laboratory measurements is possible using both non-Darcy and capillary number effects. The effect of heterogeneity was demonstrated using simulations of various stochastically generated permeability fields.