This research evaluates and improves capabilities incorporated in the Water Rights Analysis Package (WRAP) modeling system for tracking salt loads, particularly for applications dealing with natural salt pollution problems that are prevalent in several major river basins in Texas and neighboring states. WRAP is the river/reservoir system simulation model incorporated in the Water Availability Modeling (WAM) System applied by agencies and consulting firms in Texas in planning and water right regulatory activities. A salinity simulation component of WRAP called WRAP-SALT was developed recently at Texas A&M University. WRAP-SALT was based on the premise of complete mixing within the monthly computational time step. However, salt concentrations actually have time variation throughout a reservoir. This thesis research investigates more realistic salinity routing methods. Historical gauged data provide a basis for calibration of routing parameters. The timing of the inflow load to determine outflow concentration is calculated by lag parameters with the monthly time steps. Complete mixing occurs during the lag months. Two options are incorporated into WRAP-SALT for setting the lag parameter. With the first option, the model-user sets a constant that is applied during every month of the simulation. This option requires calibration studies to determine the lag. With the alternative option, a variable lag is computed within the model in each month based on the concept of retention time, which is a representation of the time required for a monthly volume of water and its salt load to flow through a reservoir. When the lag is activated, the accuracy between observed and computed mean monthly salinity concentrations through the reservoir is generally improved. The basin-wide simulation was performed for the Brazos River Basin for conditions with and without salt control dams proposed by the Corps of Engineers. The proposed salt control impoundments improve water quality throughout the basin.

This Master Thesis work aims to find a model system combining the positive effects of surfactant and polymer flooding to enhance oil recovery. This report presents the results of 12 core floors performed to enhance recovery of waterflood residual oil. The recovery is enhanced by a visous surfactant flood consistent of one polymer to increase the viscosity, one surfactant for interfacial tension reduction, and one di-alcohol to function as co-surfactant and for salinity control. The chemical treatment that gave the best result, gave an additional oil production normalized on OOIP of 20%, improving the oil recovery from 45 to 66% mostly by the means of mobility control. Pure viscosity floods gave an additional recovery of 12 to 13% of OOIP. Novel technology is used to investigate environmental friendly enhanced oil recovery. A biopolymer made out of microfibrils from wooden material was for the first time ever to my knowledge, attempted used in a core flood to enhance oil recovery. A viscous surfactant tertiary recovery process may help improve oil recoveries from many marginal oil fields or those that face shut-down due to uneconomic operating costs, but still contain significant amounts of oil.

Monahans Field of the Permian Basin in West Texas is a complex carbonate reservoir due to the lateral heterogeneity caused by facies changes throughout the Lower Guadalupian Glorieta Formation and the Upper Leonardian Upper Clearfork Formation. A facies model, porosity model, and a siltstone model were generated in Petrel to better characterize the Monahans Field reservoir. Interbedded impermeable siltstone beds in Monahans Field partition the reservoir making oil production and water injection difficult. The facies model indicates that during deposition, a tectonically uplifted area (island) influenced sedimentation and also shows that the Upper Clearfork Formation is mainly subtidal facies and the Glorieta Formation consists mainly of tidal flat facies. The porosity model shows the greatest porosity to be in the diagenetically altered supratidal deposits. The siltstone model identified siltstone barriers that prograded across the platform when sea level was low. 4th-order sequences occur within the larger 3rd-order sequence. The models identified multiple flow units in Monahans Field. Preferential injection of water within the reservoir compartments, horizontal drilling, and hydraulic fracture stimulation may all provide mechanisms to more efficiently sweep the remaining reserves from the reservoir.

An integrated full-field study was conducted on the Monument Northwest field located in Kansas. The purpose of this study was to determine the feasibility and profitability of a waterflood using numerical simulation. Outlined in this thesis is a methodology for a deterministic approach. The data history of the wells in the field beginning from spud date were gathered and analyzed into information necessary for building an upscaled reservoir model of the field. Means of increasing production and recovery from the field via a waterflood was implemented. Usually, at the time of such a redevelopment plan or scheme to improve field performance, a tangible amount of information about the reservoir is already known. Therefore it is very useful incorporating knowledge about the field in predicting future behavior of the field under certain conditions. The need for an integrated reservoir study cannot be over-emphasized. Information known about the reservoir from different segments of the field exploration and production are coupled and harnessed into developing a representative 3D reservoir model of the field. An integrated approach is used in developing a 3D reservoir model of the Monument Northwest field and a waterflood is evaluated and analyzed by a simulation of the reservoir model. From the results of the reservoir simulation it was concluded that the waterflood project for the Monument Northwest field is a viable and economic project.

The Jacob field was discovered in the year 1931. In the year 2002, due to the low productivity of the field, the company wanted to determine whether to keep operating, abandon or sell the field. So they asked Texas A&M University to perform the study, determine the oil potential, and make recommendations to improve production. Since no previous reservoir study was performed in this field, the original oil in place and the current status of depletion was unknown. Therefore a complete integrated study was needed in order to learn about the reservoir and evaluate it in a qualitative and quantitative manner, before making any recommendation. The current pay zone underlying the Jacob field forms a monocline structure composed of unconsolidated young clastic sediments deposited in the Eocene epoch of the stratigraphic column of the Nueces River Basin, mainly due to a fluvial deltaic system developed in south Texas. The original oil in place for this pay zone was estimated to be 18.12 MMSTB and the cumulative production as of October 2003, 3.8 MMSTB. The analysis of the production data available had shown that the pay zone is being flooded by a strong water encroachment from the lower sides of the structure. This behavior was confirmed by the anisotropy analysis from core and log data, which shows that the reservoir tends to be more homogeneous in the direction of the water encroachment. It seems that there is not much room for further development in the current pay zone in the Jacob field (the remaining reserves were estimated to be 10 MSTB as of October 2003). However, the presence of a continuous shallow clean sandstone, not properly tested, of better reservoir properties than the actual pay zone was noticed. Moreover, this clean sandstone showed oil and gas presence in thirteen wells in the drilling cuttings. Therefore further development should concentrate more on investigating and developing the oil potential of the latter sandstone as well as accelerating the reserves production in the actual pay zone by means of waterflooding and/or infill drilling.

This research combines a statistical tool called experimental design/response surface methodology with reservoir modeling and flow simulation for the purpose of reservoir characterization. Very often, it requires large number of reservoir simulation runs for identifying significant reservoir modeling parameters impacting flow response and for history matching. Experimental design/response surface (ED/RS) is a statistical technique, which allows a systematic approach for minimizing the number of simulation runs to meet the two objectives mentioned above. This methodology may be applied to synthetic and field cases using existing statistical software tools. The application of ED/RS methodology for the purpose of reservoir characterization has been applied for two different objectives. The first objective is to address the uncertainties in the identification of the location and transmissibility of flow barriers in a field in the Gulf of Mexico. This objective is achieved by setting up a simple full-factorial design. The range of transmissibility of the barriers is selected using a Latin Hypercube Sampling (LHS). An analysis of variance (ANOVA) gives the significance of the location and transmissibility of barriers and comparison with decline-type curve analysis which gives us the most likely scenarios of the location and transmissibility of the flow barriers. The second objective is to identify significant geologic parameters in object-based and pixel-based reservoir models. This study is applied on a synthetic fluvial reservoir, whose characteristic feature is the presence of sinuous sand filled channels within a background of floodplain shale. This particular study reveals the impact of uncertainty in the reservoir modeling parameters on the flow performance. Box-Behnken design is used in this study to reduce the number of simulation runs along with streamline simulation for flow modeling purposes. In the first study, we find a good match between field data and that predicted from streamline simulation based on the most likely scenario. This validates the use of ED to get the most likely scenario for the location and transmissibility of flow barriers. It can be concluded from the second study that ED/RS methodology is a powerful tool along with a fast streamline simulator to screen large number of reservoir model realizations for the purpose of studying the effect of uncertainty of geologic modeling parameters on reservoir flow behavior.

The further exploration and development of Pabst Gas Field with faulted sand reservoirs require an understanding of the properties and roles of faults, particularly Low Throw near Vertical Faults (LTNVFs), in gas migration and accumulation at a reservoir scale. This study presents numerical modeling of gas migration and accumulation processes in Pabst Field. Based on studies of the reservoirs, structure, faults, and fluid properties of the field, reservoir scale modeling was performed to determine the gas supply style and the fault properties by means of hundreds of iterations in which the fault properties and gas supply pattern were modified to match the gas distribution obtained from modeling with the gas distribution inferred from seismic data constrained by well data and production data. This study finds that in the main three sand reservoirs of Pabst Field the overlying younger sands cut down into the underlying older sands, so that partial connections between the three sands allow gas communication among the sands. Meanwhile, three fault families break up the three sands into numerous compartments. A primary fault and large synthetic and antithetic faults act as gas migration pathways: the synthetic and antithetic faults are inlets for gas flow and the primary fault is an outlet, and LTNVFs act as barriers to gas flow. Modeling requires fault properties in the field to change while the field is formed. The porosity and permeability of the faults in Pabst Field are 10% and 0.1 md, respectively, during gas charging of the sand reservoirs. But when there is no gas charging and large gas columns are maintained, the porosity and permeability of the faults decrease to 6% and 0.001 md, respectively. Pabst Field probably has an impulse gas charge history. Fault opening and closing, gas charge and recharge, and replacement of gas by formation water may occur. A combination of stratigraphy, structure, overpressure and gas charge rate control gas migration style, gas charge history, and gas distribution in the field. The significance of the study is that this improved numerical approach for modeling gas migration into and through specifically faulted sand reservoirs fills the gap between basin modeling and production modeling.

This research evaluates and improves capabilities incorporated in the Water Rights Analysis Package (WRAP) modeling system for tracking salt loads, particularly for applications dealing with natural salt pollution problems that are prevalent in several major river basins in Texas and neighboring states. WRAP is the river/reservoir system simulation model incorporated in the Water Availability Modeling (WAM) System applied by agencies and consulting firms in Texas in planning and water right regulatory activities. A salinity simulation component of WRAP called WRAP-SALT was developed recently at Texas A&M University. WRAP-SALT was based on the premise of complete mixing within the monthly computational time step. However, salt concentrations actually have time variation throughout a reservoir. This thesis research investigates more realistic salinity routing methods. Historical gauged data provide a basis for calibration of routing parameters. The timing of the inflow load to determine outflow concentration is calculated by lag parameters with the monthly time steps. Complete mixing occurs during the lag months. Two options are incorporated into WRAP-SALT for setting the lag parameter. With the first option, the model-user sets a constant that is applied during every month of the simulation. This option requires calibration studies to determine the lag. With the alternative option, a variable lag is computed within the model in each month based on the concept of retention time, which is a representation of the time required for a monthly volume of water and its salt load to flow through a reservoir. When the lag is activated, the accuracy between observed and computed mean monthly salinity concentrations through the reservoir is generally improved. The basin-wide simulation was performed for the Brazos River Basin for conditions with and without salt control dams proposed by the Corps of Engineers. The proposed salt control impoundments improve water quality throughout the basin.

An integrated full-field study was conducted on the Monument Northwest field located in Kansas. The purpose of this study was to determine the feasibility and profitability of a waterflood using numerical simulation. Outlined in this thesis is a methodology for a deterministic approach. The data history of the wells in the field beginning from spud date were gathered and analyzed into information necessary for building an upscaled reservoir model of the field. Means of increasing production and recovery from the field via a waterflood was implemented. Usually, at the time of such a redevelopment plan or scheme to improve field performance, a tangible amount of information about the reservoir is already known. Therefore it is very useful incorporating knowledge about the field in predicting future behavior of the field under certain conditions. The need for an integrated reservoir study cannot be over-emphasized. Information known about the reservoir from different segments of the field exploration and production are coupled and harnessed into developing a representative 3D reservoir model of the field. An integrated approach is used in developing a 3D reservoir model of the Monument Northwest field and a waterflood is evaluated and analyzed by a simulation of the reservoir model. From the results of the reservoir simulation it was concluded that the waterflood project for the Monument Northwest field is a viable and economic project.

The development of coarsened reservoir simulation models from high resolution geologic models is a critical step in a simulation study. The optimal coarsening sequence becomes particularly challenging in a fluvial channel environment where the channel sinuosity and orientation can result in pay/non-pay juxtaposition in many regions of the geologic model. The optimal coarsening sequence is also challenging in tight gas sandstones where sharp changes between sandstone and shale beds are predominant and maintaining the pay/non-pay distinction is difficult. Under such conditions, a uniform coarsening will result in mixing of pay and non-pay zones and will likely result in geologically unrealistic simulation models which create erroneous performance predictions. In particular, the upgridding algorithm must keep pay and non-pay zones distinct through a non-uniform coarsening of the geologic model. We present a coarsening algorithm to determine an optimal reservoir simulation grid by grouping fine scale geologic model cells into effective simulation cells. Our algorithm groups the layers in such a way that the heterogeneity measure of an appropriately defined static property is minimized within the layers and maximized between the layers. The optimal number of layers is then selected based on an analysis resulting in a minimum loss of heterogeneity. We demonstrate the validity of the optimal gridding by applying our method to a history matched waterflood in a structurally complex and faulted offshore turbiditic oil reservoir. The field is located in a prolific hydrocarbon basin offshore South America. More than 10 years of production data from up to 8 producing wells are available for history matching. We demonstrate that any coarsening beyond the degree indicated by our analysis overly homogenizes the properties on the simulation grid and alters the reservoir response. An application to a tight gas sandstone developed by Schlumberger DCS is also used in our verification of our algorithm. The specific details of the tight gas reservoir are confidential to Schlumberger's client. Through the use of a reservoir section we demonstrate the effectiveness of our algorithm by visually comparing the reservoir properties to a Schlumberger fine scale model.