Paleokarst reservoirs consist of complex cave networks, which are formed by various mechanisms and associated collapsed cave facies. Traditionally, cave structures are defined using variogram-based methods in flow models and this description does not precisely represent the reservoir geology. Algorithms based on multiple-point statistics (MPS) are widely used in modeling complex geologic structures. Statistics required for these algorithms are inferred from gridded training images. However, structures like modern cave networks are represented by point data sets. Thus, it is not practical to apply rigid and gridded templates and training images for the simulation of such features. Therefore, a quantitative algorithm to characterize and model paleokarst reservoirs based on physical and geological attributes is needed. In this study, a unique non-gridded MPS analysis and pattern simulation algorithms are developed to infer statistics from modern cave networks and simulate distribution of cave structures in paleokarst reservoirs. Non-gridded MPS technique is practical by eliminating use of grids and gridding procedure, which is challenging to apply on cave network due to its complex structure. Statistics are calculated using commonly available cave networks, which are only represented by central line coordinates sampled along the accessible cave passages. Once the statistics are calibrated, a cave network is simulated by using a pattern simulation algorithm in which the simulation is conditioned to sparse data in the form of locations with cave facies or coordinates of cave structures. To get an accurate model for the spatial extent of the cave facies, an algorithm is also developed to simulate cave zone thickness while simulating the network. The proposed techniques are first implemented to represent connectivity statistics for synthetic data sets, which are used as point-set training images and are analogous to the data typically available for a cave network. Once the applicability of the algorithms is verified, non-gridded MPS analysis and pattern simulation are conducted for the Wind Cave located in South Dakota. The developed algorithms successfully characterize and model cave networks that can only be described by point sets. Subsequently, a cave network system is simulated for the Yates Field in West Texas which is a paleokarst reservoir. Well locations with cave facies and identified cave zone thickness values are used for conditioning the pattern simulation that utilizes the MP-histograms calibrated for Wind Cave. Then, the simulated cave network is implemented into flow simulation models to understand the effects of cave structures on fluid flow. Calibration of flow model against the primary production data is attempted to demonstrate that the pattern simulation algorithm yields detailed description of spatial distribution of cave facies. Moreover, impact of accurately representing network connectivity on flow responses is explored by a water injection case. Fluid flow responses are compared for models with cave networks that are constructed by non-gridded MPS and a traditional modeling workflow using sequential indicator simulation. Applications on the Yates Field show that the cave network and corresponding cave facies are successfully modeled by using the non-gridded MPS. Detailed description of cave facies in the reservoir yields accurate flow simulation results and better future predictions. / text

Meren field, located offshore Niger Delta, is one of the most prolific oil-producing fields in the Niger Delta. The upper Miocene D-07, D-08 and E-01 oil sands comprise a series of stacked hydrocarbon reservoirs in Block 2 of Meren field. These reservoir sandstones were deposited in offshore to upper shoreface environments. Seven depositional facies were identified in the studied interval, each with distinct lithology, sedimentary structures, trace fossils, and wire-line log character. The dominant lithofacies are (1) locally calcite-cemented highly-bioturbated, fine-grained sandstones, (middle to lower shoreface facies); (2) cross-bedded, fine- to medium-grained well-sorted sandstones (upper shoreface facies); (3) horizontal to sub-horizontal laminated, very-fine- to fine-grained sandstone (delta front facies); (4) massive very-fine- to fine-grained poorly-sorted sandstone (delta front facies); (5) muddy silt- to fine-grained wavy-bedded sandstone (lower shoreface facies); (6) very-fine- to fine-grained sandy mudstone (lower shoreface facies); and (7) massive, silty shales (offshore marine facies). Lithofacies have distinct mean petrophysical properties, although there is overlap in the range of values. The highest quality reservoir deposits are cross-bedded sands that were deposited in high-energy upper shoreface environments. Calcite cements in lower shoreface facies significantly reduce porosity and permeability. Integration of core and wire-line log data allowed porosity and permeability to be empirically determined from bulk density. The derived equation indicated that bulk density values could predict 80% of the variance in core porosity and permeability values. Three parasequence sets were interpreted, including one lower progradational and two upper retrogradational parasequence sets. The progradational parasequence set consists of upward-coarsening delta front to upper shoreface facies, whereas the upward-fining retrogradational parasequence sets are composed of middle to lower shoreface deposits overlain by offshore marine shales. The limited amount of core data and the relatively small area of investigation place serious constraints on stratigraphic interpretations. Two possible sequence stratigraphic interpretations are presented. The first interpretation suggests the deposits comprise a highstand systems tract overlain by a transgressive systems tract. A lowstand systems tract is restricted to an incised valley fill at the southeastern end of the study area. The alternate interpretation suggests the deposits comprise a falling stage systems tract overlain by transgressive systems tract.

>Magister Scientiae - MSc / The Bredasdorp Basin is one of the largest hydrocarbon producing blocks within Southern Africa. The E-M field is situated approximate 50 km west from the FA platform and was brought into commission due to the potential hydrocarbons it may hold. If this field is brought up to full producing capability it will extend the lifespan of the refining station in Mosselbay, situated on the south coast of South Africa, by approximately 8-10 years. This study is focused in block 9 off shore western part of the Bredasdorp Basin in the main Outeniqua Basin South Africa. Cretaceous Sandstone reservoirs are commonly heterogeneous consequently they may require special methods and techniques for description and evaluation. Reservoir characterization is the study of the reservoir rocks, their petrophysical properties, the fluids they contain or the manner in which they influence the movement of fluids in the subsurface. The main goal of the research is to assess the potentials of hydrocarbons in Cretaceous sediments in the Bredasdorp Basin through the integration and comparison of results from core analysis, production data and petrography studies for the evaluation and correction of key petrophysical parameters from wireline logs which could be used to generate an effective reservoir model for wells (E-BB1, E-BD2, EA01) in the Bredasdorp Basin. Porosity and permeability relationships, wire-line log data have been examined and analysed to determine how the porosity and permeability influence reservoir quality which further influences the potential of hydrocarbon accumulation in the reservoirs. The reservoir sandstone is composed mainly of fine to medium grained Sandstones with intercalation of finger stringers of Siltstone and Shale. In carrying out this research the samples are used to characterize reservoir zones through core observation, description and analyses and compare the findings with electronic data obtained from Petroleum Agency of South Africa (PASA). Secondary data obtained from (PASA) was analysed using softwares such as Interactive Petrophysics (IP), Ms Word, Ms excel and Surfer. Wireline logs of selected wells (E-BB1, E-BD2, E-A01) were generated, analysed and correlated. Surfer software also used to digitize maps of project area, porosity and permeability plotted using IP. Formation of the Bredasdorp Basin and it surrounding basins during the Gondwana breakup. The Bredasdorp Basin consists mainly of tilting half graben structures that formed through rifting with the break-up of Gondwanaland. The model also revealed that these faults segregate the reservoir which explains the pressure loss within the block. The production well was drilled, confining pressure relieved and pressure dropped hence production decreases. The age, transportation, deposition and thermal history of sediment in the basin, all plays a vital role in the type of hydrocarbon formation. Structural features such as faults, pore spaces determines the presence of a hydrocarbon in the reservoir. Traps could be stratigraphic or structural which helps prevent the migration of hydrocarbons from the source rock to reservoir rock or from reservoir rock to the surface over a period of time. The textural aspects included the identification of grain sizes, sorting and grain shapes. The diagenetic history, constructed from the results of the reservoir quality study revealed that there were several stages involved in the diagenetic process. It illustrated several phases of cementation with quartz, carbonate and dolomite with dissolution of feldspar. A potentially good reservoir interval was identified from the data and was characterized by several heterogeneous zones. Identifying reservoir zones was highly beneficial during devising recovery techniques for production of hydrocarbons. Secondary recovery methods have thus been devised to enhance well performance. As recommendation, additional wells are required to appraise the E-M structure and determine to what extent the cement present in the basin has affected fluid flow as well as the degree of sedimentation that could impede fluid flow. There are areas still containing untapped resources thus the recommendation for extra wells. This research may well be reviewed with more data input from PetroSA (wells, seismic and production data) for additional studies, predominantly with respect to reservoir modelling and flow simulation. Based on the findings of this research, summary of calculated Net Pay shows that in well E-BB1, reservoir (1) is at depth 2841.5m – 2874.9m has a Gross Thickness of 33.40m, Net Pay of 29.72 and Pay Summary of 29.57 and reservoir (2) has depth of 2888.1m – 2910.5m, Gross Thickness of 22.40m, Net Pay of 19.92m and Pay summary of 1.48m. Well E-AO1 has depth from 2669.5m – 2684.5m and Gross Thickness of 15.00m and has Net Pay of 10.37m and Pay Summary of 10.37m. Based on the values obtained from the data analysed the above two wells displays high potential of hydrocarbon present in the reservoirs. Meanwhile well E-BD2 has depth from 2576.2m – 2602.5m and has Gross Thickness of 350.00m, Net Pay of 28.96m and Pay Summary of 4.57 hence from data analysis this reservoir displays poor values which is an indication of poor hydrocarbon potentials.

Master of Science / Department of Geology / Abdelmoneam Raef / This research presents a workflow integrating several post-stack seismic attributes to assist in understanding the development history of Weirman Field, Ness County, KS. This study contributes to shaping future drilling plans by establishing a workflow combining analysis of seismic attributes and well cuttings to locate a channel fill zone of better reservoir quality, and to highlight reservoir boundaries due to compartmentalization. In this study, I have successfully outlined a fluvial channel, which is expected to be significantly different in terms of petrophysical properties. The Pennsylvanian aged Cherokee sandstones that potentially comprise channel fill lithofacies, in this study, have been linked to oil production throughout the state of Kansas. It is important to understand channel sandstones when evaluating drilling prospects, because of their potential as an oil reservoir and unpredictable shapes and locations. Since their introduction in the 1970s, seismic attributes have become an essential part of lithological and petrophysical characterization of hydrocarbon reservoirs. Seismic attributes can correlate to and help reveal certain subsurface characteristics and specific geobodies that cannot be distinguished otherwise. Extracting and analyzing acoustic impedance, root-mean-square amplitude and amplitude attenuation, guided by a time window focused on the top of the Mississippian formation, resulted in an understanding of the key seismic channel-facies framework and helped to explain some of the disappointing drilling results at Weirman Field. To form a better understanding of these seismic attributes, this study combined certain attributes and overlayed them in partially transparent states in order to summarize and better visualize the resulting data. A preliminary study of spectral decomposition, which was introduced in the late 1990s, was preformed, and a more in-depth study of this multi-resolution attribute is recommended for future study of this particular field. This study also recommends integrating the revealed compartmentalization boundary and the seismic channel-facies framework in future drilling plans of Weirman Field.

Middle Pennsylvanian (Desmoinesian) strata of the Lower Desert Creek (LDC) sequence within the sub-surface Greater Aneth Field (GAF) reflect a hierarchy of 4th and 5th order carbonate-dominated cycles. The Lower Desert Creek sequence, along the studied transect are composed of eight carbonate facies deposited on an east-facing shelf. There is a lateral transition from open marine algal buildup from the southeast (cores R-19, Q-16, O-16, and J-15) to a more restricted lagoonal environment to the northwest (core K-430 and E-313). The Lower Desert Creek sequence within the GAF contains three main parasequence sets: a basal, relatively deep-water unit (LDC 1), a middle skeletal to algal unit (LDC 2-4), and a shallow, open-marine/restricted lagoon unit (LDC 5-7). The southeast cores (R-19, Q-16, O-16, and J-15) contain the dolomitized basal unit in parasequence LDC 1. The northwest cores (K-430 and E-313) also contain the dolomitized basal unit in LDC 1, but show a deeper facies succession through LDC 2-4. Parasequences LDC 2-4 are the heart of the algal buildup in the GAF particularly in the southern part of the transect. The upper few parasequences (LDC 5-7) are dominated by an open marine environment represented by robust fauna. The upper parasequences (LDC 5-7) show the same shallowing upward trends with algal facies in K-430 and restricted lagoon facies in E-313. Shoaling upward trends that characterize the Lower Desert Creek sequence terminate with an exposure surface at the 4th order (Lower Desert Creek-Upper Desert Creek) sequence boundary. Porosity and permeability is weakly correlated to facies. Diagenesis within the algal reservoir is the most important factor in porosity and permeability. Marine diagenesis is observed in the form of micritization of Ivanovia, a phylloid algae. Thin fibrous isopachous rims of cloudy cement also indicate early marine diagenesis. Ghost botryoidal cements are leached during meteoric diagenesis. Meteoric drusy dog tooth cements as well as sparry calcite fill most depositional porosity. Neomorphism of micrite and the isopachous rim cements reflect meteoric diagenesis. Burial diagenesis is represented by baroque dolomite cement, compaction, and mold-filling anhydrite cement.

The Multilayer Transient Test is a well-testing technique designed to determine formation properties in multiple layers, and it has been proved effective during the past two decades. To apply the Multilayer Transient Test, a combination of rate profiles from production logs and transient rate and pressure measurements are required at multiple surface rates. Therefore, this method can be time consuming and may involve significant errors due to inaccurate transient flow rate measurements. A new testing approach is proposed after realizing the limitations of the Multilayer Transient Test. The new testing approach replaces the transient flow rate measurement with transient temperature measurement by using multiple temperature sensors. This research shows that formation properties can be quantified in multiple layers by analyzing measured transient temperature and pressure data. A single-phase wellbore/reservoir coupled thermal model is developed as the forward model. The forward model is used to simulate the temperature and pressure response along the wellbore during the transient test. With the forward model, this work proves that the transient temperature and pressure are sufficiently sensitive to formation properties and can be used for multilayer reservoir characterization. The inverse model is formulated by incorporating the forward model to solve formation properties using nonlinear least-square regression. For the hypothetical cases, the proposed new multilayer testing method has successfully been applied for investigating formation properties in commingled multilayer reservoirs. Layer permeability, damaged permeability, and damaged radius can be uniquely determined using single-point transient pressure data and multipoint transient temperature data at appropriate locations. Due to the proposed data acquisition scheme, only one surface flow rate change is needed to implement this testing approach, which significantly reduces the test duration compared to the standard multilayer transient testing approach using a series of flow rate changes. Of special interest, this is the first test design that shows promise for determination of the damaged radius, which can be useful for well stimulation design. In addition, temperature resolution, data noise, and data rate impacts have been studied along with a data filtering approach that enable selection of suitable pressure and temperature sensor technologies for applying the new testing method.

In this thesis, we propose two novel approaches for hybrid Ensemble Kalman Filter (EnKF) to overcome limitations of the traditional EnKF. The first approach is to swap the ensemble mean for the ensemble mode estimation to improve the covariance calculation in EnKF. The second approach is a coarse scale permeability constraint while updating in EnKF. Both hybrid EnKF approaches are coupled with the streamline based Generalized Travel Time Inversion (GTTI) algorithm for periodic updating of the mean of the ensemble and to sequentially update the ensemble in a hybrid fashion. Through the development of the hybrid EnKF algorithm, the characteristics of the EnKF are also investigated. We found that the limits of the updated values constrain the assimilation results significantly and it is important to assess the measurement error variance to have a proper balance between preserving the prior information and the observation data misfit. Overshooting problems can be mitigated with the streamline based covariance localizations and normal score transformation of the parameters to support the Gaussian error statistics. The swapping mean and mode estimation approach can give us a better matching of the data as long as the mode solution of the inversion process is satisfactory in terms of matching the observation trajectory. The coarse scale permeability constrained hybrid approach gives us better parameter estimation in terms of capturing the main trend of the permeability field and each ensemble member is driven to the posterior mode solution from the inversion process. However the WWCT responses and pressure responses need to be captured through the inversion process to generate physically plausible coarse scale permeability data to constrain hybrid EnKF updating. Uncertainty quantification methods for EnKF were developed to verify the performance of the proposed hybrid EnKF compared to the traditional EnKF. The results show better assimilation quality through a sequence of updating and a stable solution is demonstrated. The potential of the proposed hybrid approaches are promising through the synthetic examples and a field scale application.

Horizontal well temperature and pressure distributions can be measured by production logging or downhole permanent sensors, such as fiber optic distributed temperature sensors (DTS). Correct interpretation of temperature and pressure data can be used to obtain downhole flow conditions, which is key information to control and optimize horizontal well production. However, the fluid flow in the reservoir is often multiphase and complex, which makes temperature and pressure interpretation very difficult. In addition, the continuous measurement provides transient temperature behavior which increases the complexity of the problem. To interpret these measured data correctly, a comprehensive model is required. In this study, an interpretation model is developed to predict flow profile of a horizontal well from downhole temperature and pressure measurement. The model consists of a wellbore model and a reservoir model. The reservoir model can handle transient, multiphase flow and it includes a flow model and a thermal model. The calculation of the reservoir flow model is based on the streamline simulation and the calculation of reservoir thermal model is based on the finite difference method. The reservoir thermal model includes thermal expansion and viscous dissipation heating which can reflect small temperature changes caused by pressure difference. We combine the reservoir model with a horizontal well flow and temperature model as the forward model. Based on this forward model, by making the forward calculated temperature and pressure match the observed data, we can inverse temperature and pressure data to downhole flow rate profiles. Two commonly used inversion methods, Levenberg- Marquardt method and Marcov chain Monte Carlo method, are discussed in the study. Field applications illustrate the feasibility of using this model to interpret the field measured data and assist production optimization. The reservoir model also reveals the relationship between temperature behavior and reservoir permeability characteristic. The measured temperature information can help us to characterize a reservoir when the reservoir modeling is done only with limited information. The transient temperature information can be used in horizontal well optimization by controlling the flow rate until favorite temperature distribution is achieved. With temperature feedback and inflow control valves (ICVs), we developed a procedure of using DTS data to optimize horizontal well performance. The synthetic examples show that this method is useful at a certain level of temperature resolution and data noise.

Reconciling high-resolution geologic models to field production history is still a very time-consuming procedure. Recently streamline-based assisted and automatic history matching techniques, especially production data integration by “travel-time matching,” have shown great potential in this regard. But no systematic study was done to examine the merits of travel-time matching compared to more traditional amplitude matching for field-scale application. Besides, most applications were limited to two-phase water-oil flow because current streamline models are limited in their ability to incorporate highly compressible flow in a rigorous and computationally efficient manner. The purpose of this work is fourfold. First, we quantitatively investigated the nonlinearities in the inverse problems related to travel time, generalized travel time, and amplitude matching during production data integration and their impact on the solution and its convergence. Results show that the commonly used amplitude inversion can be orders of magnitude more nonlinear compared to the travel-time inversion. Both the travel-time and generalized travel time inversion (GTTI) are shown to be more robust and exhibit superior convergence characteristics. Second, the streamline-based assisted history matching was enhanced in two important aspects that significantly improve its efficiency and effectiveness. We utilize streamline-derived analytic sensitivities to determine the location and magnitude of the changes to improve the history match, and we use the iterative GTTI for model updating. Our approach leads to significant savings in time and manpower. Third, a novel approach to history matching finite-difference models that combines the efficiency of analytical sensitivity computation of the streamline models with the versatility of finite-difference simulation was developed. Use of finite-difference simulation can account for complex physics. Finally, we developed an approach to history matching three-phase flow using a novel compressible streamline formulation and streamline-derived analytic sensitivities. Streamline models were generalized to account for compressible flow by introducing a relative density of total fluids along streamlines and a density-dependent source term in the saturation equation. The analytical sensitivities are calculated based on the rigorous streamline formulation. The power and utility of our approaches have been demonstrated using both synthetic and field examples.

Many low matrix-porosity hydrocarbon reservoirs are productive because permeability is controlled by natural fractures. The understanding of basic fracture properties is critical in reducing geological risk and therefore reducing well costs and increasing well recovery. Unfortunately, neither geophysics nor borehole methods are, so far, accurate in the acquisition of key fracture attributes, such as density, porosity, spacing and conductivity. This study proposes a new protocol to predict key fracture characteristics of subsurface carbonate rocks and describes how using a relatively low-cost but rock-based method it is possible to obtain accurate geological information from rock samples to predict fracture attributes in nearby but unsampled areas. This methodology is based on the integration of observations of diagenetic fabrics and fracture analyses of carbonate rocks, using outcrops from the Lower Cretaceous Cupido Formation in the Monterrey Salient of the Sierra Madre Oriental, northeastern Mexico. Field observations and petrographic studies of crosscutting relations and fracture-fill mineralogy and texture distinguish six principal coupled fracturing-cementation events. Two fracture events named F1 and F2 are characterized by synkinematic calcite cement that predates D2 regional dolomitization. A third fracture event (F3) is characterized by synkinematic dolomite fill, contemporaneous with D2 dolomitization of host strata. The fourth event (F4) is characterized by synkinematic D3 baroque dolomite; this event postdates D2. The fifth fracture event (F5) is characterized by C3 synkinematic calcite, and postdates D3 dolomite. Finally, flexural slip faulting (F6) is characterized by C3t calcite, and postdates D3 dolomite. Carbon and oxygen stable isotopes were used to validate the paragenetic sequences proposed for the Cupido Formation rocks. The dolomite isotopic signatures are consistent with increasing precipitation temperatures for the various fracture cements, as is expected if fractures grew during progressive burial conditions. Three main groups of calcite cement can be differentiated isotopically. Late calcite cement may have precipitated from cool waters under shallow burial conditions, possibly during exhumation of the SMO. The development of the Structural Diagenetic Petrographic Study protocol, and its integration with geological, geophysical and engineering data, can be applied to oil fields in fractured carbonates such as those located in Mexico, to validate its applicability. / text