Master of Science / Department of Geology / Saugata Datta / In response to increasing concerns over release of anthropogenic greenhouse gases the Arbuckle saline aquifer in south-central Kansas has been proposed as a potential site for geologic storage for CO2. Two wells (KGS 1-32 and 1-28) have been drilled to provide data for site specific determination of the storage potential of the Arbuckle. Cores from specific depths within Arbuckle (4164`-5130`) were utilized for study and flow-through experiments. Examination of formation rocks by thin section studies, SEM, XRD and CT scans was carried out to characterize the mineralogy of the core. Dominant mineralogy throughout the formation is dolomite with large chert nodules and occasional zones with pyrite and argillaceous minerals. Carbonate-silica contacts contain extensive heterogeneity with sulfide minerals and argillaceous material in between. Extensive vugs and microfractures are common. This study focuses on three zones of interest: the Mississippian pay zone (3670`-3700`), a potential baffle in Arbuckle (4400`-4550`) and the proposed CO2 injection zone (4900`-5050`). Drill stem tests and swabbed brine samples collected from 13 depths throughout the aquifer reveal a saline brine (~50,000-190,000 TDS) dominated by Na+, Ca2+ and Cl-. Elemental ratios of major cations with Cl- demonstrate a typical saline aquifer system. Cl/Br ratios reveal mixing between primary and secondary brines within the aquifer. Ca/Cl and Mg/Cl ratios suggest effect of dolomitization within the brines. δ18O and δ2H isotopes and Li/Cl ratios in the brine suggest the separation of upper and lower Arbuckle by a baffle zone. Swabbed waters provide Fe speciation data and reveal the importance of it in the system. Laboratory experiments carried out at 40°C and 2100 psi using formation core plug and collected brine identify reaction pathways to be anticipated when supercritical CO2 is injected. Results showed fluctuating chemistries of elements with Ca2+, Mg2+, Na+ and Cl- increasing during the first 15 hours, while Fe, S, and SO42- decrease. For the next 15 hours a reverse trend of the same elements were observed. Alkalinity and pH show inverse relationship throughout the experiment. We conclude that dominant reactions will occur between brine, CO2 and dolomite, calcite, chert, pyrite and argillaceous minerals. There is no perceived threat to freshwater resources in Kansas due to CO2 injection.

This thesis presents results of a successful simulation study using CO2-EOR technique to enable production from an offshore heavy oil field, named here as Omega, which is located offshore West Africa at a water depth around 2000 m. The findings and contributions to knowledge are outlined below: 1. Long distance CO2 transportation offshore – The solution to the space and weight constraints offshore with respect to CO2-EOR, is a tie-back via long distance CO2 dense phase transportation from onshore to offshore. 2. Cold heavy oil production (CHOP) using CO2-EOR technique - Based on conditions investigated, Miscible Displacement was found to be more efficient for deepwater production. However, Immiscible Displacement can offer greater reliability with regards to CO2 sequestration. 3. CO2 sequestration during CHOP using CO2-EOR technique – Lower CO2 may be released post start-up operation, followed by gradual decline of CO2 retention after the production peak. CO2 retention increases with increasing reservoir pressure, starting with 17.7 % retention at 800 psig to 32.8 % at 5000 psig, based on peak production analysis. 4. Techno-economic Evaluation – Miscible displacement is asssociated with higher cash flow stream that extend throughout the lifetime of the asset due to continuous production while Immiscible Displacement has a longer payback period (in order of 22 years) due to the time lag between the CO2 injection and the incremental heavy oil production. 5. Mathematical Modelling – Improved mathematical models based on existing theories are proposed, to estimate the CO2 requirement and heavy oil production during CHOP using CO2-EOR technique, and to provide an operating envelope for a wide range of operating conditions. As part of further work, the proposed models will require more refinement and validation across a broad range of operating conditions, could be adapted and modified to increase its predictive capability over time.

Salt water is produced from the Ferron Sandstone Member of the Mancos Shale in central Utah as part of the production of coalbed methane (CBM) and is disposed of by injection predominantly into the Navajo Sandstone between 4,500 feet to 7,300 feet and is considered to be a hazardous waste. Local government agencies are concerned about the potential impacts on shallow groundwater because of this disposal method. Water samples were gathered from four shallow water-supply wells, and nine salt water disposal (SWD) wells to compare hydrochemistries as an indicator of potential mixing. Shallow water-supply wells are likely recharged by local precipitation while the source of CO2 is from atmospheric and/or soil CO2 gas and comparatively, are low in total dissolved solids. Carbonate mineral dissolution is the source of CO2 in the SWD wells and is exceptionally high in TDS. The SWD water appears to be old water and displays an evaporative signature. A geologic analysis was conducted for the Drunkards Wash gas field using 479 digital gas well logs. Three subsurface faults were identified with one fault in the north and the other two in the central part of the gas field near the eastern and western flanks. These faults were further confirmed by comparing average monthly gas and water production from the first 24 months in these faulted areas to adjacent control areas. Areas near faults reveal two to six times greater gas production than that of the associated control areas, and water production is greater by nearly an order of magnitude. This difference is likely due to the fracturing associated with the damage zone near the faults allowing for increased flow of gas and water. Due to the high injection pressures the vertical hydraulic gradient has been reversed from downward to upward. However, due to the thick sequences of shale separating the disposal aquifers and the shallow aquifers the estimated time required for the disposal waters to migrate to the surface would be at least 2,000 years. I conclude that the saline waters produced from the Ferron Sandstone are being safely sequestered in deeply buried, extensive and geologically-sealed aquifers.

Seismic full waveform inversion (waveform tomography) is a method to reconstruct the underground velocity field in high resolution using seismic data. The method was first introduced during the 1980’s and became computationally feasible during the late 1990’s when the method was implemented in the frequency domain. This work presents three case studies and one synthetic benchmark of full waveform inversion applications. Two of the case studies are focused on time-lapse cross-well and 2D reflection seismic data sets acquired at the Ketzin CO2 geological storage site. These studies are parts of the CO2SINK and CO2MAN projects. The results show that waveform tomography is more effective than traveltime tomography for the CO2 injection monitoring at the Ketzin site for the cross-well geometry. For the surface data sets we find it is difficult to recover the true value of the velocity anomaly due to the injection using the waveform inversion method, but it is possible to qualitatively locate the distribution of the injected CO2. The results agree well with expectations based upon conventional 2D CDP processing methods and more extensive 3D CDP processing methods in the area. A further investigation was done to study the feasibility and efficiency of seismic full waveform inversion for time-lapse monitoring of onshore CO2 geological storage sites using a reflection seismic geometry with synthetic data sets. The results show that waveform inversion may be a good complement to standard CDP processing when monitoring CO2 injection. The choice of method and strategy for waveform inversion is quite dependent on the goals of the time-lapse monitoring of the CO2 injection. The last case study is an application of the full waveform inversion method to two crooked profiles at the Forsmark site in eastern central Sweden. The main goal of this study was to help determine if the observed reflections are mainly due to fluid filled fracture zones or mafic sills. One main difficulty here is that the profiles have a crooked line geometry which corresponds to 3D seismic geometry, but a 2D based inversion method is being used. This is partly handled by a 3D to 2D coordinate projection method from traveltime inversion. The results show that these reflections are primarily due to zones of lower velocity, consistent with them being generated at water filled fracture zones.

Reservoir management, sometimes referred to as asset management in the context of petroleum reservoirs, has become recognized as an important facet of petroleum reservoir development and production operations. In the first stage of planning field development, the simulation model is calibrated to dynamic data (history matching). One of the aims of the research is to extend the streamline based generalized travel time inversion method for full field models with multimillion cells through the use of grid coarsening. This makes the streamline based inversion suitable for high resolution simulation models with decades long production history and numerous wells by significantly reducing the computational effort. In addition, a novel workflow is proposed to integrate well bottom-hole pressure data during model calibration and the approach is illustrated via application to the CO2 sequestration. In the second stage, field development strategies are optimized. The strategies are primarily focused on rate optimization followed by infill well drilling. A method is proposed to modify the streamline-based rate optimization approach which previously focused on maximizing sweep efficiency by equalizing arrival time of the waterfront to producers, to account for accelerated production for improving the net present value (NPV). Optimum compromise between maximizing sweep efficiency and maximizing NPV can be selected based on a 'trade-off curve.' The proposed method is demonstrated on field scale application considering geological uncertainty. Finally, a novel method for well placement optimization is proposed that relies on streamlines and time of flight to first locate the potential regions of poorly swept and drained oil. Specifically, the proposed approach utilizes a dynamic measure based on the total streamline time of flight combined with static and dynamic parameters to identify "Sweet-Spots" for infill drilling. The "Sweet-Spots" can be either used directly as potential well-placement locations or as starting points during application of a formal optimization technique. The main advantage of the proposed method is its computational efficiency in calculating dynamic measure map. The complete workflow was also demonstrated on a multimillion cell reservoir model of a mature carbonate field with notable success. The infill locations based on dynamic measure map have been verified by subsequent drilling.

This work examines the impact of a viscosity force parameter, fluid velocity, and a capillary force parameter, interfacial tension, on the saturation, morphology, and topology of NW fluid in Bentheimer sandstone after primary imbibition, drainage, and secondary imbibition. Brine and air (used as a proxy for supercritical CO₂) flow experiments were performed on 6 mm diameter Bentheimer cores and were quantified via imaging with x-ray computed microtomography (x-ray CMT), which allows for three dimensional, non-destructive, pore-scale analysis of the amount and distribution of NW phase fluid within the sandstone cores. It was found that trapped NW phase saturation decreases with increases in capillary number, average blob size decreases with increases in capillary number, and the number of NW blobs increases with increases in capillary number. In addition, it was found that NW phase trapping is dependent on initial NW phase connectivity within the porous medium; with more negative values of initial NW phase Euler number resulting in less trapping. We suggest that the Euler number-saturation and the capillary number-saturation relationships for a given medium should be taken into consideration when designing a CO₂ sequestration scenario. / Graduation date: 2013

This investigation tested simulated saline lake environments as mineralization sites for sequestering anthropogenic CO2. Four unique saline lakes were simulated in the laboratory. Two sets of experiments were conducted by diffusing CO2(g) through each simulated lake over 30 days. The first set tested the carbonate system response to elevated CO2(g). The second set of experiments replicated the same process but used ammonium hydroxide to elevate pH. Water samples were collected daily to test for cation loss via mineralization. Rapid mineralization occurred with the pH enhancer and cation activity was greatly reduced by as much as 38,000 mg/L Ca due to precipitation. This resulted in a mass of 100,000 mg/L of CO2 being sequestered via Ca and Mg-carbonate mineralization. With proper geochemical conditions, saline lake environments can therefore potentially serve a purpose in sequestering CO2(g).

Global warming and climate change are closely related to the amount of CO2 in the air. Forest ecosystem plays very important role in the global carbon cycle; CO2 from the atmosphere is taken up by vegetation and stored as plant biomass. Therefore, quantifying biomass and carbon sequestration in tropical forests has a significant concern within the United Nations Framework Convention on Climate Change (UNFCC), Kyoto Protocol and Reducing Emission from Deforestation and Forest Degradation (REDD) program for the purpose of the improvement of national carbon accounting as well as for addressing the potential areas for carbon credits, basis for payment for environmental services. The aim of research is to estimate biomass and carbon stocks in tropical forests using remote sensing data for dry forest of central highlands of Vietnam. This result showed that from satellite images of the SPOT, satellites could build the land cover map, carbon map and biomass map of Yok Don National Park, Central Highlands of Vietnam. Through which also the biomass (above ground biomass and below ground biomass) of each type of forest can be calculated. For instance the biomass of the dry forest (Dry Dipterocarp Forest) is 153.49 tones x ha-1, biomass of rich forest is 343.35 tones x ha-1, biomass of medium forest is 210.34 tones x ha-1 and biomass of poor forest & scrub are 33.56 tones x ha-1. / Sự ấm lên toàn cầu và biến đổi khí hậu có liên quan chặt chẽ với tổng lượng CO2 trong không khí. Hệ sinh thái rừng có vai trò rất quan trọng trong chu trình các bon toàn cầu; khí CO2 trong khí quyển được hấp thụ bởi thảm thực vật dưới dạng sinh khối. Vì vậy, việc xác định sinh khối và carbon tích trữ trong rừng nhiệt đới đã có được sự quan tâm đáng kể trong Công ước của Liên hiệp quốc về biến đổi khí hậu (UNFCC), Nghị định thư Kyoto và Chương trình giảm phát thải từ phá rừng và suy thoái rừng (REDD) gần đây, nhằm cho mục đích cải thiện việc tính toán lượng các bon tích trữ cũng như giải quyết các vấn đề tiềm năng cho tín dụng các bon, làm cơ sở cho việc thanh toán cho các dịch vụ môi trường. Mục đích của nghiên cứu này là ước lượng sinh khối và các bon lưu trữ trong các khu rừng nhiệt đới bằng cách sử dụng dữ liệu viễn thám, mà ở nghiên cứu này là cho rừng khộp Tây Nguyên của Việt Nam. Kết quả cho thấy rằng, từ ảnh vệ tinh SPOT có thể xây dựng bản đồ lớp phủ thực vật, bản đồ các bon và bản độ sinh khối của Vườn quốc gia Yok Đôn, Tây Nguyên Việt Nam. Qua đó đã tính toán được sinh khối (bao gồm cả trên mặt đất và dưới mặt đất) như: đối với sinh khối của rừng khô cây họ dầu (Dry Dipterocarp Forest) là 153,59 tấn/ha, sinh khối rừng giàu là 343,35 tấn/ha, sinh khối rừng trung bình là 210,34 tấn/ha và sinh khối rừng nghèo&cây bụi là 33,56 tấn/ha.

The analytical and numerical modeling of CO2 sequestration in deep saline aquifers having different properties was studied with diffusion and convection mechanisms. The complete dissolution of CO2 in the aquifer by diffusion took thousands, even millions of years. In diffusion dominated system, an aquifer with 100 m thickness saturated with CO2 after 10,000,000 years. It was much earlier in convective dominant system. In diffusion process, the dissolution of CO2 in aquifer increased with porosity increase / however, in convection dominant process dissolution of CO2 in aquifer decreased with porosity increase. The increase in permeability accelerated the dissolution of CO2 in aquifer significantly, which was due to increasing velocity. The dissolution process in the aquifer realized faster for the aquifers with lower dispersivity. The results of convective dominant mechanism in aquifers with 1md and 10 md permeability values were so close to that of diffusion dominated system. For the aquifer having permeability higher than 10 md, the convection mechanism began to dominate gradually and it became fully convection dominated system for 50 md and higher permeability values. These results were also verified with calculated Rayleigh number and mixing zone lengths. The mixing zone length increased with increase in porosity and time in diffusion dominated system. However, the mixing zone length decreased with increase in porosity and it increased with increase in dispersivity and permeability higher than 10 md in convection dominated system.

Although deep saline aquifers are found in all sedimentary basins and provide very large storage capacities, a little is known about them because they are rarely a target for the exploration. Furthermore, nearly all the experiments and simulations made for CO2 sequestration in deep saline aquifers are related to the sandstone formations. The aim of this study is to create a predictive model to estimate the CO2 storage capacity of the deep saline carbonate aquifers since a little is known about them. To create a predictive model, the variables which affect the CO2 storage capacity and their ranges are determined from published literature data. They are rock properties (porosity, permeability, vertical to horizontal permeability ratio), fluid properties (irreducible water saturation, gas permeability end point, Corey water and gas coefficients), reaction properties (forward and backward reaction rates) and reservoir properties (depth, pressure gradient, temperature gradient, formation dip angle, salinity), diffusion coefficient and Kozeny-Carman Coefficient. Other parameters such as pore volume compressibility and density of brine are calculated from correlations found in literature. To cover all possibilities, Latin Hypercube Space Filling Design is used to construct 100 simulation cases and CMG STARS is used for simulation runs. By using least squares method, a linear correlation is found to calculate CO2 storage capacity of the deep saline carbonate aquifers with a correlation coefficient 0.81 by using variables found from literature and simulation results. Numerical dispersion effects have been considered by increasing the grid dimensions. It has been found that correlation coefficient decreased to 0.77 when the grid size was increased from 250 ft to 750 ft. The sensitivity analysis shows that the most important parameter that affects CO2 storage capacity is depth since the pressure difference between formation pressure and fracture pressure increases with depth. Also, CO2 storage mechanisms are investigated at the end of 300 years of simulation. Most of the gas (up to 90%) injected into formation dissolves into the formation water and negligible amount of CO2 reacts with carbonate. This result is consistent with sensitivity analysis results since the variables affecting the solubility of CO2 in brine have greater affect on storage capacity of aquifers. Dimensionless linear and nonlinear predictive models are constructed to estimate the CO2 storage capacity of all deep saline carbonate aquifers and it is found that the best dimensionless predictive model is linear one independent of bulk volume of the aquifer.