Abstract Burrow-associated diagenetic alteration and eventual reservoir quality parameters such as porosity and permeability may be altered due to reorganization of the sediment fabric associated with animal burrowing, or result from heterogeneous cement distribution influenced by the bioturbate texture. Petrographic analysis has significant application in recognizing burrow-associated porosity characteristics in marine sandstones. Petrographic analysis can provide mineral identification due to diagenetic chemical alterations and textural evidence regarding cementation history that can lead to more accurate hydrocarbon target interpretations. Overlooking burrow structures may lead to misinterpretations of permeability streaks in hydrocarbon reservoirs. This may be extremely important for reservoirs where slight permeability variations have an effect on hydrocarbon reserve calculations. Understanding biogeochemical reactions and burrow-associated diagenesis that ultimately control reservoir quality is necessary if production from ancient bioturbated marine sandstone reservoirs is to be optimized.

No description available.

The Columbus Basin, offshore Trinidad, is a mature gas producing basin with a number of major fields now in decline. Focus for infield exploration and production is shifting, with thin bedded sandstones as a secondary pay target. This basin is exceptional as age equivalent analogues to the subsurface reservoirs are exposed along the south east coast of Trinidad at Mayaro Bay (16 – 25 m sections). This research utilizes these outcrops and integrates findings with subsurface core data to present an improved understanding of thin bedded sandstones in three significant areas: 1) depositional setting on a wave dominated delta through description and interpretation of their large scale architecture and facies associations, 2) reservoir quality and connectivity of the facies and microfacies that comprise these heterolithic units through petrography and pore system characterization and 3) pore scale reservoir quality and connectivity through micro CT imaging and 3D modelling of their pore system morphology. Detailed sedimentological analysis has revealed that thin beds are highly interbedded units with thicknesses of 0.1 – 10 cm and have a lenticular geometry. Their lateral extent, controlled by their exposure, varies from 3 to 10s m in some areas. Field sampling and microfacies analysis, revealed five distinct lithofacies types and five microfacies types that make up two principal facies associations (FA): (FA1) axial distal delta front facies and (FA2) lateral distal delta front facies. The reservoir quality poroperm data achieved for the thin sandstones of these two facies associations are consistent with routine core analysis data from basin core and industry assigned values for conventional thicker bedded sandstones, inferring their secondary reservoir potential. Utilizing new techniques such as X-Ray tomography, a high resolution 3D model of the thin sandstone pore systems has been created for qualitative and quantitative reservoir characterization, especially vertical and lateral connectivity within the thin bedded units. This detailed dataset of 3D pore dimensions that can be used as conditioning data for other reservoir models. The observations and conclusions of this research give an insight into the depositional architecture and thin bedded sandstones on a distal delta front and their associated reservoir properties and connectivity mechanisms that facilitate an effective reservoir. These findings may inform and guide future exploration and appraisal, development and production and well completion and configuration programmes for thin bedded reservoirs as explained by the implications and recommendations at the end of this thesis.

Master of Science / Department of Geology / Matthew W. Totten / The area of study for this project is the Leach Field, which is located in Jackson County, Kansas. Production in the Leach Field has historically been disappointing, with 388,787 barrels of oil being produced since the field’s discovery in 1963 (KGS, 2015). Production of the field has been highly variable, with only 20,568 barrels of oil being produced in the last 20 years. Economic and other concerns that have impacted production and production rates of the field include: low oil prices soon after its discovery, numerous changes of ownership, and lack of significant production infrastructure in the area. Stroke of Luck Energy & Exploration, LLC. has recently purchased the majority of the leases and wells in the Leach Field, and is reestablishing the field as a productive oil field. Plans include: washing down several plugged and abandoned wells, and drill new wells to increase production in the field. The goal of this study was to determine the major geologic factors controlling reservoir quality in the Hunton and Viola Limestone Formations in the Leach Field, so that a future exploration model can be developed to help increase and stabilize the field's overall production. This model was created by applying several testing methods including: well logging analysis, microscope analysis, and subsurface mapping. Based on these results it was determined that the quality of the reservoir rocks is controlled by the degree of dolomitizaiton in both formations. Reservoir quality is as important as structure in determining well productivity in the Leach Field.

Carbonate reservoirs hold more than 50 % of Earth’s remaining conventional hydrocarbon. However, recovery from these reservoirs is notoriously difficult due to the complex and multiple scales of porosity. This heterogeneity is a function of both the depositional environment and of subsequent diagenetic processes. This thesis examines the processes that have controlled the reservoir quality of three Early Cretaceous carbonate oil fields (A, B, and C), in particular the role of deposition, diagenesis and the timing of oil charge in controlling final properties. Results are then used to help provide a theoretical basis for the modelling and prediction of reservoir quality and to improve the calibration of basin models. Field A and B are stacked and highly compartmentalised giant oil fields in the U.A.E. that are dominated by muddy fabrics and have a highly variable porosity (0- 35 %) and permeability (0.01-830 mD). Although the depositional environment strongly determines the location of reservoirs extensive diagenesis, through cementation and dissolution, has greatly modified the porosity and permeability of the reservoirs. Bulk δ13C values obtained from the main pore occluding calcite and dolomite cements are similar to the δ13C values of bulk micrite for the reservoir interval in which they are now present. This suggests that the cements that are occluding the pore space in each stacked reservoir are locally sourced and implies that each reservoir behaves as a relatively closed system during cement precipitation. In-situ (SIMS) δ18OVPDB values were obtained for the complete calcite cementation history of multiple reservoirs in Field A and B. The δ18OVPDB values for the first (oldest) calcite cement zone in each reservoir can be related to the global δ18OVPDB marine curve during the Hauterivian-Aptian and to million-year scale major climatic cooling events. The δ18OVPDB values for successive cement zones then progressively decrease, which is related to successive precipitation as a result of increasing temperature during burial in a relatively closed system. In-situ (SIMS) δ18OVPDB data together with oil inclusion occurrence suggest that initial oil charge (from the Dukhan Formation), at ~ 55-45 Million years ago (Mya) in Field A, reduced the cementation rate in the oil reservoir and preserved porosity. Whereas in the coeval aquifer a large volume of cement precipitated, after oil entered the oil reservoir, that greatly reduced porosity. Furthermore, the most reduced δ18OVPDB and mMg/mCa values are obtained from the cements in the shallowest (youngest) reservoirs, suggesting that cementation ceased in the deepest reservoirs first. This can be related to hydrocarbon stopping cementation or to the complete occlusion of effective porosity in the older reservoirs prior to the younger. After calcite and dolomite cementation ceased in the reservoirs of Field A and B a large scale dissolution event has been identified which significantly enhanced porosity. This dissolution event is then followed by the precipitation of authigenic kaolinite. Basin modelling reveals that this dissolution event is likely to be related to the thermal maturation of sedimentary organic matter that is present within local intraformational seals and to the migration of organic acids prior to a second hydrocarbon charging event (at ~ 45 Mya). The aluminium, that is required for the formation of kaolinite, would then have been brought into the system by complexing with the organic compounds derived from this maturation event. Field C is an oil field located in offshore Brazil. The field is dominated by high energy facies that have porosities which range from 5 % to 39 %, and permeabilities from 0.1 mD to 8.1 D. The depositional poro-perm properties of the oil reservoir have undergone little diagenetic alteration; however, the aquifer is extensively cemented and the porosity is much reduced. All the cements identified, by both petrography and stable isotopic analyses, in the oil reservoir are early and are thought to have formed from a pore fluid similar to, or slightly evolved from, Early Cretaceous seawater. Basin modelling suggests that oil may have entered the field slightly after deposition (at ~105 Mya) and led to the preservation of high porosities and permeabilities in the oil reservoir by stopping cementation.

This study presents an integrated evaluation of the burial and thermal history of an exhumed (uplifted and eroded) basin, and investigates the implications for the evolution of reservoir quality of the Ordovician sandstone in the Illizi Basin, Algeria. Complementary techniques including sonic compaction analysis, apatite fission track analysis, thermal maturity analysis, fluid inclusion microthermometry, and sandstone petrography are integrated to provide calibration for burial and thermal history models and diagenetic forward modelling, in order to predict variations in sandstone reservoir quality across the study area. The Illizi Basin has been structurally modified due to multiple exhumation events, including the uplift of the Hoggar Massif, which resulted in exhumation of the flanking sedimentary basins over a distance of 1,500 km from north to south. This study presents new apatite fission track data and analyses that constrain the onset of major exhumation in the Illizi Basin to the Eocene with exhumation magnitudes estimated to be 1-1.4 km in the study area. The study area contains a multi trillion cubic foot gas-condensate accumulation within a large four way dip closure. Hydrocarbon generation occurred during two main phases in the Carboniferous and the Mesozoic, but ceased during Cenozoic exhumation. Due to the Cenozoic tilting of the Illizi Basin in response to the uplift of the Hoggar Massif to the south, the present-day structural trap is interpreted to have formed after the main hydrocarbon generation phases. Therefore, alternative charging mechanisms of this post-peak burial trap are required and explored. In addition, new fluid inclusion data provides evidence of a significant fluid flow event within the Illizi basin, triggered by Cenozoic exhumation. Brines hosted present-day in the Ordovician sandstone in the study area are shown to be genetically linked to Triassic-Liassic evaporites deposited over 400 km to the north. Overpressure dissipation during exhumation is proposed to be a potential driving mechanism for the late stage remobilization of deep brines. A major pre-drill risk in many North African Paleozoic plays relates to sandstone reservoir quality, largely due to extensive quartz diagenesis. The Ordovician reservoir in the study area is characterised through petrography and core analysis, and the impact of burial and thermal history on the reservoir quality is investigated through diagenetic forward modelling. Results indicate that facies and variations in thermal history are a major control on preserving reservoir quality. This study demonstrates the importance of integrating the burial and thermal history, depositional facies and diagenetic history during predictive reservoir quality studies, particularly in exhumed basins where the burial and exhumation history may be complex, and present-day depth or geometry is not indicative of the past. Methodologies and implications from this study could be applied to exhumed basins in general.

In the next 20 years, the global demand for oil is forecast to grow by 0.7% every year, and the demand for natural gas will increase by 1.6% annually. But as we continue to produce oil and gas, the resources of our current oilfields are depleting. To meet the rising global energy demand, it is essential that we can keep discovering more petroleum resources in the future. The primary aim of this PhD project is to deepen our understanding of hydrocarbon reservoirs and enhance our ability to explore. The first project looked at the geological risks in hydrocarbon exploration. It reviewed and statistically analysed the data of 382 unsuccessful boreholes in the UK offshore area. The results suggest that the most significant risk for an exploration well is encountering a thin or absent target reservoir. This risk happened to 27 ± 4% of the past unsuccessful wells. The following most common risks are low-porosity reservoirs (22 ± 4% of all cases) and the lack of a closed trap (23 ± 4%). The probability of a target reservoir having a leaky caprock is 5 ± 2%. The study has calculated the probability of occurrence of all the geological risks in exploration, and this risk data can be applied to predict the potential geological risks in future exploration. One challenge in developing saline aquifers as CO2 storage reservoirs is the lack of subsurface data, unless a well has been drilled. Drawing on the experience of hydrocarbon exploration, a potential CO2 storage site identified on seismic profiles will be subject to many uncertainties, such as thin or low-porosity reservoirs, leaky seals, which are analogue to the geological risks of an undrilled hydrocarbon prospect. Since the workflow of locating CO2 storage reservoirs is similar to the exploration for hydrocarbon reservoirs, the risk data of hydrocarbon exploration wells can be applied to infer the geological risks of the exploration wells for CO2 storage reservoirs. Based on this assumption, the study of Chapter 3 estimated that the probability of a borehole encountering a reservoir suitable for CO2 storage is c. 41-57% (90% confidence interval). For reservoirs with stratigraphic traps within the UKCS, the probability of success is slightly lower, at 39 ± 10% (90% confidence). Chapter 4 studies the porosity and diagenetic process of the Middle Jurassic Pentland Formation in the North Sea. The analysis data come from 21 wells that drilled and cored the Pentland Formation. Petrographic data suggest the content of detrital illite is the most important factor affecting the porosity of the Pentland Sandstone - the porosities of the sandstones with more than 15% of illite (determined by point-count) are invariably low (< 10%). Quartz cement grows at an average rate of 2.3 %/km below the depth of 2km, and it is the main porosity occluding phase in the deep Pentland Sandstone. Petrographic data shows the clean, fine-grained sandstones contain the highest amount of quartz cement. Only 1-2 % of K-feldspar seems to have dissolved in the deep Pentland Sandstone (> 2 km), and petrographic data suggest that K-feldspar dissolution does not have any substantial influence on the sandstone porosity. There is no geochemical evidence for mass transfer between the sandstones and shales of the Pentland Formation. Chapter 5 investigates the high porosity of the Pentland Sandstone in the Kessog Field, Central North Sea. The upper part of the Kessog reservoir displays an anomalously high porosity (c. 25 %, helium porosity) that is 10 % higher than the porosity of other Pentland sandstones at the same depth (c. 15 %, 4.1 - 4.4 km). Petrographic data show these high porosities are predominantly primary porosity. The effects of sedimentary facies, grain coats, secondary porosity and overpressure on the formation of the high porosity are considered to be negligible in this case. Early hydrocarbon emplacement is the only explanation for the high porosity. In addition to less quartz cement, the high-porosity sandstones also contain more K-feldspar and less kaolin than the medium-porosity sandstones of the same field. This indicates that early hydrocarbon emplacement has also inhibited the replacement of K-feldspar. The last chapter studies the potential mass transfer of silica, aluminium, potassium, iron, magenesium and calcium at sandstone-shale contacts. The study samples include 18 groups of sandstones and shales that were collected from five oilfields in the North Sea. The interval space between the samples of each group varies from centimetres to meters. The research aim is to find evidence of mass transfer by studying the samples' variation of mineralogy and chemistry as a function of the distance to the nearest sandstone-shale contact. The sandstones are mostly turbidite sandstones, and the shales are Kimmeridge Clay shales. Petrographic, mineralogical and chemical data do not provide firm evidence for mass transfer within any group of the samples. The result indicates that the scale of mobility of silica, aluminium, potassium, iron, magenesium and calcium in the subsurface may be below the scale of detection of the study method, i.e. < 5 cm.

An enhanced coal-bed methane facility in Russell County, Virginia is targeting lower Pennsylvanian coals for CO2 storage, but the shallow sandstone units intercalated with the coals may also prove to be potential CO2 reservoirs, since the injection apparatus is already in place. Using samples from a continuous core in southwestern Virginia, this detailed review of the petrography and local volume of the Breathitt Formation sandstone units examines their diagenetic alterations in order to assess the units' reservoir quality. The high-frequency sequences of immature sandstones, heterolithics, shales and coals in Russell County represent deposits from the transverse fluvial facies association of a broad braided-fluvial drainage system in the central Appalachian Basin. The sandstone units within these sequences are laterally extensive, maintaining similar thickness and gamma ray signature across the study area. Lower Pennsylvanian sandstone units are consistently sublitharenite with a diagenetic mineral assemblage including siderite, chlorite, kaolinite, albite, illite, silica and calcite. Primary porosity is not preserved, but secondary porosity (5 ± 3.1 %) has developed at the expense of feldspars and unstable lithic fragments. Permeability assessments collected in Grimm (2010) measured impervious values (0.005-0.008mD) for the medium-coarse grained sublitharenites. At the temperatures and pressures present within these units, CO₂ is unlikely to react with either the primary or diagenetic mineralogy in a way that negatively impacts continued injection on human time scales. Low pore volume and permeability due to the timing of certain authigenic mineral emplacement are the main hindrance to reservoir quality. Lower Pennsylvanian sandstones are not viable potential reservoirs for carbon sequestration. / Master of Science

Master of Science / Department of Geology / Matthew Totten / Jackson County, Kansas is situated on the west side of the Forest City Basin, location of the first oil discovery west of the Mississippi River (KGS), Production in the area is predominately from the Viola Limestone, and a noticeable trend of oil fields has developed where the basin meets the Nemaha Anticline. Exploration has been sluggish, because of the lack of an exploration model. Production rates have varied widely from well to well, even when they are structurally equivalent. The goal of this study was to determine the factors controlling reservoir quality in the Ordovician-aged Viola Limestone so that a better exploration model could be developed. A two township area was studied to examine relationships between subsurface variations and production rates. In the absence of an available core through the Viola, drill cuttings were thin-sectioned and examined under a petrographic microscope to see the finer details of porosity, porosity type and dolomite crystal-size that are not visible under a binocular microscope. Production appears to be controlled by a combination of structural position and dolomite crystal size, which was controlled by secondary diagenesis in the freshwater-marine phreatic mixing zone. The best wells exhibited a Viola Limestone made up of 100% very coarsely crystalline, euhedral dolomite crystals. These wells occur on the east and southeast sides of present day anticlines, which I have interpreted to be paleo-highs that have been tilted to the east-southeast.

<p>This thesis constrains the distribution of diagenetic alterations and their impact on reservoir-quality and heterogeneity evolution pathways in relation to depositional environments and sequence stratigraphy (systems tracts and key sequence stratigraphic surfaces) of four selected paralic and shallow marine siliciclastic successions. </p><p>Typical eogenetic alterations encountered include the dissolution and kaolinitization of framework silicates, which are closely associated to shoreface facies of forced regressive systems tract (FRWST), lowstand systems tract (LST), upper part of the highstand systems tract (HST), and below the sequence boundary (SB). These alterations are attributed to incursion of meteoric water owing to rapid and considerable fall in the relative sea level. Extensive carbonate cementation is most evident below marine and maximum flooding surfaces (MFS), whereas dissolution of carbonate cement and detrital dolomite occur in LST, HST and below SB. Parameters controlling the patterns and texture (microcrystalline vs. poikilotopic) of calcite cement have been constrained within sequence stratigraphic framework of the sandstones. Coarse crystalline to poikilotopic calcite textures of meteoric water origin are thus closely linked to the FRWST, LST and upper part of the HST sandstones and occur mainly as stratabound concretions, whereas microcrystalline calcite, which was precipitated from marine porewaters, occurs as continuously cemented layers in the transgressive systems tract (TST) and lower part of the HST sandstones.</p><p>Eogenetic alterations impose, in turn, profound control on the distribution pattern of mesogenetic alterations, and hence on reservoir quality evolution (destruction vs. preservation) pathways of sandstones. Eogenetic infiltrated clays, which occur in the tidal estuarine TST and HST sandstones, have helped preserving porosity in deeply buried sandstone reservoirs (≈ 5 km) through inhibition of extensive cementation by quartz overgrowths. Other essential findings of this thesis include deciphering the control on the formation of authigenic illite and chlorite by ultra-thin (≤ 1 µm thick), grain-coating clay mineral substrate. </p>