The major challenge facing society in the 21st century is to improve the quality of life for all citizens in an egalitarian way, by providing sufficient food, shelter, energy and other resources for a healthy meaningful life, whilst at the same time decarbonizing anthropogenic activity to provide a safe global climate. This means limiting the temperature rise to below 2 C. Currently, spreading wealth and health across the globe is dependent on growing the GDP of all countries. This is driven by the use of energy, which until recently has mostly derived from fossil fuel, though a number of countries have shown a decoupling of GDP growth and greenhouse gas emissions from the energy sector through rapid increases in low carbon energy generation. Nevertheless, as low carbon energy technologies are implemented over the coming decades, fossil fuels will continue to have a vital role in providing energy to drive the global economy. Considering the current level of energy consumption and projected implementation rates of low carbon energy production, a considerable quantity of fossil fuels will still be used, and to avoid emissions of GHG, carbon capture and storage (CCS) on an industrial scale will be required. In addition, the IPCC estimate that large scale GHG removal from the atmosphere is required using technologies such as Bioenergy CCS to achieve climate safety. In this paper we estimate the amount of carbon dioxide that will have to be captured and stored, the storage volume and infrastructure required if we are to achieve both the energy consumption and GHG emission goals. By reference to the UK we conclude that the oil and gas production industry alone has the geological and engineering expertise and global reach to find the geological storage structures and build the facilities, pipelines and wells required. Here we consider why and how oil and gas companies will need to morph into hydrocarbon production and carbon dioxide storage enterprises, and thus be economically sustainable businesses in the long term, by diversifying in and developing this new industry.
Wells producing water are likely to develop deposits of inorganic scales. Scales can and do coat perforations, casing, production tubulars, valves, pumps, and downhole completion equipment, such as safety equipment and gas lift mandrels. If allowed to proceed, this scaling will limit production, eventually requiring abandonment of the well. Technology is available for removing scale from tubing, flowline, valving, and surface equipment, restoring at least some of the lost production level. Technology also exists for preventing the occurrence or reoccurrence of the scale, at least on a temporary basis. "Temporary" is generally 3 to 12 months per treatment with conventional inhibitor "squeeze" technology, increasing to 24 or 48 months with combined fracture/inhibition methods. As brine, oil, and/or gas proceed from the formation to the surface, pressure and temperature change and certain dissolved salts can precipitate. If a brine is injected into the formation to maintain pressure and sweep the oil to the producing wells, there will eventually be a commingling with the formation water. Many of these scaling processes can and do occur simultaneously.
Little is known about the nature and origin of microcrystalline quartz in sandstone reservoirs or mudstone reservoirs. We have utilized advanced analytical capabilities to improve our understanding of controls on microcrystalline quartz development in several examples where porosity is preserved in deeply buried sandstone reservoirs to understand the development in siliceous mudstones.
In this study, several advanced analytical techniques were used to evaluate the crystallographic and compositional controls on the formation of microcrystalline quartz. SEM/Cathodoluminescence (CL) imaging confirms that quartz overgrowths have a complex growth history. Previous workers (Kraishan et al. 2000) suggested that CL patterns in quartz cement are largely due to trace elements rather than defects and that aluminum varies consistently between each cement phase. Electron Backscatter Diffraction (EBSD) combined with Wavelength Dispersive Spectrometry (WDS) confirms that the complex banding visible in CL is not due to changes in crystallographic orientation but more likely variations in quartz composition associated with changes in pore fluid composition and/or reservoir conditions. Secondary Ion Mass Spectrometry (SIMS) analysis provides maps of ultra-trace element distribution that confirm that trace amounts of iron, manganese, and titanium can be used as proxies for defect density and temperature. Additionally, SIMS analysis provides oxygen isotope data providing insight into the initial reservoir conditions and temperature of formation of microcrystalline quartz in several formations.
Microcrystalline quartz in the form of replacement, micropore, and overgrowth cements is present in the Wolfcamp A in the southern Delaware Basin. The amount of cementation has an effect on the reservoir quality and appears to have an impact on the petrophysical properties. The siliceous mudstones are comprised predominantly of biogenic silica (sponge spicules, radiolarians, which are the silica sources for the authigenic microcrystalline quartz), detrital grains (quartz and feldspars), pyrite framboids, and organic matter.
Integrating the results from these advanced analytical techniques has helped us develop our understanding of the processes controlling the formation of quartz cement and improved our ability to reconstruct the reservoir diagenetic history of quartz growth leading to a proposed model for predicting porosity preservation in deep, hot sandstone reservoirs and the formation of microcrystalline quartz in siliceous mudstones. This is the first research to report on spatially resolved isotopic analysis of silica cements integrated into a petrographic framework and a proposed mechanism for microcrystalline quartz growth.
Operators are collecting abundant produced-water data that are often underused. Produced-water-composition data provide clues related to the geochemical reactions that are occurring in the subsurface. This information can be useful for monitoring interwell connectivity and predicting and managing oilfield scale resulting from brine supersaturation. Coupling thermodynamic calculations with produced-water analysis helps to identify geochemical effects that could affect oil recovery.
This work addresses the difference that reservoir temperature has on geochemical reactions in carbonate reservoirs by comparing data from two offshore fields and identifying the rock/brine and brine/brine reactions that will affect scale management.
Two seawater-flooded chalk fields located near each other were selected as candidates for comparison. The temperature of one field is 130°C, whereas for the other field, it is 90°C. Produced-water samples (a total of 6,800) from these two fields were analyzed, and the compositional trends were plotted to identify the deviation from conservative (nonreacting) behavior. The compositional trends were then grouped to identify if there were common features between wells. This analysis was complemented by 1D reactive-transport modeling to identify the reactions that would be consistent with the observed trends.
Two groups of wells were identified within each reservoir on the basis of the produced-brine compositional behavior. Each well group exhibits a distinct ion-trend behavior, especially with respect to barium, calcium, strontium, and magnesium concentrations—because these are divalent cations that are abundant in the formation brines. The breakthrough of sulfate, a component primarily introduced during seawater flooding, varies very significantly between the two groups in each case. In one grouping, the sulfate is barely retarded, and it breaks through at seawater fractions lower than 10%. In the other grouping, however, sulfate does not break through until the seawater fraction in the produced brine exceeds 75%. This retardation of sulfate occurs most strongly in the hotter reservoir, and this might be attributed to the lower solubility of the calcium sulfate mineral anhydrite at a higher temperature. The retardation of sulfate then means that barium is produced at higher concentrations because barite precipitation in the reservoir is thus restricted, caused by sulfate being the limiting ion. However, some sulfate stripping does occur in the cooler reservoir, despite the higher solubility of anhydrite. Furthermore, in all cases, magnesium is retarded, with some groupings exhibiting the complete stripping of magnesium from the injected seawater.
The magnesium-stripping behavior is reproduced in the reactive-transport models when calcium- and magnesium-replacement reactions are allowed. This phenomenon has been observed elsewhere in coreflood experiments, and it also contributes to the sulfate stripping through the promotion of anhydrite precipitation within the rock. This process, which is beneficial in terms of reducing the scale risk, is more pronounced at higher temperatures. Therefore, higher-temperature chalk reservoirs might act as natural sulfate-reduction plants, reducing scaling, souring risks and, thus, operating costs of the fields.
Hu, Yisheng (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Mackay, Eric (Heriot-Watt University) | Vazquez, Oscar (Heriot Watt University ) | Ishkov, Oleg (Heriot-Watt University)
In waterflooded reservoirs under active scale management, produced-water samples are routinely collected and analyzed, yielding information on the evolving variations in chemical composition. These produced-water chemical-composition data contain clues as to the fluid/fluid and fluid/rock interactions occurring in the subsurface, and are used to inform scale-management programs designed to minimize damage and enable improved recovery.
In this interdisciplinary paper, the analyses of produced-water compositional data from the Miller Field are presented to investigate possible geochemical reactions taking place within the reservoir. The 1D and 2D theoretical model has been developed to test the modeling of barium sulfate precipitation implemented in the streamline simulator FrontSim. A completely 3D streamline simulation study for the Miller Field is presented to evaluate brine flow and mixing processes occurring in the reservoir by use of an available history-matched streamline reservoir-simulation model integrated with produced-water chemical data. Conservative natural tracers were added to the modeled injection water (IW), and then the displacement of IW and the behaviors of the produced water in two given production wells were studied further. In addition, the connectivity between producers and injectors was investigated on the basis of the comparison of production behavior calculated by the reservoir model with produced-water chemical data. Finally, a simplified model of barite-scale precipitation was included in the streamline simulation, and the calculation results with and without considering barite precipitation were compared with the observed produced-water chemical data. The streamline simulation model assumes scale deposition is possible everywhere in the formation, whereas, in reality, the near-production-well zones were generally protected by squeezed scale inhibitor, and, thus, the discrepancies between modeled and observed barium concentrations at these two given wells diagnose the effectiveness of the chemical treatments to prevent scale formation.
The production experience from the Statfjord Field on the Norwegian Continental Shelf is one of the greatest adventures in modern oil and gas history. After achieving very high oil recovery factor using a predominant drainage strategy with pressure maintenance by water and gas injection, the drainage strategy in the field has since 2007/2008 been changed to reservoir depressurization.
Prior to depressurization start-up, the field has produced about 652 million Sm3 (4.1 billion bbl) oil and 187 billion Sm3 gas. Currently, the field is producing at an oil rate of approximately 5 300 Sm3/d and a gas rate of about 11 million Sm3/d. Estimates indicate that successful implementation of the new drainage strategy will continue and lead to an ultimate oil recovery of higher than 67% and a significant additional gas production, as a result of the depressurization process. In addition, the field life will be extended from 2009 to 2025, and this will contribute to lifetime extension of the attached satellite fields.
The main purpose of this paper is to provide a description of the multidisciplinary approach used for evaluation and planning of the Statfjord Late Life (SFLL) with reservoir depressurization, share learnings from depressurization start-up and address challenges, uncertainties and opportunities.
Imbibition only relative permeability is commonly used to model water influx in water-drive gas reservoirs, however an aquifer is rarely strong enough to maintain constant pressure support. Continued pressure depletion in the part of the reservoir swept with watercauses expansion and remobilisation of trapped gas behind the waterfront. This paper presents a reservoir simulation study on modelling the expansion and remobilisation of trapped gas due to pressure depletion as secondary drainage flow using relative permeability hysteresis.
Previous studies in literature on relative permeability show the secondary drainage curve during blowdown is below the primary imbibition curve. This is based on field cases and core experimental studies, which establish the existence of a gas remobilisation threshold above residual saturation to reconnect the gas phase. Commonly used hysteresis models by
The conclusion of this study is that the standard formalisms used to model relative permeability hysteresis (Killough, Carlson) should not be used to model trapped gas remobilisation due to blowdown as they do not incorporate a gas remobilisation threshold and a secondary drainage curve underlying the primary imbibition curve. By assuming no mobility threshold above residual gas saturation, the total recovery of residual gas will be overestimated. Instead, by adopting the ODD3P hysteresis model, gas production will be lower and water production higher due to the correct use of secondary-drainage relative permeability curves in a gas reservoir invaded by water. This will lead to a significant improvement in results from reservoir simulation and the subsequentevaluation of trapped gas recovery.
The expansion and remobilisation of residual or trapped gas saturations has a major impact on the prediction and/or matching of production and pressure response from a reservoir. This study intends to understand these impacts and serve as a preliminary guideline in modelling trapped gas expansion and remobilisation as secondary drainage flow, which is applicable to many water-drive gas reservoirs.
Duvivier, G. (BP) | Al-Naqi, M. (Kuwait Oil Company) | Ameen, A. A. (Kuwait Oil Company) | Al-Enizi, N. (Kuwait Oil Company) | Al-Shati, A. (Kuwait Oil Company) | Rajan, S. (Kuwait Oil Company) | Clark, R. A. (BP)
Stimulating water injectors successfully is critical to any waterflood and to successfully stimulate wells it is important to understand what technology works and what does not. An effective method of evaluating stimulation efficency is by monitoring the long term performance of the water injectors and how injection pressure and temperature varies over time. The primary source of injection water for Greater Burgan is produced water, which is collected through an extensive gathering system. Because this gathering system is so large, the resulting fluids drop to atmospheric temperature before they are available for injection. Average daily temperatures in Kuwait vary by more than 60 F annually. All of the injection wells are injecting above fracturing pressures and these temperature swings impact the size of fractures leading to observed changes in rate of up to 40%. These effects must be understood to evaluate the impact of injection fluid temperature upon stimulation. Monitoring this surface injection data has allowed the team to select a successful stimulation method for the injectors and added significantly to the field's injection rate.
A Residual Oil Zone (ROZ) is a naturally waterflooded reservoir at residual or near residual oil saturation, technically recoverable only through unconventional methods. The development of ROZs is extensively pursued in the Texas Permian Basin. Several successful ROZ CO2 Enhanced Oil Recovery (CO2-EOR) projects indicate enormous resource potential for these emerging oil plays. Another approach, called Depressurizing the Upper ROZ (DUROZ), was recently proposed and is currently under extensive investigation. This study offers a mechanistic understanding of DUROZ and investigates the factors affecting its viability and performance.
DUROZ refers to the progressive reduction of reservoir pressure through the withdrawal of large volumes of water from a horizontal well in the upper section of ROZ. When reservoir pressure falls below the saturation pressure, gas bubbles liberate from capillary-trapped oil and develop into a continuous gas phase. Consequently, the oil phase may also become mobile beyond waterflood residual oil saturation. We history-match the oil and water production from two DUROZ producers in the upper San Andres dolomite using a tuned reservoir simulation model. To properly capture the rock and fluid interaction, the relative permeability data are tuned with the experimental core data from the San Andres ROZ. Extensive experimental studies have highlighted a substantial difference between relative permeabilities measured under external drive and solution gas drive. We define two sets of relative permeabilities: an original set based on the external drive experiments and the relevant correlations, and a modified set for modeling production under solution gas drive.
Our results show that even for the most optimistic relative permeabilities, the reservoir initial oil saturation should be at least 20% above the residual oil saturation in order to match the oil cuts of the reported DUROZ producers. This shows inconsistencies in use of the term "residual oil" zone by the industry in the Permian Basin. In other words, although DUROZ shows potential for production beyond waterflood residual oil saturation, the documented cases are unlikely to be true ROZ producers and are more likely completed in the Transition Zone (TZ) or near-ROZ. Finally, a discussion on the operational risks and technical considerations associated with DUROZ, including water disposal, infrastructure and facility requirements, and modeling limitations, is presented.