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In this paper, the well under consideration is a horizontal oil production well located in the northern part of the Mittelplate oilfield, Germany’s largest oilfield. The well production started in July 2017 via electrical submersible pump (ESP) at an average initial liquid rate of 115 m³/d with no water production. One year after production start, the ESP performance decreased resulting to a significant drop in oil production. Since then, the well has been operated as an intermittent producer to prevent severe damages at the ESP. The objective of this study is to describe the different measures carried out to restore well productivity and present results achieved. Based on previous field experiences, it was assumed that the ESP performance reduction was due to asphaltene precipitations in the pump. The well was therefore regularly treated with aromatic washouts to dissolve asphaltene depositions. An attempt to achieve a more suitable and cost-effective alternative to the aromatic washouts was tested with asphaltene dispersant injection through the chemical injection line (CIL) of the well. After several months of field test, the aromatic washouts as well as dispersant injection could not improve the well performance. An additional measure to increase well productivity was to support the reservoir pressure in the northern part of the reservoir. This was implemented in late 2018 whereby, a nearby production well was converted into an injection well with a steady increase in injection rate. Increased bottom hole flowing pressures are being observed currently at production wells. However, it is challenging to evaluate the effect of the injection at the target well without downhole pressure data. At present, the well is still operated as an intermittent producer with prolonged downtime periods allowing stronger pressure buildups at the perforations. It is planned to further increase injection rate to enhance pressure support in the region. An interwell water tracer campaign, currently in design for the field, is aimed to determine water breakthrough times and sources and establish reservoir flow patterns within the reservoir.
Reservoir compaction in depleting gas fields can cause seismicity, as has been observed in a dozen countries (Foulger
For a few gas reservoirs, the evolution of potential fault slippage is simulated using the commonly adopted Mohr-Coulomb failure criterion. This shows that fault criticality is expected for reservoirs that showed seismic as well as non-seismic behavior. Apparently, some characteristic property is missing to explain the difference in behavior.
Using published pressure histories for seismically active gas fields, the relation is shown between seismic magnitude and relative depletion. It appears that in many cases, the first induced earthquake is relatively strong which suggests substantial cohesion of the faults. It is plausible from the geological history that in non-seismic regions, fault cohesion is larger, so that slippage is inhibited.
Geothermal energy refers to the heat stored in the subsurface that can be extracted by producing the hot fluids (water and/or steam) in contact with the hot formation. A major issue that may restrict the extraction of geothermal energy is precipitation of mineral scales which can occur within the reservoir, inside the wellbore, or surface facilities. The objective of this paper is to find the most efficient scale treatment strategy to prevent mineral scaling.
Continuous injection of chemical scale inhibitor (SI) downhole in the production well, is the most common method to prevent mineral scale in geothermal plants. This method although effective does not protect the near-wellbore area, where the highest pressure drop is expected. To address this issue, two methods will be studied, bullheading the production well with SI, commonly known as squeeze treatment, and injecting SI in the injection well. Optimum designs for both methods were identified considering different levels of SI adsorption, and also permeability variation in fractured and non-fractured formations.
As expected, the volume of SI required in continuous injection in producer was lower than the other two methods. However, in cases where the highest risk of precipitation is in the near-wellbore area or it is below the continuous injection point, it is necessary to apply one of the suggested methods. While the squeeze treatment protects only the formation around the producer well, treatments deployed in injector wells will protect the whole system and this extra protection may offset the extra volume of chemical necessary. The application of SI in injector well was studied in both continuous and batch mode with different injection frequencies. It was shown in continuous injection that even though less SI volume is used, the SI breakthrough time in producer can be so long that a series of squeeze treatments might be required to protect the well. The simulation results showed that in high adsorption formations, squeeze treatment is more efficient than deploying SI in the injector well. However, in cases of low adsorption and fractured reservoirs, the scenario commonly found in geothermal plants, SI injection at the injector is more optimal.
Two different scale treatment methodologies were studied in geothermal wells, including squeeze treatment in producer and SI injection in the injector and the results were compared with the continuous SI injection in producer, which is the most current treatment in geothermal wells. It was illustrated in fractured geothermal reservoirs with relatively low levels of adsorption, that SI injection in the injector is the most optimum treatment that can effectively protect the whole plant from scaling.
Seright, Randall S. (New Mexico Institute of Mining and Technology) | Wavrik, Kathryn E. (New Mexico Institute of Mining and Technology) | Zhang, Guoyin (New Mexico Institute of Mining and Technology) | AlSofi, Abdulkareem M. (Saudi Aramco)
The goal of this work was to identify viable polymers for use in the polymer flooding of high-temperature carbonate reservoirs with hard, saline brines. This study extensively examined recent enhanced-oil-recovery (EOR) polymers for stability, including new 2-acrylamido-tertbutylsulfonic acid (ATBS) polymers with a high degree of polymerization, scleroglucan, n-vinylpyrrolidone (NVP) -based polymers, and hydrophobic associative polymers. For each polymer, stability experiments were performed over a 2-year period under oxygen-free conditions (less than 1 ppb) at various temperatures up to 180°C in brines with total dissolved solids (TDS) ranging from 0.69 to 24.4%, including divalent cations from 0.034 to 2.16%. Use of the Arrhenius analysis was a novel feature of this work. This rarely used method allows a relatively rapid assessment of the long-term stability of EOR polymers. Rather than wait years or decades for results from conventional stability studies at the reservoir temperature, reliable estimates of the time-temperature stability relations were obtained within 2 years. Arrhenius analysis was used to project polymer-viscosity half-lives at the target reservoir temperature of 99°C. The analysis suggests that a set of ATBS polymers will exhibit a viscosity half-life over 5 years at 120°C and over 50 years at 99°C, representing a novel finding of this work and a major advance for extending polymer flooding to higher temperatures.
For five polymers that showed potential for application at higher temperatures, corefloods were performed under anaerobic conditions. Another novel feature of this work was that anaerobic floods were performed without using chemical oxygen scavengers, chemical stabilizing packages, or chelating agents (that are feared to alter rock properties). Using carbonate cores and representative conditions, corefloods were performed to evaluate polymer retention, rheology in porous media, susceptibility to mechanical degradation, and the residual resistance factor for each of the polymers at 99°C.
Summary Fracture closure and proppant settling are two fully coupled processes during both shut-in and production. Proppant distribution greatly affects the residual fracture width and conductivity evolution, whereas fracture closure might limit proppant settling and force the proppant to crush or embed into the rock. Modeling fracture closure with proppant settling and embedment is challenging because of the multiple coupled physical processes involved, large timescale differences, and extreme nonlinearity in the coupling of the processes. Conventional fracture-closure models either use simplified analytical estimates of the stress-dependent permeability of the reservoir or explicitly calculate the fracture width using empirical relationships, without considering the effect of fluid leakoff and dynamic changes in the proppant distribution in the fracture. In this work, we use a novel fully implicitly coupled fracturing/reservoir simulator to study fracture closure and proppant-settling/embedment processes during shut-in and production. During shut-in, a modified Barton-Bandis (Bandis et al. 1983) formula is used to describe the nonlinear relationship between the contact force and the residual fracture aperture considering the dynamic proppant spatial distribution and rock heterogeneity. During production, fracture conductivity is evaluated according to proppant distribution and further fracture closure caused by proppant crushing and embedment. A Newton-Raphson method is applied to solve the coupled system of equations. Results from the simulations clearly show that typical periods of shut-in after fracturing lead to the formation of proppant banks at the bottom of the fracture in low-permeability, low-leakoff formations. This can lead to near-wellbore tortuosity and poor connectivity between the wellbore and the hydraulic-fracture network. Stress-dependent permeability, likely induced by induced unpropped fractures, is shown to be essential to obtain reasonable values of leakoff and to history match production trends. Proppant embedment is shown to be an important factor controlling production-decline rates in clay-rich shales.
Lu, Cong (Southwest Petroleum University) | Luo, Yang (Southwest Petroleum University and SINOPEC Southwest Oil and Gas Company) | Li, Junfeng (China National Petroleum Corporation) | Chen, Chi (Southwest Petroleum University) | Xiao, Yongjun (Sichuan Changning Gas Development Company) | Liu, Wang (Sichuan Changning Gas Development Company) | Lu, Hongguang (Huayou Group Company Oilfied Chemistry Company of Southwest) | Guo, Jianchun (Southwest Petroleum University)
Temporary plugging during fracturing operations has become an efficient method to create a complex fracture network in tight reservoirs with natural fractures (NFs). Accurate prediction of the network-propagation process plays a critical role in plugging- and fracturing-parameter optimization. In this paper, the interaction between one single hydraulic fracture (HF) within a temporary plugging segment and multiple NFs was simulated using a complex fracture-development model. A new opening criterion for an NF penetrated by a nonorthogonal HF already was implemented to identify the dominant propagation direction of a HF under plugging conditions. Fracture displacements and the induced-stress field were determined by the 3D displacement-discontinuity method, and the Gauss-Jordan and Levenberg-Marquardt methods were combined to handle the coupling between rock mechanics and fluid flow numerically. Numerical results demonstrate that the opening and development of an NF are mainly dominated by its approaching angle and relative location. For a certain NF crossed by an HF within the plugging segment, the HF tends to propagate along the NF branch inclined in the main HF direction. The farther the interaction position is away from the HF tip, the easier the NF with an approaching angle less than 30° or larger than 150° can be open, and the outcome will be opposite if the approaching angle is larger than 45° or less than 135°. Higher approaching angle and plugging strength is necessary for expanding the position scope of NF that can be opened around HF. Under the effect of plugging, fluid pressure in the HF plummets at the beginning of the NF opening and keeps decreasing until the NF extends for a certain distance or encounters secondary NFs. Fluid-pressure drop occurs mainly in the unturned NF, together with the width of unturned NF being significantly lower than that of the turned NF and HF. Sensitivity analysis shows that the main factors, such as geometry, aperture profile, and fluid-pressure distribution, affecting the network progress under the temporary plugging conditions are the horizontal differential stress, NF position, approaching angle, plugging time, and plugging-segment length. The simulation results provide critical insight into complex fracture-propagation progress under temporary plugging conditions, which should serve as guidelines for well choosing and plugging optimization in temporary plugging fracturing.
An integrated workflow was developed to support the waterflood design of an onshore field in Brazil. This giant mature field has more than 2000 drilled wells with a long production history that has been declining. The objective of the study was then to improve the recovery factor for that field, as well as generate an integrated workflow that could be adapted and applied to other similar fields.
The workflow comprised four main stages. It started with the gathering and treatment of all relevant input data, such as fluid and rock lab data, well logs, and production historical data, to construct a simulation model fit for streamline simulation. A sensitivity study was then conducted analysing the uncertain parameters that had most impact on the simulation results, followed by an uncertainty analysis. Best candidates from this second phase were then used as base cases for the history match process. Eventually, the waterflood design was analysed and optimized considering three main aspects: water allocation, workovers and well placement.
The water allocation was first optimized and a reduction of about a fifth of injected water was achieved while maintaining the level of oil production. This was performed using the Pattern Flood Management algorithm (PFM), available in the streamline simulator. This module performed water re-allocation based on bundle efficiency ranking. Different control criteria and optimization parameters were experimented to reach an optimal result. The potential for workovers and, in particular conversion of producers into injectors, was then evaluated but didn't provide a significant improvement in results. Eventually it was considered an increase in well count, looking into optimized well placement based on sweet spot maps and streamline analysis. These solutions were finally combined in an iterative process to ensure interactive effects were accounted for and all aspects jointly optimized and led to an expected increase in oil production of about 5%.
This study generated an integrated workflow bridging a long production history with a full-field simulation model for this large mature field. Also, using streamline simulation for such waterflood design optimization appeared fit for purpose. First, it brought an improved efficiency as the workflow required running several scenarios. Second, it allowed to not only consider traditional tools to improve recovery factor but also solutions making use of the understanding of model connectivity the streamline simulator provides.
A major Malaysian matured offshore oilfield which is currently under waterflooding has been seen declining in production in recent years. Among various enhanced oil recovery (EOR) techniques evaluated, this field appears to be amenable to chemical EOR implementation. Chemical EOR project requires high capital and operating expenditure (CAPEX and OPEX) and often involve complex logistical and operational challenges in an offshore environment. A comprehensive study and technical road map plan from laboratory to pilot and then to full field reservoir simulation model has been established to reduce the project risks prior to field-scale chemical EOR implementation.
For this study, detailed EOR screening and ranking evolution is conducted and confirmed that chemical EOR is ranked high among other EOR techniques and stands for better chance of success techno-economically. Subsequently, all the relevant field examinations to verify the incremental oil recovery from chemical EOR including extensive laboratory experiments such as fluid-fluid and fluid-rock evaluations and pilot tests by single well chemical tracer method were designed and implemented.
This paper mainly presents the challenges and the strategies to build a realistic full field chemical EOR numerical simulation model (using CMG's STARS), which include history matching and waterflooding optimization process stages. The work has been carried out to address the best practice workflow for chemical EOR simulation, lessons learned from how to properly prepare and incorporate the chemical input data, identify uncertainties relate to project risks and minimize or mitigate the impact of risks to the project economics.
Numerical simulation was utilized along with assisted optimization methods that combine experimental design and artificial intelligence (AI) techniques (using CMG's CMOST) to determine injection chemical concentration and chemical slug size for optimal oil recovery factor and project net present value (NPV). Sensitivity studies were also performed with the reservoir simulation models to determine the impact of effects such as residual oil saturation (Sor) reduction, chemical loss through adsorption, dilution effects on capillary number, salinity and viscosity effects, cooling effects, chemical reactions, among others. The study results show that chemical EOR injection is a technically feasible and economically viable option for this oilfield from subsurface, incremental oil recovery, and facilities stand points. Furthermore, the results of this risk assessment will facilitate and expedite the full field project execution and investment plan in future.
Liu, Wenting (Federal Institute for Geosciences and Natural Resources(BGR)) | Eickemeier, Ralf (Federal Institute for Geosciences and Natural Resources(BGR)) | Fahland, Sandra (Federal Institute for Geosciences and Natural Resources(BGR))
ABSTRACT: This study focuses on numerical 3D modeling to analyze the long-term barrier integrity of bedded salt under consideration of thermal loading caused by heat-generating radioactive waste disposal. As a basis for the model calculation, a literature review of appropriate constitutive models and material parameters of homogenous zones was conducted. Thermo-mechanical coupled calculations have been carried out using large-scale 3D models. Due to the thermal loading of HLW waste, the temperature of rock mass rises. Thermally induced deformation of the formation leads to uplift of the rock above the repository. Integrity is assessed against a dilatancy criterion and a fluid pressure criterion. Calculations indicate that barrier integrity of the bedded salt is locally and temporarily violated. However, a large region of the salt barrier is not affected. At any time, at least 300 m of intact salt barrier remains, and no continuous migration paths occur.
With the restart of site selection for a repository for heat-generating radioactive waste in Germany (StandAG 2017, 2013), all potential host rocks (salt, claystone and crystalline rocks) are being evaluated for suitability as a nuclear-waste repository for a safety demonstration period of one million years. Salt formations are considered as potential hosts, due to their high thermal conductivity, favorable mechanical properties and impermeability for gases and fluids. So far, bedded salt has not been as intensely investigated as domal formations in Germany. Since 2015, investigation of bedded salt as a host rock has been launched in the framework of the R&D project KOSINA (Bollingerfehr et al. 2018). Concepts for a generic repository for heat-generating waste in bedded salt formations in Germany and safety and demonstration concepts have been investigated in this project, which includes partner organizations of BGE TECHNOLOGY GmbH, Gesellschaft für Anlagen- und Reaktorsicherheit (GRS) gGmbH, Institute of Geomechanics GmbH (IfG) and Federal Institute for Geosciences and Natural Resources (BGR). The analyses of geomechanical integrity of the bedded salt have been carried out both by IfG and BGR using different methods of modeling and constitutive equations.
Teatini, P. (University of Padova) | Ferronato, M. (University of Padova) | Franceschini, A. (University of Padova) | Frigo, M. (University of Padova) | Janna, C. (University of Padova) | Zoccarato, C. (University of Padova) | Isotton, G. (M3E Srl)
ABSTRACT: Underground gas storage (UGS) is a practice that is becoming widely implemented to cope with seasonal peaks of gas consumption. When the target reservoir is located in a faulted basin, a major safety issue concerns the reactivation of pre-existing faults, possibly inducing (micro-) seismicity. Faults are reactivated when the shear stress exceeds the limiting acceptable strength. It has been observed in The Netherlands that this occurrence can happen “unexpectedly” during the life of a UGS reservoir, i.e. when the actual stress regime is not expected to reach the failure condition. A numerical analysis by a 3D FE-IE elasto-plastic geomechanical simulator has been carried out to cast light in this respect, by investigating the mechanisms and the critical factors that can be responsible for a fault reactivation during the various stages of UGS in reservoirs located in the Rotliegend formation. The model outcomes show that the settings (in terms of reservoir and fault geometry, geomechanical parameters, and pressure change distribution) more prone to fault activation during primary production are also the most critical ones during cushion gas injection and UGS cycles.
Because of the importance of natural gas for energy production, the interest to develop underground gas storage (UGS) projects is continuously increasing worldwide. In May 2015, 268 UGS facilities existed or were planned in Europe and over 400 in the USA. UGS is traditionally used to ensure a relatively smooth delivery from gas reservoirs to the gas consumption pattern dictated by daily and seasonal oscillations. The hazard and risk associated with subsurface gas storage are a recurrent issue whenever a new UGS is planned. Many different aspects are involved, such as formation integrity, health and safety as related to public perception, economic risk, and environmental impacts. Among the latter, the geomechanical effects induced by seasonal gas injection and withdrawal may play a very important role.