Residual oil zones (ROZs) are defined as those zones where oil is swept over geologic time period (natural flush) and exists at residual saturation. ROZs are increasingly being commercially exploited using CO2-enhanced oil recovery (EOR) (in Permian Basin). In this study, CO2 storage potential, long-term CO2 fate and oil recovery potential in ROZs are characterized. We use numerical simulations of CO2 injection with a reservoir model based on data from the Permian Basin. The changes of CO2 storage capacity and potential oil recovery with amount of CO2 injection are investigated. The effects of different well patterns (five-spot and line drive) and well spacing on fraction of CO2 retained in reservoir and cumulative oil production are also investigated. Furthermore, the effect of different CO2 injection modes, i.e., continuous CO2 injection and water-alternating-gas injection (WAG), on the CO2 storage and EOR potential are evaluated and compared. After the preliminary characterization of CO2 storage and EOR potential in ROZs, we next develop empirical models that can be used for estimating the CO2 storage capacity and oil production potential for different ROZs. A supervised machine learning algorithm, Multivariate Adaptive Regression Splines (MARS, (Jamali et al.)) is used for developing the empirical models.
Results show that CO2 retention efficiency and oil recovery vary non-linearly with amount of CO2 injected. It is observed that long-term CO2 fate is a function of CO2 injection amount and significant fraction of reservoir CO2 resides in hydrocarbon phase. Five-spot well pattern results in more oil production and larger amount of CO2 retained in reservoir than line-drive well pattern. During the investigation of well spacing, we observe that less number of wells actually results in higher CO2 retention and oil recovery, and less number of wells can also result in less probability of wellbore leakage. In comparison of WAG and continuous CO2 injection modes, it is observed that WAG injection has higher fraction of injected CO2 retained in reservoir, but with slightly lower cumulative oil production. In the study of empirical models for the capacity assessment of CO2 storage and EOR, results show that MARS can generate high-fidelity empirical models that can be used to predict the cumulative CO2 storage capacity and cumulative oil production for different ROZs.
A private company based in Houston, Texas, collects and analyzes water source, logistics, recycling and disposal data for the upstream oil and gas industry. The company recently started applying machine learning methods to satellite imagery of the Permian Basin to identify frac water impoundments and facilitate water trading between operators. Freshwater frac pond locations in Texas are not available from any public record data source, so identification of their locations and other characteristics through satellite imagery analysis may reveal new insights about energy industry operations. The company partnered with the University of Texas Bureau of Economic Geology to analyze eleven quarters of historical central Midland Basin satellite imagery, a time series beginning in January 2016, to test correlations between frac ponds and hydraulic fracturing activity. The study identified a significant positive correlation between total frac pond surface area in the satellite imagery and IHS data on aggregate water use for hydraulic fracturing in the Midland Basin area studied. This study also found a striking 76% increase in average frac pond volume over the 27-month study period, and found that the percentage of available frac pond water injected for hydraulic fracturing grew from 11% to 20% from January 2016 to July 2017. The most notable observation from this study, however, may be that the permit-based (IHS) control data appeared to lose integrity between six and ten months prior to the study date, while the satellite-derived data appeared to maintain integrity right up to the study date. As of May 2018, the IHS data shows water injected for hydraulic fracturing in the Midland Basin dropping 90% beginning in July 2017 because of absence of complete data. The satellite data, however, shows steady growth in total frac water supply throughout that period. This timeliness-of-data comparison was not the purpose of the study, but the study conclusions were limited because reliable control data could not be obtained for the time period of about ten months prior to the study date. This suggests that oilfield market research could be improved through the use of more satellite imagery analytics versus public permit and industy reported data.
Rojas, Pedro A. Romero (Weatherford International Ltd.) | Bacciarelli, Mark (Weatherford International Ltd.) | Elkington, Peter (Weatherford International Ltd.) | Shokeir, Ramez (Occidental Petroleum) | Newsham, Kent (Occidental Petroleum) | Pumphrey, Joe (Logicom) | Lopez, Egleé (Logicom) | Morys, Marian (Petromar Technologies) | Avdeev, Dmitry (Petromar Technologies)
Alternating conventional and unconventional reservoir layers in the Permian Basin challenge the acquisition, processing, and interpretation of water saturation (Sw) using nuclear magnetic resonance (NMR) log data. A new-generation NMR wireline tool addresses these challenges using a specially designed conventional-unconventional activation sequence to enable construction of optimized maps of Longitudinal–Transversal Relaxation times (T1-T2 maps) at regular depth intervals.
T1-T2 maps are used to compute level-by-level Sw based on a multicomponent fluid model with appropriate statistical properties. Each spot in the T1-T2 space represents a fluid component from which a volume fraction is calculated. Integrating the volume fractions gives the total porosity. Because of the diverse relaxation mechanisms in the conventional and unconventional layers, oil spot positions with T1/T2 values greater than two reflect either viscosity (for bulk relaxation) or pore-size distribution (for surface/volume relaxation). Water tends to be close to the 1:1 T1/T2 diagonal line with T1/T2 values less than two. Low permeability means that mud-filtrate invasion does not appear on the T1-T2 maps.
NMR porosity matched expected values based on core and density-neutron log analysis. NMR fluid-typing-derived Sw—including clay bound water (CBW), capillary bound water (BVI), and free water—matched values from tested intervals. Results are in good agreement with reference values from production and core data within an uncertainty of one standard deviation. The resolution of fluid components in intervals where the components overlap can be enhanced by changes in the inversion parameters and map-grid dimensions.
This methodology for conventional-unconventional data acquisition followed by a multimodel approach for fluid typing will be applied to other wells. It enables a more accurate assessment of water saturation, especially when intercalated layers of conventional and unconventional reservoirs are present.
Pressure transient testing is a method to obtain information on reservoir characteristics. Thin shale layers isolating productive intervals in a reservoir have important implications for reservoir development and EOR strategies. In addition, weaknesses in caprocks overlying injection intervals may adversely affect the safety of fluid injection approaches including gas storage, waste water disposal, and CO2 geological storage. Even low permeability of a caprock overlying the injection zone can be very important by allowing for pressure dissipation out of the reservoir. In this work, we apply harmonic pressure testing method to characterize a caprock overlying a given injection zone. The diffusivity equations are written and solved in frequency domain for system of injection layer and above zone with the low permeability caprock in between. A vertical well is perforated in the middle of the injection layer. A periodic flow rate pulse is disseminated from the injection well. The pressure pulses traveled through the caprock are observed in the above zone. The hydraulic characteristics of the low permeability caprock are estimated applying the analytical solution based on the above zone pressure amplitude. The caprock diffusivity is found to be in acceptable agreement with the true value. It is shown that the harmonic pulse testing is useful to characterize the intra/inter reservoir low permeability layers (caprocks).
Molecular diffusion plays a dominant role in various reservoir processes, especially in the absence of convective mixing. In general, gas diffusion in oils depend on several factors such as pressure, temperature, oil viscosity and gas-to-oil ratio (GOR). Out of these factors, GOR effects/live oil compositional changes on diffusivity is rare or not available in literature. The current work fills this gap and present the experimental observations on the effect of GOR on gas diffusivity in reservoir fluid systems.
Synthetic live oils were created by combining stock tank oil (STO) and methane in various ratios. Constant composition Expansion (CCE) experiments were performed with these oils to obtain their bubble points and liquid-densities in relation to GOR. Methane diffusivity in these oils were obtained from pressure-decay tests at high temperature/pressure conditions. The diffusion and solubility parameters were estimated from pressure-decay data using the diffusion model and integral-based linear regression presented in the previous works ([
In this work, we have experimentally investigated the effect of GOR on methane diffusivity in oils at high temperature/pressure conditions using pressure-decay tests. In particular,
We present experimental data for bubble-points and liquid density of synthetic oils having various GOR-values. For the range of GOR's considered, these measurements show that the bubble-point pressure increases linearly with GOR.
Late transient solution of the pressure-decay model was utilized to obtain diffusivity parameters by regressing against experimental data. It is found that as GOR-value increases (i.e. when oil becomes lighter), the diffusivity-value increases, which is in accordance with Stokes-Einstein relation.
Most importantly, an empirical correlation is developed based on limited data set to describe the variation in diffusivity values with GOR. This can be very important when experimental data for the STO is available but not for the live oils. It can also be extremely useful in gas injection processes where amount of gas dissolved in the oil varies leading to variations in diffusivity as well.
Horizontal drilling and multistage hydraulic fracturing applied in tight reservoirs in North America over the past decade and economic productivity attained by creating large fracture surface area to contact the reservoir and create the conductive pathway for the flow of hydrocarbon into the wellbore. Perforation cluster spacing and fracture stagging are keys to successful hydraulic fracturing treatment for horizontal wells. The early focus of the industry was on the operational efficiency. A geometric spacing of perforation clusters adopted as the preferred completion method.
The scope of this study is to present an integrated workflow to identify reservoir properties variation along the lateral section of horizontal to engineer completion design, improve stimulation effectiveness, and improve cluster efficiency. The methodology adopted in this study resulted in optimized fracture design that helped reduce-cost and increased well EUR. Optimal cluster spacing was determined based on long-term production performance. The final calibrated hydraulic fracture and reservoir models were used to optimize the cluster spacing and other completion parameters.
Verification and testing of a newly installed wellbore barrier, in older assets has proven to be challenging. Even more so when the well has structural issues, indemnities or weak spots in the barrier envelope, or weakend well construction that limits the possibility to acheive a positive pressure verification of the barrier with an applied surface pressure versus the reservoir pressure.
A suitable location with necessary support and strength should be located in the well. If installing a mechanical barrier in means of a bridge plug as the primary barrier, we will monitor the installation forces in the anchoring and sealing sequence. This individual signature will be verified towards a nominal base line signature of a ISO approved test and a library of thousands of collected installation profiles. Any abnormality can trigger a release and relocating of the barrier. A second verification barrier will then be installed close above the primary barrier and installation sequence will be verified the same way as the primary barrier. When both installation signatures are accounted for we can pressure test the installed barriers. This can be done with a pressure manipulation tool, where we introduce a calculated predetermined pressure drop between the installed primary barrier and the verification barrier above. By monitoring this pressure alteration vs. the pressure above the verification barrier, we can determine if we have a verified primary and verification barrier.
The Primary Barrier is verified in the direction of flow (negative pressure test). And verification barrier as the secondary barrier is verified with a positive pressure test. If a dual barrier is requested you can leave the verification barrier as secondary barrier or pull to re-use.
The adoption of a digital project delivery methods utilized by the manufacturing industry can be applied to oil and gas capital projects. Benefits include: greater collaboration and transparency between an EPC and owner-operator, the use of near real-time data to facilitate and drive better project decision-making, and the ability to save resources through increased efficiencies. To better understand poor performance on capital projects, different methods must be looked at. A case study using implementation of a digital project delivery approach through Project Lifecycle Management (PLM) is compared to a legacy project delivery using disconnected tools. This new approach to project delivery shows how adapting PLM software brings together engineering data with planning information, digital action workflows, collaborative review sessions, and visualization of status using a 3D model into a new way of delivering oil and gas capital projects more efficiently. The project schedule is merged with the master deliverables register and data coding to create live project dashboards and end-to-end schedule visibility. Going beyond the technological aspects, the behavioral and organizational challenges of project execution are examined, highlighting the limitations of legacy approaches and the project benefits gains using the digital project delivery approach.
By leveraging the interconnectedness of data, the real-time insights that can be derived, and with the right project team support model, all of these factors come together to show how application of digital project delivery systems enables better project management visibility and capital project performance.
SPE Technical Directors: State-of-the-Technical Discipline - An Annual Conversation with your SPE Technical Directors - presented by Ramona Graves