bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Simple Unified Pressure Transient Analysis Method for Fractured Waterflood Injectors and Minifracs in Hydraulic Fracture Stimulation
Authors: Hoek Paul van 
Published: September 2016

Abstract
Pressure Transient Analysis (PTA) is commonly used in Industry to estimate parameters such as dimensions (length, height) and skin of induced (hydraulic) fractures, and reservoir permeability. PTA interpretation methods are well established for the limiting cases of ‘low’ leak-off [Mini-Frac Analysis (MFA) of stimulation hydraulic fractures] and ‘high’ leak-off [Injection Fall-Off (IFO) analysis of waterflood-induced fractures]. However, traditional methodologies used for these two limiting cases differ fundamentally and there exists no established approach for intermediate leak-off, in spite of many efforts to date.
We present exact 3D simulations of hydraulic fracture propagation at arbitrary rate and for arbitrary leak-off (from very low to very high), followed by fracture closure as a result of shut-in and after-closure reservoir flow. Based on the trends resulting from these simulations, we propose a novel very simple analytical PTA method for estimating fracture dimensions, skin, leak-off coefficient, and reservoir permeability. This method is applicable both to fractured waterflood injectors and mini-fracs in hydraulic fracture stimulation. It presents a consistent approach to before-closure analysis (BCA) and after-closure analysis (ACA).
We compared the exact simulations with our novel analytical PTA method, and with more conventional MFA and IFO approaches, such as g-functions, square root time, and other existing BCA and ACA methods. For all these cases, it is demonstrated that the currently existing approaches present limiting cases for either low leak-off (MFA) or high leak-off (IFO) of our proposed PTA method, and that our novel methodology provides superior results to the existing approaches particularly in the intermediate leak-off range. We also use our numerical methodology to demonstrate that more recently proposed analysis methods using generalized versions of the Agarwal/Bourdet derivative do not necessarily result in a ‘correct’ interpretation, in particular with respect to identifying the point of fracture closure. With respect to the latter, we also demonstrate that often identification of fracture closure from PTA will be virtually impossible.
Finally, we apply our PTA method to a few field cases, thereby demonstrating its simplicity of usage.
Delineating Overburden Anomalies through Dip-Constrained Tomography for Improved Reservoir Imaging in an Offshore Carbonate Field
Authors: Waqas Muhammad , Nakayama Shotaro , Benson Mark , Goraya Yassar , Kleef Franciscus van , Macri Giuseppe , Sroka Agata , Mills Keith , Cowley John 
Published: September 2016

Abstract
Overburden (shallow) anomalies such as channels, sink holes, or karst features pose challenges for seismic time imaging, resulting in an obscured image below the anomalies i.e. pull-ups or push-downs. These anomalies can propagate down to the reservoir masking the image and create structural uncertainties. These relatively small scale (&lt; 1 – 2 km) overburden anomalies cannot be resolved with conventional depth imaging usually, based on migration velocity analysis and residual move out (RMO) minimization only.
This paper proposes the application of dip-constrained tomography, in combination with RMO tomography to help resolve these shallow anomalies. Although the method has been widely used elsewhere e.g. in offshore Brazil and North Sea (Chen et al., 2012, Guillaume et al., 2013, Carotti et al., 2015 and Hollingworth et al., 2015), this is the first time it has been applied in a carbonate oilfield in offshore Abu Dhabi.
An accurate velocity model is required for seismic depth imaging. The velocity model is optimized using a tomographic technique which is a non-linear optimization process with relevant constraints imposed. The data are migrated using an initial velocity model and common image gathers are obtained. RMO is defined in a cost function and non-linear tomography finds a velocity model minimizing the cost function. An additional structural constraint in the form of an offset-dependent dip constraint is introduced in the cost function for minimizing the misfit between the offset-dependent dip of the events and the expected dip.
Dip-constrained tomography was able to obtain a high resolution velocity model in the overburden and provided a robust seismic image essentially free of pull-up and push-down effects in the reservoir. The structural uncertainty in the reservoir was subsequently reduced. Inverting the dip term together with RMO term can potentially correct image distortions e.g. pull-ups and push-downs and focus the image simultaneously. The refined subsurface image can help optimize the reservoir model with less structure uncertainty and can enhance the production profile by providing more flexibility in well design and planning. The methodology was applied on a pilot area which gave quite encouraging results and leads to extend the pre-stack depth imaging to a full-field application.
A Methodology to Integrate Multiple Simulation Models and 4D Seismic Data Considering Their Uncertainties
Authors: Assunção Germano S. , Davolio Alessandra , Schiozer Denis J. 
Published: September 2016

Abstract
Traditionally, integration between 4D seismic (4DS) and simulation data has been performed considering the 4DS data deterministically. However, there are uncertainties in the response of seismic. The goal of the methodology presented in this work is to compare the changes of dynamic properties estimated from 4DS and simulation models considering the uncertainties inherent to both data.
The relevant reservoir uncertainties can be combined to generate multiple simulation models, which provide maps of dynamic changes, such as pressure change (Δp) and water saturation variation (ΔSw). Available 4DS can also be used to map dynamic changes. Through a stochastic seismic inversion, multiple ΔSw and Δp maps can be obtained from 4DS. After selecting a proper scale (scale transference), we compare the dynamic maps from seismic and simulation data using probabilistic density functions (PDFs), establishing levels of agreement/disagreement between 4DS and simulation data.
To validate the methodology we use a synthetic dataset, with moderate complexity and seven uncertainties mapped, such as fault transmissibility, porosity, facies, and permeability. 500 maps of ΔSw and Δp from 4D seismic were generated from prior probabilistic seismic inversion. 500 simulation models previously calibrated using well production data generated the set of 500 maps of ΔSw and Δp from simulation. Applying the methodology, we identify four regions: (1) reservoir locations where both estimates (seismic and simulation) are similar, showing regions properly calibrated, (2) locations where simulation estimates are more precise than 4D seismic, (3) reservoir locations where the data sets indicate divergent estimates, and (4) 4DS estimates are more precise than simulation.
This information can be very useful to guide data integration. As an example, we show that region (4) can be used to select the simulation models that reproduce ΔSw or Δp behavior from 4DS, since 4D seismic data is more precise than the simulation estimates in this region. Other useful information from the proposed methodology is that the reservoir zones identified as region (2) can be used as a constraint to reinterpret 4D seismic data, as simulation estimates are more precise.
The methodology is a new way to evaluate the information from 4D seismic and simulation data considering uncertainties. The identification of these four regions can be useful in the parametrization phase of the history matching procedure (a complex process), as an additional tool to understand the properties in this procedure. The methodology also indicates possible locations to use reservoir engineering constraints to improve seismic interpretation, in regions where estimates from simulation are more precise than 4D seismic data. Moreover, we can use the methodology to determine critical reservoir locations to be reevaluated, those presenting disagreement between the two data source.
Planning For Uncertainties in Gas Composition: Reduce Project Risks by Early Adoption of a Robust Gas Processing Concept
Authors: Chilukuri Pavan , Bowerbank Gary 
Published: September 2016

Abstract
This paper demonstrates that selecting a gas processing concept that is robust against changes in predicted gas composition during the maturation of (associated) gas projects reduces the risk of schedule delays and cost creep while potentially presenting opportunities to deliver first hydrocarbons to customers earlier.
During early project phases, the availability and quality of data on the specific field to be developed are usually limited. Consequently, project teams have often been left with two options when designing gas processing facilities. The first option is to rely on old data, data from well tests of questionable quality and/or data from analogue fields, if available, in order to form the basis of their design. This brings relatively high risk of having to redesign once higher quality data become available. Design alterations may delay the schedule to first oil/gas and lead to increased costs and erosion of the overall project value.
The second option is to wait for new well test data to become available before starting work on the gas processing facilities. This approach, though preferable, can result in costly schedule delays and does not guarantee the delivery of accurate data on which to predict the gas composition and base the gas processing design.
Appreciating this uncertainty is the first step in mitigating the risk. The second step is selecting a gas processing concept that is robust against flow and compositional deviations. In this way, the design of the gas processing facilities can go ahead at a low risk before full appraisal of the field is complete. This may enable parallel project phasing by starting the engineering procurement and construction (EPC) phase for the gas processing facilities during field appraisal.
Shell believes that an effective gas processing line-up of an acid gas removal unit (AGRU) that utilises the Shell Sulfinol-X all-in-one amine technology along with a selective acid gas enrichment unit (AGEU) combined with sulphur recovery units (SRU) and sulphur dioxide (SO2) tail gas treatment provides the robustness to deal with high compositional uncertainty for the gas.
The novelty in this paper is recognising that robust gas treating line-ups such as the one described above can have operational advantages and enable developers to secure their licence to operate by meeting emission restrictions. These line-ups can also have additional project execution/schedule advantages that add value to a project.
Specifically, this paper will demonstrate that the small additional capital expenditure required for the proposed robust design is more than compensated for by the acceleration of the project resulting in an overall improvement to the net present value. Additional benefits to the project will be ease of operation, simplicity and ultra-low emissions.
Challenges During Execution, Construction and Operational Readiness Phase of Surface Facilities in a Full Field Polymer Flood Project
Authors: Mohanram Santosh , Bhaumik Premashis , Jain Shagun 
Published: September 2016

Abstract
This paper is a follow up paper to SPE-169709-MS and discusses key challenges in Surface Facilities Project implementation during the Construction and Operational Readiness phase of the Project and presents available performance results from the full field implementation.
The key areas discussed include (a) operational difference in the available technologies for high concentrated polymer dissolution, (b) transfer of high viscous Polymer Mother Solution with minimum viscosity loss - refinement of the pressure drop calculations based on actual experience (c) efficacy of pumping facility with high viscosity non Newtonian liquid flow with varying turn down-challenges and lessons learnt based on field experience and (d) supply chain strategy for polymer logistics
The paper also presents preliminary performance results from the full field implementation of world's largest single polymer injection facility as compared to expected challenges and perceived mitigation during design phase.
Self-Sealing Isn’t Just for Cracks: Recent Advance in Sour Well Protection
Authors: Dieguez E. Sevilla , Bottiglieri A. , Vorderbruggen M. , Saeed Y. 
Published: September 2016

Abstract
Cementing sour wells can be very challenging; even when best practices are followed, the integrity of the cement, casing, and/or tubing can be jeopardized. In such cases, challenging and costly remedial work is necessary due to the complicated nature of the environment. A safe, cost effective way to prevent the need for remedial work is the use of self-sealing systems; however, until now, there was no data that validated self-sealing systems’ capability to tolerate exposure to H2S. This paper focuses on the newly discovered ability for the self-sealing systems to withstand exposure to H2S while maintaining self-sealing properties.
To confirm that the self-sealing material is uninhibited by H2S, a gas mixture of H2S in nitrogen was bubbled through a mixture of self-sealing material and water. The concentration and rates used were picked to mimic a standard sour well’s condition allowing the testing to recreate the challenging well environment. The self-sealing material was then added to the cement slurry and transferred to the crack/seal equipment for testing.
The results from the experiment were compared to a self-sealing slurry with the same components but in which the self-sealing material had not been exposed to H2S. Both systems were able to seal multiple times, validating the ability of the exposed material to withstand H2S exposure. The finding from this study opens the door for self-sealing cements to address several kinds of corrosive gases. Because the system was able to withstand exposure to such a strong gas, it will likely be able to tolerate weaker corrosive gases such as CO2.
The discovery from this experiment promotes a new use for self-sealing cements. No longer will their use be limited to cracks in the cement matrix but also as an extra precaution when working in sour wells and corrosive environments.
Numerical Investigation of the Effect of Nonuniform Fracture Aperture of Eagle Ford Outcrop Maps on Production Performance
Authors: Sun Jianlei , Schechter David , Rui Zhenhua 
Published: September 2016

Abstract
Nonuniform fracture aperture not only might affect initial reservoir fluids in place, but also production behavior. Previous experimental work has already demonstrated the importance of nonuniform fracture aperture on permeability and residual oil distributions. This study investigates its impact on unconventional liquid reservoirs through outcrop analysis of Eagleford maps, unstructured gridding, and reservoir simulation of hydraulically fractured horizontal wells.
Previously documented Eagleford outcrop maps are digitized as fracture patterns. Fracture networks for reservoir simulation are generated by duplicating the fracture patterns along horizontal and vertical directions. Then, in order to evaluate production performance of the complex fracture networks, unstructured gridding algorithms are developed to discretize the fractured reservoir domain. Furthermore, previously CT-measured lognormal fracture apertures are populated along each fracture. Finally, the impact of nonuniform fracture apertures on production performance is evaluated under different closure stresses and compared with corresponding uniform fracture apertures.
The complex fracture networks generated from outcrop maps show very high natural fracture density than what we usually observe in the literature about Eagle Ford formation. Fractures with nonuniform apertures show responses of finite fracture conductivity. In the early period, fracture drainage is observed around the horizontal well, even if fractures in outcrop maps are very well connected. At the later period, matrix-fracture transient flow dominates the production, showing a long tail in production rate plots. In addition, stress-dependent nonuniform fracture apertures affect cumulative oil production. The higher the closure stresses, the higher the chance the aperture decreases, and thus the lower the production performance. Moreover, when fracture mineralization is taken into account, the decrease of nonuniform apertures can bring down the cumulative oil production by almost half. Furthermore, the cumulative oil profile of nonuniform apertures is bounded by those of arithmetic and harmonic averaged apertures. Therefore, it is possible to quickly estimate well production using uniform fracture apertures that are obtained by applying averaging techniques to nonuniform apertures.
This paper proposed a workflow to simulate well production performance of Eagle Ford outcrop maps with nonuniform fracture apertures. Besides, the impact of nonuniform fracture apertures due to closure stresses and mineralization is presented together with comparisons with uniform fracture apertures.
Pipe-Conveyed Microfrac Testing and Acoustic/Image Logs Enables Gas Depleted Formation Stress Calibration in Carbonate Reservoirs
Authors: Franquet Javier A. , Jaiyeola Abiodun I. , Al Beshr Huda , El-Hamawi Mohamed , Elarouci Fethi 
Published: September 2016

Abstract
Development plans in largely depleted carbonate gas bearing reservoirs are dependent upon having a complete understanding of reservoir mechanical behavior under change of in-situ stress state. The accuracy of 3D geomechanical models relies highly upon proper tectonic strain and stress calibration using in situ straddle packer microfrac testing conducted in vertical pilot wellbores. Pipe-conveyed straddle packer microfrac tests have become an important technology to measure in-situ fracture closure stress in depleted and non-depleted reservoir layers in order to quantify the stress contrast among multiple intervals with different reservoir pressure regimes.
This case study describes the use of microfrac tests to validate and calibrate the horizontal stress profile in various reservoir intervals of a carbonate formation that had been developed to a substantially depleted condition. Well-injection plans, cap-rock integrity assessment, stress contrast, hydraulic fracture containment, and minimum horizontal stress estimations can all be quantified from multiple microfrac tests recorded at various depths of the reservoir formation. The fracture closure analysis was conducted using three different methods: (i) square-root of time, (ii) G-function and (iii) Log-Log plot. The final fracture closure measurement was obtained after consolidating the three fracture closure identification methods in all injecting cycles conducted on each microfrac station.
The integrated post job microfrac analysis includes borehole acoustic processing and resistivity imaging. The borehole acoustic response is used to estimate not only formation mechanical properties but also log-derived stress profiles while borehole Imaging is used to select the microfrac points and to confirm the induced borehole fracture created during the pressurization of the straddle packer tool. Formation breakdown, fracture reopening, propagation and closure at multiple reservoir layers provide the necessary in situ measurements to calibrate the stresses change due to pore pressure depletion. This information provides a better understanding of the in situ stress state in depleted formations that reduce risk in designing future gas development strategies in the field.
Enhanced Heavy Oil Recovery by Liquid CO2 Injection under Different Injection Strategies
Authors: Farzaneh Seyed Amir , Seyyedsar Seyyed Mehdi , Sohrabi Mehran 
Published: September 2016

Abstract
There are vast resources of heavy oil located in reservoirs in which the reservoir temperature is lower than or in the vicinity of the critical temperature of CO2 (31.1 °C). A good example of that are the huge resources of heavy oil in the Alaska North Slope. In these reservoirs, CO2 would be in liquid state and would exhibit higher viscosity and solvent power compared to gaseous or supercritical CO2. The objective of this study is to experimentally assess the potential of liquid CO2 injection for enhancing recovery from these reservoirs. A positive outcome could bring significant economic and environmental benefit by improving oil recovery and at the same time managing produced CO2 from neighboring reservoirs.
A comprehensive series of coreflood experiments were performed using a heavy crude oil under the conditions of a heavy oil reservoir in the North Slope, Alaska. Different injection scenarios were experimentally simulated including water flood, CO2 flood, as well as combined water and CO2 injection in the form of WAG and SWAG injection. In order to investigate the impact of an initial depletion stage on the performance of CO2 injection, the impact of the amount of dissolved hydrocarbon gas in crude oil was also investigated and the results of the different injection scenarios were compared with each other and with the base case (waterflood).
The coreflood results show a very good performance for liquid CO2 injection in the heavy oil system tested in this work. Dissolution of CO2 in heavy oil and the consequent significant reduction in the oil viscosity leads to a prolonged period of oil recovery during CO2 injection. This is different from waterflood whereby oil recovery almost ceases as soon as water breaks through. Combining CO2 and water and injecting CO2SWAG (simultaneous injection of water and CO2) increased oil recovery more than water or CO2 injection alone. CO2WAG injection (alternating injection of water and CO2) brought about an ultimate oil recovery of 74 % IOIP. This was a staggering 30% higher than the ultimate oil recovery by waterflood under the same conditions.
Dynamic Reservoir Characterization from Microbuildups with Formation Tester
Authors: Azari Mehdi , Khan Waqar , Jambunathan Venkat , Hadibeik Hamid , Iskander Fady , Malik Mayank , Nash Derek , Kurniawan Bobby 
Published: September 2016

Abstract
Historically, drillstem tests (DSTs) have been considered the standard for establishing the productive capacity of oil and gas reservoirs, providing measurements, such as formation pressure, permeability, and skin factor. In a recent study, the possibility of obtaining similar results was investigated by using wireline formation testing tool.
The pressure-transient data obtained during the fluid-sampling cleanout operation was used to obtain reservoir properties. Of particular interest, spherical and radial flow models were successfully fit to very short buildup times (on the order of a few minutes) after pumpouts. To obtain similar formation properties from the shorter duration buildup times associated with flowline surging to clean debris (on the order of seconds), a process referred to as "sneezing" was investigated, yielding comparable results. Sneezing is performed several times during the fluid pumpout and sampling operation. Repetitive analyses of these microbuildups along with other pressure buildup periods in one pumpout location can help reduce uncertainty with respect to the estimation of formation properties.
This paper presents three examples, including both oil- and gas-bearing formations, ranging in terms of lithology, permeability, and pressure. Formation permeability, skin damage, and reservoir-pressure values were evaluated from pressure-transient analyses during pumpouts. Results clearly demonstrate that zonal thickness, permeability, and anisotropy are key contributors to microbuildup analysis. Evaluation of reservoir properties is performed in real time with this approach to help optimize field-development plans. Analyzing these microbuildups is a unique method for supplementing/replacing the standard longer-duration pressure-transient analysis at the lowest-possible cost to the operator.