bluuebunny/crossref_metadata_2025 huggingface dataset:
Uncertainty Quantification of the Fracture Network with a Novel Fractured Reservoir Forward Model
Authors: Chai Zhi , Tang Hewei , He Youwei , Killough John , Wang Yuhe
Published: October 2018

A major part of the uncertainty for shale reservoirs comes from the distribution and properties of the fracture network. However, explicit fracture models are rarely used in uncertainty quantification due to their high computational cost. This paper presents a workflow to match the history of reservoirs with complex fracture network with a novel forward model. By taking advantage of the efficiency of the model, fractures can be explicitly characterized, and the corresponding uncertainty about the distribution and properties of fractures can be evaluated. No upscaling of the fracture properties is necessary, which is usually a required step in a traditional workflow.

The embedded discrete fracture model (EDFM) has recently been studied by many researchers due to its high efficiency compared to other explicit fracture models. By assuming a linearly distributed pressure near fractures, EDFM can provide a sub-grid resolution that lifts the requirement to refine near the fractures to a comparable size as the fracture aperture. Although efficient, considerable error is reported when applying this method to simulate flow barriers, especially when dominant flux direction is across instead of along the fractures. In this work, a novel discrete fracture model, compartmental EDFM (cEDFM) is developed based on the original EDFM framework. However, different from the original method, in cEDFM the fracture would split matrix grid blocks when intersecting them. The new model is benchmarked for single phase as well as multi-phase cases, and the accuracy is evaluated by comparing to fine explicit cases. Results indicate the improved model yields much better accuracy even for multi-phase flow simulation with flow barriers.

In the second part of the work, we applied the model in history matching and performed uncertainty quantification to the fracture network for two synthetic cases. We used Ensemble Kalman Filter (EnKF) as the data assimilation algorithm due to its robustness for cases with large uncertainty. The initial state does not need to be close to the truth to achieve convergence. Also EnKF performs well for the history matching of reservoirs with complex fracture network, where the number of parameters can be large. Therefore, it is advantageous compared to using Ensemble Smoother (ES) or Markov Chain Monte Carlo (MCMC) for fractured reservoirs. After the final step of data assimilation, a good match is obtained that can predict the production reasonably well. The proposed cEDFM model shows its robustness to be incorporated into the EnKF workflow, and benefit from the efficiency of the model, this work made it practical to perform history matching with explicit fracture models.
The Challenges of Deploying an MPD System on a MODU to Drill Narrow Margin Shallow Horizontal Wells in DW GoM
Authors: Moghazy Sharief , Smelker Keith , Hernandez Julian , Van Noort Roger , Arnone Maurizio
Published: October 2018

Managed Pressure Drilling (MPD) is an existing technology that is emerging in Deepwater drilling operations. This paper provides a case study from the Operator’s view, of preparing and deploying an MPD Surface Back Pressure (SBP) system for use in a shallow horizontal well with narrow drilling margins in 8,000ft water depth in the Gulf of Mexico.

This paper will describe the engineering, preparations and operational challenges of deploying a Below Tension Ring (BTR) MPD system. The paper will also include information on the hazard assessments, Mud Gas Separator (MGS) considerations, training plan, deployment plan and results, and engagement with the regulator.

The paper will present a case for the requirement of MPD for use in the narrow margin shallow horizontal wells, including an analysis of the required mud weights and surface back pressure to drill through narrow margins. It will also include a summary of best practices and lessons learned.
A New Technique for Quantifying Pressure Interference in Fractured Horizontal Shale Wells
Authors: Chu Weichun , Scott Kyle , Flumerfelt Ray , Chen Chih-Cheng
Published: October 2018

Pressure communication is commonly observed in fractured horizontal shale wells, particularly at early times when wells are placed on production. This paper will present a new technique, based on the diffusion exponent from the power-law model, to quantify connectivity in multi-stage hydraulic fractured wells with complex fracture networks. In addition to explaining the theory and analysis techniques, we will present examples utilizing measured bottom-hole pressure (BHP) from the Permian Basin Wolfcamp Shale, which illustrate the utility of this technique to better understand the relationship between completion size, well spacing, and well performance.

Chen and Raghavan (2015) recently developed a one-dimensional, fractional-order, transient diffusion equation to model fluid flow in complex geological media. They showed power-law behavior is the norm in unconventional reservoirs such as Permian Basin Wolfcamp Shale. Under the framework of power law behavior, we plot pressure interference test (PIT) data in terms of the Chow Pressure Group (CPG), which enables us to define an indicator of connectivity reflecting temporal and spatial effects. On each test, we derive a diffusion exponent reflective of the magnitude of pressure interference (MPI). We will show among other things that multiple PITs over time often indicate degrading connectivity between wells.

From PIT analyses in Permian Basin Wolfcamp Shale, we were able to establish a relationship between MPI and well spacing. The first example demonstrates analyses of PITs between wells during the production phase and also shows how connectivity between wells diminishes over time. A second example applies the same analysis techniques to quantify inter-well connectivity during the post-stimulation phase by analyzing a pressure falloff (PFO) after communication with other wells. A third example illustrates an application of desuperposition to remove the effect of a power-law pressure trend on interference tests.

Techniques to analyze PITs assuming radial or linear flow have been previously developed; however, Raghavan and Chen (2018) showed apparent radial or linear flow could exist under anomalous diffusion for heterogeneous reservoirs. In this work, we present a technique for analyzing power-law PIT data, which is typical of most horizontally fractured shale wells. This model is a unique approach to understanding flow behavior, quantifying well interference, and analyzing & predicting well performance in unconventional reservoirs. Our examples, which are based on high-quality BHP gauge data, show how this technique could shorten the cycle time for operators to determine the well spacing for a given completion design.
Modeling Fault Reactivation Using Embedded Discrete Fracture Method
Authors: Tavassoli Shayan , Xu Yifei , Sepehrnoori Kamy
Published: October 2018

The integrity of a geological formation is a primary concern in any underground fluid injection project. Hydraulic pressurization due to injection may reduce fault strength, trigger fault slippage, and cause fault reactivation. The reactivated fault affects the fluid migration and loss from the injection zone, which might undermine the efficiency and safety of the project. Hence, a reliable modeling of fault reactivation is critical.

In this work, we propose a new approach to modeling fault reactivation. Faults are complex structures and generally consist of core and damage zones with macroscopic fracture networks. The embedded discrete fracture model (EDFM) is an effective method for simulating complex geometries such as fracture networks and nonplanar hydraulic fractures. We used the EDFM in conjunction with a compositional reservoir simulator to model fault reactivation under hydraulic pressurization. The phase behavior and fluid flow are accurately modeled using the equation of state (EOS) compositional simulation.

The activation of fault occurs at a threshold pressure, which depends on the chemo-mechanical properties of the formation rock. The threshold pressure can be estimated using analytical, numerical, or laboratory methods. In this study, we provided an analytical calculation of the threshold pressure. Moreover, we used a refined, multiphase, compositional, and geomechanical reservoir simulator to predict the threshold pressure. The coupled geomechanical reservoir simulation is computationally expensive; therefore, we suggest using this approach, in the absence of laboratory measurements, to simulate only a few regions of the formation with distinctive rock types. The estimated values of threshold pressures for different geomechanical rock types can be used in our simulations.

We performed large-scale reservoir simulations using the EDFM to investigate the storage capacity of carbon depositional formations representative of the Gulf of Mexico and monitor CO2 migration paths before and after fault reactivation. The results of this study are helpful to evaluate the capacity and integrity of carbon storage sites. Our methodology gives promising results for the prediction of fault reactivation and CO2 migration within a formation.

The proposed approach accurately models faults and their reactivation. It does not require refinement and geomechanical calculation for each gridblock in the domain, which reduces the computational time by at least five times. The significance of this approach becomes more pronounced in large formations with multiple rock types and faults. Although we used our approach for the study of carbon storage, the same methodology can be used for other types of fluid injection, such as water disposal.
Statistical Analysis of Effect of Proppant Design on Production Decline Profile of Shale Wells
Authors: Yang Alex , Stewart Benjamin , Jacob Thomas , Abramov Artem , Ramos-Peon Alexandre
Published: October 2018

In recent years, operators have been pumping more and more proppant per stimulated foot while simultaneously increasing lateral lengths. In order to mitigate the resultant costs and logistical difficulties, operators and service companies have switched to lower cost brown sands sourced from the Hickory Formation. We believe enough time has passed to test the hypothesis that the new design profile of wells-massive amounts of lower crush strength sand-will result in steeper production decline. We have gathered data from fracfocus.org on frac treatment design, supplemented it with data from state databases when available, and rigorously validated and cross-referenced all sources of data. We also gathered monthly production data from said state agencies. We regressed proppant type and intensity against production for every play, including in Texas where raw well level production data is unavailable, and instead allocated production to wells on a lease. We used geographical components and operator fixed effects to control for acreage and operator practices, respectively. In addition to statistical analysis, we also looked at well pads where wells used different types of sand.

While we succeeded in building predictive models for production decline, we did not find that sand color was a significant feature in these models
Investigation of Stress Field and Fracture Development During Shale Maturation Using Analog Rock Systems
Authors: Vega Bolivia , Yang Jie , Tchelepi Hamdi A. , Kovscek Anthony R.
Published: October 2018

The emergence of hydrocarbons within shale as a major recoverable resource has sparked interest in fluid transport through these tight mudstones. Recent studies suggest the importance to recovery of microfracture networks that connect localized zones with large organic content to the inorganic matrix. The paper presents a joint modeling and experimental study to examine the onset, formation, and evolution of microfracture networks as shale matures. Both the stress field and fractures are simulated and imaged.

A novel laboratory-scale, phase-field fracture propagation model was developed to characterize the material failure mechanisms that play a significant role during the shale rock maturation process. The numerical model developed consists of coupled solid deformation, pore pressure, and fracture propagation. Benchmark tests were conducted to validate model accuracy. Laboratory-grade gelatins with varying Young’s modulus were used as scaled-rock analogs in two-dimensional Hele-Shaw cell setups. Yeast within the gelatin generates gas in a fashion analogous to hydrocarbon formation as shale matures. These setups allow study and visualization of host rock elastic-brittle fracture and fracture network propagation mechanisms. The experimental setup was fitted to utilize photoelasticity principles coupled with birefringence properties of gelatin to explore visually the stress field of the gelatin as the fracture network developed. Stress optics image analysis and Linear Elastic Fracture Mechanics (LEFM) principles for crack propagation were used to monitor fracture growth for each gelatin type.

Observed and simulated responses suggest gas diffusion within and deformation of the gelatin matrix as predominant mechanisms for energy dissipation depending on gelatin strength. LEFM, an experimental estimation of principal stress development with fracture growth, at different stages was determined for each gelatin rheology. Synergy between diffusion and deformation determines the resulting frequency and pattern of fractures. Results correlate with Young’s modulus. Experimental and computed stress fields reveal that fractures resulting from internal gas generation are similar to, but not identical to, type 1 opening mode.

The novelty of our work is that microfracture networks are imaged and modeled as they form rather than measured after the fact. Host rock elastic-brittle fracture and fracture network propagation mechanisms are triggered by internal gas generation, microfracture frequency, connectivity, and topology are linked to material properties in a direct fashion.
Optimizing Drilling by Simulation and Automation with Big Data
Authors: Hutchinson Mark , Thornton Ben , Theys Philippe , Bolt Harald
Published: October 2018

For many years the aerospace and automotive industries have realized significant improvements in efficiency, performance and cost savings by simulating multiple prototype vehicle designs and control systems under various operating conditions. These same simulation techniques have now been introduced to the oilfield drilling industry and are delivering insights for more effective drilling tool designs, bottom hole assembly optimization, drilling severity minimization, dysfunction recognition and for drilling performance improvement with fewer downhole failures. Drilling is a non-linear, coupled and dynamic hydro-geomechanical process, the physics for all aspects of which must be captured to enable a robust automated drilling control process.

Drill string, drilling tool and drill bit failures are frequently incorrectly blamed upon the invisible geology through which they drill. Field engineers frequently report more severe downhole vibrations at rotation speeds other than those predicted by linear frequency-based finite element critical speeds analyses. The same multi-body dynamics simulation techniques used by the automotive and aerospace industries, however, are now being applied to capture the non-linear aspects of the drilling process and provide more realistic predictions of drilling performance.

Simulation validation is achieved by comparing virtual data to physical data with an implicit understanding of the uncertainties of each. Recommendations are presented for improving the usefulness and the quality of physical drilling data which simulation can then also help assure.

The ultimate objective is to deliver better quality boreholes which are less costly with fewer drilling tool failures. These novel simulation techniques are enabling manufacturers to benefit from lower development costs and shorter times to market with more reliable proprietary drilling tool designs. Drilling contractors are using simulations to optimize top-drive controls and drill more effectively. Product developers are able to configure higher performing and more optimal bottom hole assemblies. Operators are able to reduce overall drilling costs with the potential benefits of higher performing drilling automation systems and greater production from better quality boreholes.
Estimating Clean Reservoir Fluid Bubblepoint and Other Properties in Real Time Using PCA Asymptote of Optical Sensor Data and Equation of State
Authors: Olapade Peter , Dai Bin , Jones Christopher Michael , Kallehbasti Mehdi Alipour
Published: October 2018

Mud filtrate invasion occurs in the immediate vicinity of the well as a result of the overbalance pressure of the mud column in the well. Oil-based muds (OBM), unlike water-based muds (WBM), are miscible with reservoir fluid, and OBM contamination alters the properties of the original formation fluid. The bubblepoint of contaminated fluid is usually lower than clean fluid. While fluid is pumped out of the formation, it becomes cleaner and the bubblepoint increases; the upper limit of the increase is the clean formation fluid. While increasing the pumping rate can shorten cleanup time, pumping below the bubblepoint can modify the fluid phase behavior and cause asphaltene content in the formation fluid to precipitate out and sensor data to become erratic and noisy. Therefore, it is important not to pump below the bubblepoint, knowing the clean fluid bubblepoint in real time provides a guideline for the field engineer. The purpose of fluid sampling is to collect a representative formation fluid—samples with an acceptably low contamination. The clean fluid bubblepoint provides a lower limit on pumping pressure, which helps ensure pumping does not go below the bubblepoint and the sample is in single phase.

This paper describes how clean fluid compositions are determined from the asymptote of the principal component analysis (PCA) reconstructed scores and then used as input for the equation of state (EOS) program to compute fluid properties such as bubblepoint and gas/oil ratio (GOR). The optical spectral data from the optical fluid analyzer is first despiked, and outliers from the despiked data are removed using the robust ordinary least squares regression (ROLSR) method and robust PCA (RPCA). After removing outliers, clean fluid spectra data are reconstructed using asymptotic PCA scores and PCA loadings. Using a neural network model, clean fluid compositions are determined from reconstructed fluid spectral data, and fluid compositions are used as input for the EOS program to determine fluid properties.

Results confirm that the clean fluid bubblepoint and GOR do not change significantly after a few tens of liters of fluid pumpout. Analysis of the first principal component (PC1) confirms that most of the variations occur during the first few tens of liters of pumpout, indicating the predicted clean fluid compositions and properties are somewhat stable. This approach can help determine the clean fluid properties, even while pumping before taking the sample, helping ensure a monophasic fluid sample. When pumpout accumulated volume reaches 40 to 50 L—within 15 to 20 min of pumping out contaminated fluid—clean fluid compositions and properties can be estimated and used to determine reservoir continuity. Additionally, knowing the clean reservoir GOR and API gravity can help determine the type of reservoir fluid in real time.
First Deepwater Campaign, Offshore Romania: Infrastructure, Design, and Execution to Deliver Drilling and Completion Fluids
Authors: Bussaglia Lucio , Di Marino Rodolfo , Smith Vance
Published: October 2018

The Black Sea, offshore Romania, is one of the world's emerging deepwater basins. The objectives of the campaign presented in this paper include safe and compliant operations, data acquisition, reservoir characterization and de-risking of adjacent prospects over the course of a seven-well, deepwater exploratory campaign. The challenges inherent to deepwater are exacerbated in exploratory wells, with additional focus placed on the reduction of risks associated with ECD management, downhole losses, wellbore instability, gas hydrate formation and mitigation of shallow hazards. The scope of this project presented additional logistical challenges, as there were no dedicated facilities in this area to support large-scale deepwater projects. Deepwater projects in emerging areas present a variety of challenges including planning, constructing, and commissioning facilities with sufficient capacity to prepare and store the requisite volumes of drilling and completion fluids. Infrastructure preparation in this project included the design and construction of two liquid mud plants with the capacity to mix, condition and store large volumes of drilling and completion fluids for a multi-well campaign. Additionally, a bulk facility was built and commissioned for handling barite additives used in the project. Project management and monitoring techniques were used to ensure on-time completion of facilities following the critical paths of the project timeline. All planned operational objectives were safely achieved because of detailed planning, commitment, and capital investments in assets and the infrastructure to support operations. This approach enabled delivery of project objectives without incidents of fluids-related non-productive time (NPT). The logistical objectives were achieved on time, and in an environmentally compliant manner. All fluid volumes were safely prepared and delivered to the 5th generation semi-submersible for use in the target intervals. This included delivery of large volumes of high-density riserless kill fluid (RKF) that was stored for three months on a multi-purpose supply vessel (MPSV) without the occurrence of barite sag. All drilling and formation evaluation objectives were accomplished with a high-performance, non-aqueous fluid (NAF) specifically designed for use in this multi-well campaign. The delivery of well testing, plugging and abandonment objectives was facilitated by use of an integrated suite of wellbore cleanup (WBCU), completion fluids and filtration technologies.
Removal of Iron Sulfide Scale with a New Formulation: A Field Application in a Sandstone Reservoir in Egypt
Authors: Abou Bakr Mohamed , Farid Ibrahim Ahmed , Nasr-El-Din Hisham , Abd El-Hay Ahmed , Amin Ehab
Published: October 2018

Iron sulfide scale is a significant problem in the oil and gas industry whereas the iron sulfide deposition has an adverse impact to the production operations. The scale is present in various species with different iron to sulfur ratios. Iron sulfide species with high iron content is soluble in acids, whereas those rich in sulfur are almost insoluble in acids.

East ZEIT oil wells have been produced for 20 years in Egypt. Scales with iron sulfides as the major components form in nearly every producing well. These scales have minor compositional but form at differing rates and thicknesses in the lower half of tubing string. Well East ZEIT-13 was completed initially in Nubia formation which is communicated with another formation called ‘’Lower Senonian’, whereas the drive mechanism is active water-drive.

The formation is sandstone with the following specs: Lose, pale yellow, quartz, very fine to fine-grained, sub-rounded to rounded, and moderately sorted sand grains. The reservoir temperature is 300°F. The well was producing using a jet pump (JP), the production stopped due to scale formation. A workover started to replace the completion. The JP was used again to produce the well with very low productivity; +/-0.06 bbl/psi. The power fluid of the JP is oil with 1% water cut. The scale was expected to cover all the casing area below the tubing end until PBTD.

A scale sample was obtained and analysis of the scale through XRD showed that the scale composition is as follows; 36% Marcasite (FeS2), 21% Greigite (Fe3S4), 17% Pyrite (FeS2) and 26% Siderite (FeCO3). Both pyrite and marcasite have a very low solubility in HCl, and the only available method of removal in the oil industry is milling. The milling operation failed to solve the problem, therefore, the production was stopped until finding an alternative solution.

An effective treatment strategy proposed to remove the scale efficiently; the technical proposal was designed taking into consideration the complicated nature of the scale. Furthermore, the proposed treatments were conducted and placed using coiled tubing (CT).

The first application using the SCSR-02 solution has been successfully carried out and the job results were outstanding. Production has been returned with an increment of 50% above its original rate. The well is producing natural flow without using the JP, and efficient cost/Bbl.
An Automatic History-Matching Workflow for Unconventional Reservoirs Coupling MCMC and Non-Intrusive EDFM Methods
Authors: Yu Wei , Tripoppoom Sutthaporn , Sepehrnoori Kamy , Miao Jijun
Published: October 2018

Technological advancements enable natural gas to be economically produced from ultratight shale rocks. However, due to the limited availability of long-term production data as well as the complexity of gridding, for reservoir simulation studies, in dealing with hydraulic fractures, an efficient automatic history-matching workflow in a probabilistic manner for performing history matching, production forecasting, and uncertainty quantification is highly needed. This can provide critical insights for the decision-making processes. In this study, we present an integrated history-matching workflow through coupling an innovative non-intrusive EDFM (Embedded Discrete Fracture Model) method, proxy modeling of KNN (K-Nearest Neighboring), and MCMC (Markov-chain Monte Carlo) sampling. The non-intrusive EDFM method can be applied in conjunction with any third-party reservoir simulators without the need of changing the source codes. Through non-neighboring connections, EDFM can accurately and efficiently handle hydraulic fractures, which does not require local grid refinement nearby fractures. The design of experiment is applied to perform sensitivity analysis with the purpose of identifying significant uncertain parameters. The KNN is utilized to build proxy model and its quality can be improved through multiple iterations of the workflow. The classic Metropolis-Hasting (MH) algorithm of MCMC is employed to perform sampling and predict posterior distribution of uncertain parameters. An application of the workflow to a horizontal shale-gas well from Marcellus shale is demonstrated and discussed in this study. Gas desorption effect is considered in the reservoir model. Six uncertain parameters are considered for this well including matrix porosity and permeability, fracture half-length, fracture conductivity, fracture height, and fracture water saturation. Based on 10 iterations and 250 simulation cases, 52 history-matching solutions with reasonable match results against actual gas and water production rates were identified. After history matching, we performed production forecasting for 30 years using all history-matching solutions under the constraint of constant flowing bottomhole pressure of 500 psi. Reliable P10, P50, and P90 of EUR (estimated ultimate recovery) predictions of gas recovery were determined as 11.9, 13.1, and 16.4 Bcf (billion cubic feet), respectively. In addition, the narrower posterior distributions of six uncertain parameters were quantified. The values with the highest frequency for each parameter are determined: porosity is 10.4%, permeability is 0.00034 md, fracture half-length is 450 ft, fracture conductivity is 2.85 md-ft, fracture height is 87.5 ft, and fracture water saturation is 38.8%.
Improved Gravity Drainage by Gas in Fractured, Oil-Wet Carbonate Rocks Using Mobility Control Agents
Authors: Zhou Jimin , Sharma Himanshu , Mohanty Kishore
Published: October 2018

Waterflooding in low permeability, fractured and oil-wet carbonate reservoirs yields extremely low oil recovery due to bypassing through fractures and little imbibition into the matrix resulting in a large amount of oil remaining in the reservoir. Gravity-aided gas injection is studied at the lab-scale in this work to enhance oil recovery from fractured reservoirs. The miscibility of the gas with a model oil (decane with naphthenic acid) is varied by enriching the methane with ethane. Mobility of the gas is decreased by incorporating the gas in foam or glycerol-alternating-gas floods. As the miscibility increases, the oil recovery increases, but reaches a plateau above the near-miscible conditions. The foam flood improves oil recovery by diverting gas into the matrix, if the gas is sufficiently soluble in the oil and the gas-oil capillary pressure is sufficiently low. The pressure gradient generated in the fracture by foam helps in the diversion of the gas into the matrix. Glycerol-alternating-gas floods result in minor additional oil recovery over foam floods because the pressure gradients are about the same. These experiments need to be repeated after gas floods (before conducting foam floods). Near-miscible (and miscible) foam floods increased the oil recovery to high values (about 85% OOIP) in core floods and their scale-up to reservoir scale warrants further study.
An Integrated Platform for IIoT in E&P: Closing the Gap between Data Science and Operations
Authors: Wen Tailai , Evers Karina , Huang Xinwo , Keyes Roy
Published: October 2018

Although major E&P companies have been investing in data-driven modeling and analytics in the Big Data era, expected cost reductions and efficiency improvements have scarcely been realized, mainly due to the overhead related to operationalizing analytics and models. This paper proposes the architecture of an industrial internet of things (IIoT) platform that minimizes the overhead and accelerates value creation in the context of the digital oilfield.

The proposed IIoT platform is an integrated portal for all members working in the same ecosystem, including data scientists, data engineers, operation engineers, business analysts, and IT administrators. It is the first platform focusing on minimizing the gap between in-house modeling teams and operation teams in an industrial context. This work successfully addresses the challenge of operationalizing the digital oilfield, in turn catalyzing smart operations through industrial analytics.
Geomechanical Analysis of Frac-Hits Using a 3D Poroelastic Hydraulic Fracture Model
Authors: Kumar Dharmendra , Ghassemi Ahmad , Riley Spencer , Elliott Brendan
Published: October 2018

Well-to-well interference or communication between the production or "Parent" well and the infill or "child" well is one of the main concern in horizontal wells refracturing, which results in a decrease of productivity of both the wells. Many field observations have demonstrated that the "child" well fractures could have a tendency to propagate towards the "parent" well resulting in well-to-well interference or "frac-hits" issues. This paper presents a geomechanical perspective to better understand the problem of "frac-hits" in horizontal well refracturing and to design solutions for it using geomechanics analysis and modeling. The numerical analysis is based on a fully coupled 3D model "GeoFrac3D" with the capabilities to simulate multistage fracturing of multiple horizontal wells. The model fully couples pore pressure to stresses and allows for dynamic modeling of production/injection and fracture propagation. The modeling results show that production from the parent well gives rise to a non-uniform reduction of the reservoir pore pressure around the production fractures leading to anisotropic decrease of the reservoir total stresses which may result in stress reorientation or reversal. The decrease of total stresses in the vicinity of the parent well fractures creates an attraction zone for the child well fractures. The child well fractures have a tendency for asymmetric growth towards the lower stress zone. The impact on the parent and child well production and the risk of "frac-hits" will vary with the reservoir stress regime and production time. Optimizing fracture and well spacing, fluid viscosity, and the timing of refracturing can help to minimize problems. The simulation results demonstrate that the risks of "frac-hits" issue can be mitigated by re-pressurization of the parent well before child well. Traditional methods of refracturing simulation usually use two different codes to solve the problem and mostly use stress analysis rather than explicit fracture propagation. The model used in this study can simulate both aspects of the problem i.e., the reservoir depletion analysis and the subsequent child well fracturing.
Smart Oilfield Technologies and Management: Maximizing Real-Time Surveillance and Utilization
Authors: Al-Kadem Mohammad , Al Yateem Karam , Al Amri Meshal
Published: October 2018

Smart oilfield technologies and management real-time data surveillance, in terms of reliability and availability, has proven essential in the process of prolonging asset lifespan, improving asset integrity, and proactively preventing problems. This illustrates a leadership role in the integration of cutting-edge technologies by utilizing an Intelligent Field concept. Surveillance capitalizes on real-time data transmitted from Intelligent Field equipment, where mathematical algorithms and logic are automated and imposed. The application captures specific sets of data to help identify and analyze challenges associated with Intelligent Field equipment. Major prevailing benefits include, identifying systematic techniques to utilize automated diagnostics for reduction in human intervention, develop field level surveillance, cross-validating measurements through online modeling, and further enhance collaboration. This paper details the methodology, the outcome, the requirements, and considerations associated with effective real-time data utilization in energy industry applications. The platform allows business team members and their partners to communicate, collaborate, and coordinate activities in real time.
Simulation of Viscoelastic Polymer Flooding - From the Lab to the Field
Authors: Qi Pengpeng , Lashgari Hamid , Luo Haishan , Delshad Mojdeh , Pope Gary , Balhoff Matthew
Published: October 2018

Experimental data in numerous publications show that viscoelastic polymers can significantly reduce residual oil saturation under favorable conditions. The effect of viscoelasticity is in addition to improved sweep efficiency of polymer flooding. The residual oil saturation decreases with increasing dimensionless Deborah number (a measure of the relative elasticity). We used these extensive coreflood data to develop a new model that is referred to here as an Elastic Desaturation Curve (EDC). The new EDC model was implemented into a reservoir simulator and used to simulate polymer floods at both the lab and field scales. The simulated coreflood results match the experimental oil cut, oil recovery and pressure drop data. The simulator was then used to predict the effectiveness of polymer floods in a quarter five-spot well pattern under favorable field conditions. The field-scale simulations show that a viscoelastic polymer flood can recover significantly more oil (12% OOIP for the base case simulation) compared to an inelastic polymer flood of the same polymer viscosity. A sensitivity analysis shows that polymer concentration, salinity, well spacing, permeability, heterogeneity and injection rate affect the incremental oil recovery due to elasticity. The results suggest that the use of viscoelastic polymers could be a beneficial enhanced oil recovery strategy at the field scale under favorable conditions.
Advanced Fracture Diagnostics by Utilizing Over 250 Fracture Diagnostic Tests in Indian Volcanic Tight Gas Reservoir
Authors: Pathak Shashank , Tibbles Raymond Joseph , Tiwari Shobhit , Anand Saurabh , Ranjan Vishal , Siddarth Punj , Bohra Avinash
Published: October 2018

This paper documents the basis of fracturing diagnostic test design and analysis methodology adopted while fracturing one of the few commercial volcanic gas reservoir in the world. More than 10 distinct types of diagnostic tests were performed with each having specific objective. These tests were primarily conducted to:

Reduce the uncertainty while fracturing Improve reservoir & hydraulic fracture understanding to enhance production Validate qualitative sources of information

These tests included standard pre-frac injection tests, post injection surveys as well as innovative modifications which significantly helped to enhance operational efficiency and improved production results. To achieve maximum net pay coverage with minimum number of frac stages, limited entry fracture technology best suited the economics of this field. Since limited entry technique was selected even with its inherent uncertainties with respect to diversion in individual fracture cluster, the overall performance of this field heavily depended on its effectiveness. To maximize the probability of success, uncertainties & risks were evaluated and a workflow was designed. This workflow consisted diagnostic tests with specific deliverables such as DFITs to calibrate mechanical earth model (MEM), Step rate tests to estimate the efficiency of fluid diversion, temperature surveys to validate fluid distribution, production logs to confirm production performance. These standard tests were also modified to minimize cost/time implication while ensuring specific information was acquired as expected from these tests. Fracture model calibration was achieved by a combination of injection tests, post injection test/fracturing temperature surveys, along with a consistent method for fracture history matching. Final verification was obtained using a series of production logs. Over 13 Diagnostic Fracture Injection Tests (DFITS), 63 Step Rate Tests (SRT), 80 Step Down Tests, 58 post SRT/Fracturing Temperature Surveys, over 50 production logs are incorporated in this study.

All of this augmented reservoir understanding and helped to save operational time and reduce cost. These tests further helped to increase from 3 clusters per frac to 6 cluster per frac, thus increased net pay coverage with same frac stages. The contribution of 6 clusters was also validated from production logs. Completion improvements have resulted in productivity and Estimated Ultimate Recovery (EUR) increases of 80% and 20% respectively. Screen out rates have dropped from 33% in the very first campaign to 5% in the most recent campaign.

Detailed analysis and key engineering findings from all of these tests. Representative case histories including, DFITS, Step rate tests, Mini Fracs, Temperature surveys and production logs to back up the results. The results from these learnings are summarized in this paper.
Self-Adaptive Depth of Cut Control Technology: A Path-Breaking Approach to Address Torsional Dysfunction and Securing Drilling Performance Gain in Challenging Deepwater Gulf of Mexico Well
Authors: Roy Chowdhury Ashabikash , Serrano Ralph , Martin Brisk , Landry Jonathan
Published: October 2018

Torsional instability in a drilling system is a significant challenge that limits performance. In its extreme form, known as stick-slip, the drillstring stops and restarts, exposing its downhole equipment to extreme forces that can lead to failures, unintended trips, and escalated operation costs. Torsional instability can also trigger lateral dysfunctions and whirl, creating further risk of bit and bottomhole assembly (BHA) failure. The risk of torsional dysfunction is heightened in applications involving concentric reamers and long drillstring, high-angle wells.

The correlation of polycrystalline diamond compact (PDC) bits with torsional dysfunction is well known, and different approaches have been suggested to address the issue. The fixed depth of cut control (DOCC) approach, which is commonly used to address the issue, limits the PDC bit and formation engagement at a pre-determined ratio of rate of penetration (ROP) and drillstring RPM. However, this approach has an uncertain success rate when drilling conditions change. To address the challenge of torsional dysfunction while drilling a directional well with a 12¼-in. pilot bit and a 14½-in. concentric reamer, a self-adaptive DOCC technology was deployed in a deepwater well in the Gulf of Mexico (GOM). The self-adaptive DOCC technology automatically adjusts the depth of cut engagement threshold as drilling conditions change, eliminating the manual parameter adjustment required at surface to manage torsional dysfunction.

The application of self-adaptive drill bit technology in the target well yielded excellent results, and the section was completed with a single bit/BHA run. Ninety-eight percent of the interval was drilled with no torsional dysfunction. The drillstring whirl was negligible, and 99% of the interval was drilled without lateral vibration. Eliminating harmful dynamic dysfunction significantly enhanced drilling performance and increased the ROP by 57% over the best PDC offset run. The dull bit condition was very encouraging; the bit displayed very low wear and no undesired impact damage, showing the effectiveness of the technology.

This paper uses real-time drilling dynamics field data measured downhole and demonstrates the effectiveness of self-adaptive DOCC technology for drilling performance improvement in deepwater directional well where torsional dysfunction continues to remain a significant challenge and could be a performance limiter.
Proposal and Experimental Trials on an Autonomous Robot for Rigless Well Intervention
Authors: Santos Hugo , Paz Paulo , Kretli Igor , Reis Ney , Pinto Hardy , Galassi Maurício , Pozzani Daniel , Lanzilotta Alessandro , Castro Bruno , Ferreira André , Thomé Lincoln , Beal Valter
Published: October 2018

This paper proposes the development of an autonomous robot for rigless well interventions in order to reduce costs by avoiding the need of a rig to do so, especially for light workover operations in offshore locations. It also presents experimental tests performed in a laboratory string and in a test well in order to evaluate the feasibility of this technology.
Pressure Pulse Testing Method for Caprock Characterization
Authors: Mosaheb Mojtaba , Zeidouni Mehdi , Shakiba Mahmood
Published: October 2018

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).
Computational Fluid Dynamics Modeling of Slip Flow Coupled with Gas Adsorption/Desorption Kinetics in Complex Pore Space
Authors: Yao Shanshan , Pini Ronny , Wang Xiangzeng , Zeng Fanhua , Ju Ning
Published: October 2018

At reservoir conditions, gas flow confined in submicron pores of shale falls within slip flow and transition flow regimes. Beyond the common instant equilibrium assumption, we believe that gas adsorption/desorption on rough pore surfaces could be in non-equilibrium status when gas pressure keeps decreasing during production. We investigate the interplay of gas slip flow inside complex submicron-scale pores and gas adsorption/desorption kinetics on pore surfaces with computational fluid dynamics (CFD) under unsteady-state flow conditions.

Different from previous studies, the gas adsorption/desorption is in non-equilibrium state, which is closer to real reservoir conditions. Given pore pressure Pp at time t, linear driving force model with gas desorption rate coefficient kd is applied to describe the difference between the equilibrium adsorption amount (calculated with adsorption isotherms) and the actual adsorption amount per unit pore surface area. Free gas flow inside 3D reconstructions of shale pore space is modeled by Navier-Stokes equations with Maxwell's first-order slip boundary conditions. To include gas contributions from desorption, extra source with strength equal to the gas desorption rate is added to the slip boundaries.

Any type of adsorption isotherms can be incorporated into our CFD modeling. We investigate the coupling of slip flow and Langmuir adsorption isotherms for methane in 3D reconstructed pore space. We observe that not all of adsorbed gas measured in adsorption isotherms contribute to gas production. In our study the pore pressure, Pp, decreases along with time t. One significant finding is that there exists a key time point, tk, after which adsorbed gas starts desorbing off pore surfaces and the decreasing rate of pore pressure becomes smaller. The higher the gas desorption rate coefficient, kd, is, the earlier tk occurs. But the decreasing rate of pore pressure is no longer sensitive to the coefficient, kd, when kd is larger than 0.0005. Another significant finding is that optimum gas production rate should be chosen according to kd values. It is always better to have high production rate when kd is larger than 0.0005. If the kd is smaller than 0.0005, simulations are necessary to determine optimum gas production rate by balancing the development efficiency and final amount of gas desorption.

Gas adsorption/desorption is always regarded as an instant equilibrium process in shale reservoir simulations. This study considers the non-equilibrium gas adsorption/desorption process, which is closer to real reservoir conditions. No studies in the literature have considered the influence of gas adsorption/desorption kinetics when choosing optimum production rates. CFD simulations in this study provide insight and guidelines on optimizing shale gas development with evaluating slip flow as well as gas adsorption/desorption characteristics.