bluuebunny/crossref_metadata_2025 huggingface dataset:
Pore Scale Investigation of Oil Displacement Dynamics by Smart Waterflooding using Synchrotron X-ray Microtomography
Authors: Qin Tianzhu , Fenter Paul , AlOtaibi Mohammed , Ayirala Subhash , AlYousef Ali
Published: October 2020

Smart waterflooding is an economic and effective method to improve oil recovery in carbonate oil reservoirs. Recent studies show controlling the salinity and ionic composition of injection water can alter the wettability of carbonate mineral surfaces. The pore-scale oil displacement by smart waterflooding in heterogeneous carbonate reservoirs, especially the dynamics at the early stage, is still unclear.

The goal of this study is to examine the role of ion concentrations and types in the oil displacement efficiency and investigate the impact of smart waterflooding on the pore-scale dynamics of oil displacement. A carbonate rock sample was flooded with synthetic high salinity water and other smart water solutions with different sulfate concentrations. The flooding processes were visualized with synchrotron X-ray microtomography. Experimental results show that the smart water with lower sulfate concentration and high salinity water did not change the wettability of the pore surfaces. Higher sulfate ion concentrations in the smart water, in contrast, altered the wettability of carbonate pore surfaces from oil-wet to neutral-wet within the first few minutes of waterflooding. Novel insight was gained on the unique ability of smart water to displace oil in the small pores and through abundant oil channels, which consequently lead to higher oil recovery from the carbonate rock.
Eigenmode Decomposition of the Diffusion Equation: Applications to Pressure-Rate Deconvolution
Authors: Kubota Leonardo , Piccinini Rodrigo
Published: October 2020

The diffusion equation in heterogeneous porous media is solved analytically with the integral transform technique given by Mikhailov and Ozisik (1984). The method enabled us to write the solution of the pressure-rate deconvolution as an infinite series of eigenmodes (eigenfunctions). Each eigenmode is associated with a hydraulic diffusion timescale (eigenvalue) that depends on the intrinsic reservoir properties. The set of eigenmodes forms a basis for the solution space and the solution shows some desirable properties: it is smooth, physically constrained for a closed system and some parameters have a physical interpretation. It is also proposed that the investigated porous volume during a well-test can be estimated from the eigenmode expansion and that the single-well deconvolved pressure-derivative response can be untangled from the interference effects of neighboring wells under certain conditions. Applications to reservoir characterization are also presented.
Assessment of Polymer-Induced Formation Damage Using Microfluidics
Authors: Sugar Antonia , Torrealba Victor , Buttner Ulrich , Hoteit Hussein
Published: October 2020

Polymers have been successfully deployed in the oil&gas industry in various field implementations, including mobility control in waterflood, flow divergence, and well conformance control. However, lab and field applications of polymer injections often encounter polymer-induced formation damage related to pore-throat clogging from polymer entrapments, leading to permeability reduction. This phenomenon manifests as a loss of injectivity, which can diminish the recovery performance. The first principles of polymer interaction with porous rocks are poorly understood. In this work, we use microfluidics to assess formation damage induced by polymer flood. Microfluidic techniques offer convenient tools to observe polymer flow behavior and transport mechanisms through porous media. The microfluidic chips were designed to mimic the pore-size distribution of oil-bearing conventional reservoir rocks, with pore-throats ranging from 1 to 10 μm. The proposed fabrication techniques enabled us to transfer the design onto a silicon wafer substrate, through photolithography. The constructed microfluidic chip, conceptually known as "Reservoir-on-a-Chip", served as a two-dimensional flow proxy. With this technique, we overcome the inherent complexity of the three-dimensional aspects of porous rocks to study the transport mechanisms occurring at the pore-scale. We performed various experiments to assess the mechanisms of polymer-rock interaction. The polymer flow behavior was compared to that of the water-flood baseline. Our observations showed that prolonged injection of polymer solutions could clog pore-throats of sizes larger than the measured mean polymer-coil size, which is consistent with lab and field observations. This finding highlights a major limitation in some polymer screening workflows in the industry that suggest selecting the candidate polymers based solely on their molecular size and the size distribution of the rock pore-throats. This work emphasizes the need for careful core-flood experiments to assess polymer entrapment mechanisms and their implication on short- and long-term injectivity.
Geomechanical Template for DAS Fiber Strain Patterns During Hydraulic Fracturing
Authors: Tan Yunhui , Wang Shugang , Rijken Peggy , Hughes Kelly , Lim Chen Ning Ivan , Zhang Zhishuai , Fang Zijun
Published: October 2020

Recently new Distributed Acoustic Sensing (DAS) data have been collected during hydraulic fracturing in shale. Low frequency DAS signals show patterns that are intuitively consistent with the understanding of the strain field around hydraulic fractures. This study utilizes a fracture simulator combined with a finite element solver to further understand the various patterns of the strain field caused by hydraulic fracturing. The results can serve as a "type-curve" template for the further interpretation of cross well strain field plots.

Incorporating detailed pump schedule and frac fluid/proppant properties, we use a hydraulic fracture simulator to generate fracture geometries, which are then passed to a finite element (FE) solver as boundary conditions for elastic-static calculation of the strain field. Since the FE calculated strain is a tensor, it needs to be projected along the monitoring well trajectory to be comparable with the fiber strain, which is uniaxial. Moreover, the calculated strain field is transformed into time domain using constant fracture propagation velocity. Strain rate is further derived from the simulated strain field using differentiation along fracture length.

Scenarios including a single planar hydraulic fracture, a single fracture with a discrete fracture network (DFN), and multiple planar hydraulic fractures, in both vertical and horizontal directions were studied. The scenarios can be differentiated in the strain patterns based on the finite element simulation results. In general, there is a tensile heart shaped zone in front of the propagating fracture tip. On the sides there are compressional zones parallel to the fracture. Multiple planar fracture show polarity reversals in horizontal fiber due to interactions between fractures. Strain field/strain rate show consistent patterns with what is observed from field cross well strain data.

The application of the study is to provide a template to better interpret hydraulic fracture characteristics using low frequency fiber strain monitoring. To the author's understanding, there are no comprehensive templates for engineers to understand the strain signals from cross well fiber monitoring. The results of this study will guide engineers toward better optimization of well spacing and frac design to minimize well interference and improve efficiency.
Evaluation of Single Fracture Stage Performance with Integrated Rock Mechanics and Pressure Transient Analysis
Authors: Ibrahim Ahmed Farid , Ibrahim Mazher , Sinkey Matt , Johnston Thomas , Johnson Wes
Published: October 2020

The most common stimulation technique for shale production is multistage hydraulic fracturing. Estimating fracture geometry is a focal parameter to judge the fracture operation and predict the well performance. Different direct and indirect techniques can be used for fracture diagnostics to estimates fracture geometries. The current study combines fracture measurements and pressure transient analysis to estimate fracture surface area on each stage and to estimate production as a pseudo production log.

The numbers and kinds of fractures were calculated as a function of treating pressures, injection rates, proppant concentrations, and formation properties to compute fracture surface area (FSA). Pressure transient analyses were then conducted with the leak-off data upon completion of each frac stage to estimate the producing surface (PSA). The fall-off data was processed first to remove the noise and water hammering effects. The PTA diagnostic plots were used to define the flow regime and the data were matched with an analytical model to calculate producing surface area.

Tensile and shear fractures are both created during the injection of frac fluids. Shear fractures are caused by movement in already existing natural (fluid expulsion) fractures found in all shale source rocks. Shear fractures form a pressure below the minimum horizontal stress. These shear fractures take advantage of the rock fabric and develop higher surface area than tensile fractures for the same given volumes of water and sand.

FSA is a measure of permeability enhanced area due to hydraulic fracturing. Producing surface area is the resulting effective flow areaconnected to the wellbore. Diagnostic plots showed a linear and radial flow regime depending on the formation and the completion design. Good correlations were found between PSA and FSA results. In general, higher FSA produces higher PSA. In cases where producing surface area was higher than expected from fracture surface area, communication was found with offset wells. When FSA higher than PSA were found, it was usually caused by increased stress from too close offset wells.

Combining FSA and PSA measurements provides forecasts of production for each stage and helps to optimize well spacing at the end of each frac stage.
Near-Wellbore Deposition of High Conductivity Proppant to Improve Effective Fracture Conductivity and Productivity of Horizontal Well Stimulations
Authors: Pearson C. Mark , Fowler Garrett , Stribling K. Michelle , McChesney Jeromy , McClure Mark , McGuigan Tom , Anschutz Don , Wildt Pat
Published: October 2020

In conventional formations it has long been established that designing fracture treatments with improved near-wellbore conductivity generates improved production and economic returns. This is accomplished by pumping treatments with increased proppant concentration in the final stages (the traditional proppant ramp design), and in some cases by changing proppant size or type in the final stages to effect greater near-wellbore conductivity - commonly referred to as a "tail-in" design. These designs overcome the impacts of greater near-wellbore pressure loss during production caused by flow concentration in the near-wellbore region compared to distal parts of the fracture.

For vertical wells and crosslinked fracture fluid treatments, the fluid flow and suspended proppant transport is effectively "piston" flow and it was a relatively straight forward matter to engineer the near-wellbore region with a tail-in of higher conductivity proppant. For unconventional reservoirs, with multi-stage horizontal completions using slickwater fluids, it has not been obvious how best to create this improved near-wellbore conductivity and most operators have employed a "one size fits all" strategy of pumping a single proppant type unless there was perhaps a need for flowback control in which case a resin coated proppant might be used as a tail-in.

This paper reports the results of two projects to address the engineering of the near-wellbore fracture conductivity for horizontal well fracturing. Firstly, a series of laboratory tests were run in a 10 ft. × 20 ft. slot wall to visualize near-wellbore proppant duning and layering associated with both "lead-in" and "tail-in" designs. The impacts of these depositions were then quantified using a 3D hydraulic fracture / reservoir simulation code for a variety of stimulation designs in the Middle Bakken and Three Forks formations of the Williston Basin.

The results of this work show that well stimulation treatments in liquid-rich unconventional formations would benefit from a combination of small (5 to 10%) lead-ins and tail-ins of high conductivity ceramic proppant. This minimizes the effects of radial flow convergence in the transverse fractures generated from the horizontal well and maximizes the economic benefit of the well stimulation. In addition to paying out the small cost increase in only 1 to 2 months, the proppant bands of higher conductivity ceramic help mitigate the effects of longer-term sand crushing and degradation on near-wellbore plugging and thus increases 3-year cumulative free cash flow and the Estimated Ultimate Recovery (EUR) of the well.
Hydraulic Frac-Hit Height and Width Direct Measurement by Engineered Distributed Acoustic Sensor Deployed in Far-Field Wells
Authors: Wu Yinghui , Tucker Andrew , Richter Peter , Trujillo Kirk , Farhadiroushan Mahmoud
Published: October 2020

Hydraulic fracture height and width are key parameters for completion design and evaluation of unconventional resources. Traditional measurement technologies like microseismic, tilt-meters, chemical or radioactive tracers, pressure temperature gauges, etc. either have low resolution or rely on sensitive models which can cause a high degree of uncertainty. Recent frac-hit measurement methods include the use of Distributed Acoustic Sensing (DAS) deployed in far-field wellbores offset from the treatment well. The DAS system directly measures the fracture propagation every second through the completion, with a few meters' spatial resolution sampled at 0.25-meter intervals along the monitored fiber well.

Cross-well fiber optic monitored far-field strain (FFS) results suggested elastic stress effects, intense inelastic fracture expansion and closure events which provide identification and measurement of frac height on a TVD plot, as well as width by measured depth along the wellbore laterals. Vertical wells or the heel-section of horizontal wells are suitable for frac-hit height (FHH) measurement; fracture azimuth and wellbore geometries need to be considered for precise evaluation. A specially designed engineered constellation fiber cable was tested and utilized in this method in combination with a true phase coherence DAS interrogator with a 20 dB improved sensitivity (Signal-to-Noise-Ratio (SNR)) for both low and high frequency ranges DAS.

The optic fiber can be either permanently installed outside the casing or temporarily deployed inside a monitor well. Comparable results can be achieved by the engineered fiber system and have been presented within case studies for both horizontal and vertical well sections. In addition, Distributed Temperature Sensing (DTS) and data from downhole gauge can confirm any temperature or pressure changes resulting from frac driven interactions (FDI).

With this approach, fracture azimuth, frac-hit corridor (FHC) width and FHH can be determined with a high degree of accuracy and resolution. Completion engineers were able to optimize frac models in real-time and further change completion schedules during the frac treatment.
Integrated PI Degradation Modeling IPDM
Authors: Zhang Yanfen
Published: October 2020

Well productivity reduction over time is one of the critical issues for deep-water wells with huge implications on expected recoveries from these wells. It is important to account for this uncertainty accurately in order to generate reliable production forecasts. Typically, reservoir simulation engineers utilize an expression (e.g. linear or exponential) for modeling changes in skin or Productivity Index (PI) over time as a function of either time or cumulative liquid production or pressure depletion. These commonly used single variable-based PI degradation modeling methods are easy to implement with a flow simulator, but they do not address the multi-dimensional nature of PI degradation which is a result of multiple subsurface effects combined with operational conditions. As a result, these single variable-based modeling methods generally do not have good reliability for predicting PI degradation trend.

This article proposes a method for predicting reduction in producing well's PI by integrating a few key well operating variables (drawdown, borehole depletion, and water cut) into a single mathematical formulation. One of the important assumptions of IPDM is that certain critical drawdown pressure exists for each well in the field. When a well is operated below the critical drawdown pressure, negligible to no PI reduction is observed; however, when drawdown exceeds the critical drawdown value, noticeable PI reduction is seen. The reduction level depends on the ratio of current drawdown pressure to critical drawdown pressure, as well as on pressure depletion and water cut levels. By doing so, the global trend and local granularity of PI reduction are well captured. The concept of critical drawdown used in IPDM is aligned well with the awareness of safe drawdown among Reservoir Management practitioners. Critical drawdown ranges derived from IPDM form a useful analog data set while deciding safe drawdown limits or forecasting PI degradation trends for future wells.

The predictability and generality of IPDM were assessed with historical well test (or PTA – Pressure Transient Analysis) data from more than 50 wells across seven deep-water fields. A detailed workflow of implementing IPDM was demonstrated through one of the field applications. From practical implementation point of view, IPDM method can be easily written in Excel Macro or using a PYTHON script or any other programming language. Once the methodology is coded (or implemented), it can then be plugged in a dynamic flow simulator (e.g. INTERSECT™). A similar approach is usually taken while incorporating single variable-based method for forecasting PI degradation into a flow simulator. Compared to the coupled modeling of geo-mechanical simulator - dynamic flow simulator, the IPDM is a much simpler approach to use and also enables engineers to evaluate the impact of key operating conditions on individual well's PI.
Implementation of Artificial Lift Systems to Produce High GOR Wells
Authors: Mali Prasanna , Al Abdullah Hashem , Al Kandari Hamad
Published: October 2020

It is imperative to produce very high GOR wells to sustain production from matured fields. ESP and PCP are major lift modes in KOC. These lift systems can handle up to 50% of free gas, when used along-with standard gas separators. Therefore, there is a need for advanced lift systems, which can help to sustain production and run-life of equipment, when free gas at pump intake is more than 50%. Objective of the present work is to share our experience, with regard to evaluation and implementation of suitable ESP and PCP systems to produce very high GOR wells.

In this regard, study of suitable ESP and PCP systems, which can handle very high gas rates, is done. Based on this study, two technologies, namely, ‘ESP with advanced down-hole multiphase gas handler’ and ‘PCP system, designed to handle very high gas rates’, are considered for pilot implementation. Both these systems are capable to handle 75% of free gas. Suitable candidate wells, where envisaged free gas at pump intake is more than 50%, are selected for these pilots. Performance of these lift systems are monitored during the pilot period and results are analyzed.

Candidate well selected for the pilot of ‘ESP with advanced down-hole multiphase gas handler’, was on self-flow, before installation of this system, with an oil rate of 600 b/d and GOR of 750 scf/barrel. The system has performed exceedingly well during the pilot period of 6 months and peak oil gain of 1100 b/d, is recorded during the pilot. Candidate well selected for the pilot of ‘PCP system, designed to handle very high gas rates’, was not flowing, before installation of this system. Estimated GOR is 900 scf/barrel. Excellent system is performance is observed during the pilot period of 6 months. Peak oil gain of 500 b/d, is reported during the pilot period.

The study enlightens efficacy of these specific lift systems to enhance or sustain production on long-term basis, under high GOR environment. Both these lift systems can be used for efficient exploitation of mature fields. The study can serve as a valuable reference for all operators, for production of very high GOR wells, which need either ESP or PCP, as a lift mode.
Influence of the Reservoir Rocks Sedimentation and its Mineral Content on the Properties of BS10 Reservoirs in the Gubkin Oil and Gas Region
Authors: Alina Malyarenko , Artem Kotenev , Maxim Kotenev
Published: October 2020

The group of BS reservoirs in the Gubkin oil and gas region is characterized by the fact that the water cut in the well production is ahead of the oil production by more than 12%. The increase in the dynamics of watering of BS10 strata in the zones of lack of underlying water is associated with its breakthrough from the injection wells. The reason for this is the insufficiently effective system of stimulation of the reservoir - the inability of injected water to displace oil from the reservoir. This problem is directly related to the geological factor, the variability of reservoir properties.

The study of the material composition of reservoir rocks in order to assess the reservoir properties and their influence on the displacement coefficient has been carried out.

Research objectives include statistical analysis of changes in clay content from porosity and permeability of rocks of the BS10 reservoir formation; establishing the effect of clay on the permeability of the reservoir.

For the BS10 reservoir group of the Gubkin oil and gas region, it was found that in highly porous hydrophobic reservoirs with a low clay content, displacement is less intense compared to hydrophilic low permeability reservoirs.
A Fast Method to Estimate the Correlation Between Confining Stresses and Absolute Permeability of Propped Fractures
Authors: Al Balushi Faras , Dahi Taleghani Arash
Published: October 2020

Depletion of oil and gas reservoirs during production from fractured wells, or fluid injection through frack-packs may cause significant changes in the effective stress that proppants experience inside the fractures. Previous studies have shown that closure stress may change absolute permeability, however, deriving this relationship requires time-consuming and costly experiments that need to be repeated with the change of proppant or field parameters. Here, we propose a methodology to estimate absolute permeability magnitudes of the propped fracture direction by just using limited knowledge about grains' geometry. In this study, Lattice Boltzmann Methods (LBM) is used to simulate fluid flow to resemble flow in propped fractures under reservoir conditions. Due to the large number of particle and complexity of the sitting of proppant particles next to each other, intensive computational power is required to carry out simulations. Therefore, a parallelized LBM code is utilized to accelerate computations. The three-dimensional granular geometry was constructed from two-dimensional micro-Computed Tomography images. The geometry was then used as an input for the finite element analysis to simulate grain deformation/sliding upon applying different stresses on the samples. The captured deformation of the grains' geometry was then exported to the LBM code for calculation of permeability. Upon increasing confining stress on the samples, the proppant particles began to deform, slide on each other and the pore network evolved. While the standard API cell measures only conductivity changes under different normal stresses, the presented method gives a greater advantage by allowing determination of the simultaneous effect of normal and shear stresses on the components of the permeability of propped fractures. It is believed that parts of complex fracture networks may experience some shear stresses, but these effects could not be measured in the lab easily. Preserving core samples with the same conditions for a long time is not feasible. Therefore, using LBM, we present a fast and reliable method to measure absolute permeability of proppants during flowback and production using limited data in the form of micro-CT images or 3D images of the grains forming proppant packs.
Integrated Systems Approach Benefit of Optimizing Drill Bit Design with Rotary Steerable System Drive Mechanism
Authors: Bone Kim , Spencer Reed
Published: October 2020

An operator, drilling a 6-in horizontal production section in an offshore African field, observed diverging directional drilling steering behaviour that resulted in a round trip non-productive time (NPT) event. Being a mature field of known drilling performance and no significant structural or lithological variations, the interval was planned for one run with a Rotary-Steerable-System (RSS) bottom hole assembly (BHA). During the horizontal drilling of a particular well, the BHA began to build inclination, and all attempts to correct trajectory resulted in incremental build. Initial root cause indications were a malfunction in the RSS due to opposite steering behaviour and not a geological explanation. To complete the remaining drilling interval, the drill bit design was changed and the steering unit replaced with standby inventory. Drilling was resumed and the horizontal geosteering interval was completed with responsive directional control to the downlinked commands through the same reservoir geology.

Extensive root cause analysis that combined in-depth bit and BHA modelling, physical RSS tool workshop testing, and detailed plotting of all surface and downhole data, verified possible malfunctions and identified potential negative steering behaviour. Proprietary digital simulation tools modelled the BHA bending behaviour and build up rates. Simulations of bit-BHA interactions in formation scenarios were run to define build and/or drop capabilities. Different drill bit designs were evaluated through the modelling iteration process to understand the observed field responses.

Inspection and physical tool testing confirmed that the RSS tool was fully operational without any issues. Modelling matched the actual field outcomes in which drill bit features contributed to the observed lack of steering responsiveness, delivering drilling in a direction opposite to downlinked commands. An extended gage length bit drilled a 3.3deg/100ft build up rate, with an average 93% downward steer force, when a drop rate of 6.0deg/100ft was expected. Applying the new drill bit design with key gage features corrected the well trajectory with a 65% reduction in steering force. After 0.45hours of directional corrections, subsequent drilling kept precise target inclination enabling a 56% rate of penetration (ROP) improvement compared to the first run.

Quality wellbore placement and NPT risk reduction can be achieved by utilizing proven and state-of-the-art digital simulations that combine bit with BHA and formation during the pre-planning phase to ensure appropriate drill bit designs are harmonized to the BHA and directional requirements. This paper illustrates the benefits when applying and adverse risk when not applying an integrated systems approach.
Multi-Basin Case Study of Real-Time Perforation Quality Assessment for Screen Out Mitigation and Treatment Design Optimization Using Tube Wave Measurements
Authors: Merry Hoagie , Dalamarinis Panayiotis
Published: October 2020

The scope of this work is to introduce a technology that measures perforation effectiveness on a stage by stage basis before the hydraulic fracturing process begins. The measurement utilizes surface generated tube waves to interrogate the perforated section of the wellbore. We present three case studies demonstrating how "low perforation quality alerts" mitigate operational issues, achieving the deployment of appropriate stimulation treatments for several operators in the Eagle Ford, Haynesville, and Niobrara formations.

The reflections of tube waves are analyzed to characterize perforation effectiveness on a stage by stage basis. This methodology is non-intrusive, infinitely repeatable and can be performed in the short time interval between removing the perforating equipment from the well and beginning the fracture treatment process. The operators in our study were alerted to stages with a high likelihood of pumping issues such as high treating pressure, screen outs, or low proppant volume placement. Real-time measurements flagged these stages as having poor wellbore connectivity to the reservoir.

Prior to pumping, the operator and crew in the field were alerted to the stages that showed low perforation quality. This allowed modifications to the stage design, such as additional acid, sweeps, finer proppant, gel, increased pad, lower rate, or an additional perforation run. In the cases where changes were made to the design, the objective of mitigating pumping problems due to poor perforation performance was a success. In all the cases where preventive design changes were not implemented, downhole difficulties were experienced resulting in sub-optimal stage execution and/or screen outs. Cost savings in the range of $300,000 on some wells were achieved due to the mitigation of pumping problems associated with poor wellbore to reservoir connectivity.

Perforation quality and reservoir rock geomechanics play a dominant role in hydraulic fracturing operational success or failure. Although there have been extensive studies focusing on the role that perforation diameter plays on treatment efficiency, these studies do not adequately consider the importance of the perforation tunnel (depth and quality of perforation penetration into the near well region). Having real-time, non-intrusive, field-based data that provides a direct measurement of this essential element can influence the execution of the hydraulic fracture design. This mitigates the costly exercise of recovering from a screen out and improves the likelihood of a productive stage.
Interwell Fracturing Interference Evaluation of Multi-Well Pads in Shale Gas Reservoirs: A Case Study in WY Basin
Authors: He Youwei , Guo Jianchun , Tang Yong , Xu Jianliang , Li Yanchao , Wang Yong , Lu Qianli , Patil Shirish , Rui Zhenhua , Sepehrnoori Kamy
Published: October 2020

Severe fracturing interference in multi-well pads has been identified in shale gas reservoirs. The gas production of affected multi-fractured horizontal wells (MFHWs) decrease a lot and is hard to restore for most wells even after fracturing fluid flowback. Currently, well interference caused by fracturing operations has become the most important factor affecting the shale gas production. However, the mechanism of fracturing interference and its quantitative impact on gas production in shale gas reservoir are not clear.

The aim of this work is to assess the mechanism and dominated factors of fracturing interference of multi-well pads in shale gas reservoirs, and evaluate the impact of interwell fracturing interference on shale gas production. Firstly, field data in WY Basin are applied to calculate the ratio of impacted wells to newly fractured wells and understand the influencing degree and recovering degree of gas production. The main controlling factors of fracturing interference are determined and the interwell fracturing interacting types are presented. Furthermore, the production recovering potential for impacted wells are analyzed. Finally, some suggestions for mitigating fracturing interference are provided.

The impact degree and recovering degree of gas production are divided into three categories. The dominated factors of fracturing interference include well spacing, pressure of the affected wells before interference, gas production before interference, and flowback ratio of fracturing fluid. The influencing degree of gas production can be estimated by using the generated equations of impact degree of gas production per well spacing (IDGPs) or impact degree of gas production per flowback ratio (IDGPf) Another novel finding is that 70% of affected parent wells belong to adjacent well pad compared with the newly fractured child well. The interwell fracturing interference is divided into four types, including pressure interference without direct communications between two MFHWs (Type I), fracturing interference through natural fracture/secondary fractures (Type II), fracturing interference through hydraulic fractures (Type III), and direct communication between hydraulic fractures and wellbore of adjacent well (Type IV). Fracturing communication through hydraulic fractures or secondary/natural fractures are more common, and the impact on well safety and production performance increases from Type I to Type IV. Therefore, the fracturing parameters need to be optimized to reduce the fracturing interference. This study can provide reasonable suggestions for infill well optimization, fracturing design, and interwell fracturing interference mitigation to achieve the highest gas recovery of all multi-well pads in shale gas reservoirs.
Frac Hit in Complex Tight Oil Reservoir in Ordos Basin: The Challenges, the Root Causes and the Cure
Authors: Wang Lipeng , Du Xianfei , Qiu Kaibin , Wu Shunlin , Zhuang Xiangqi , Bai Xiaohu , Wang Lizhi , Pan Yuanwei
Published: October 2020

Severe frac hit incidents were encountered during stimulating horizontal production wells in a pilot pad of a tight oil reservoir in Ordos basin. The reservoir is interbedded, highly heterogeneous both vertically and horizontally as result of gravity flow deposition. This raised a big concern on the stimulation treatment size and well spacing of the pad and further implication on the field development plan of the reservoir. A deep understanding of root causes and an effective frac hit prevention and mitigation strategy were much needed to address the problem.

A multidisciplinary team was formed to investigate the problem. Initial analysis on the frac hit incidents showed that the frac hits were not correlated to well spacing, or stimulation volume as frac hits only occurred at certain stages out of those with the same stimulation volume or well spacing. Then the study turned the focus to investigating the problem from the geological and geomechanical perspective through leveraging a 3D high definition (HD) geological and geomechanical model.

The detailed investigation revealed that the root causes of the frac hits were multiple folds: Existence of natural fracture corridors led to frac hit of wells in much longer distance.Alignment of hydraulic fractures among horizontal wells also increased the chance of frac hits as the result of alignment of perforations among horizontal wells.Asymmetrical propagation of hydraulic fracture (e.g., deviated to one side of horizontal laterals increased the chance of frac hit as the result of heterogeneous sand body and in-situ stress field.)Lack of vertical fracture containment resulted in the crossing-layer frac hits.

With the good understanding of the root causes of frac hits, a frac hit risk map was generated based on the 3D HD geoscience model, which highlighted high frac risk zone in the pad. The frac hits observed from subsequent stimulations of the horizontal wells occurred only in the high frac hit risk zone, which validated the frac hit risk map. Based on the findings from the study, the frac hit prevention and mitigation strategy was developed.
Automated Lease Operating Statements for Cost Optimization and Reserve Evaluation Using Artificial Intelligence
Authors: Klie Arturo , Klie Hector , Vuong Duc , Chaban Fady , Chaban Nidal
Published: October 2020

The objective of the present work is to streamline the analysis of Lease Operating Statements (LOS) with advanced learning paradigms from artificial intelligence (AI). The proposed approach aims at the: (a) consolidation of disparate expenses data; (b) timely expense assessment at field, pad or well level; (c) prevention and quick identification of negative cash flow trends (d) robust LOS predictions; and (e) optimal budget planning under uncertainty. To achieve this objective, a LOS acceleration platform was developed for the automatic integration of volume estimation with Lease Operating Expenses (LOE). Historical data from production volumes, revenues, price differentials, LOEs, marketing and transportation costs, taxes, CAPEX, P&A costs and others considered to strengthen the accuracy of individual expense categories and the overall LOS predictive model. The predictive model consists of a combined blend of analytical and machine learning models that allows to reliably forecast trends and proactively detect anomalies that may be negatively affecting the operational cash flow. Intuitive and portable visualizations allow a quick interpretation and communication of results among engineers and managers. The implemented platform fills a gap between traditional LOS analysis and preemptive expense planning involving many wells and expense categories that are hard to track daily. It is shown that the proposed approach can lead to savings of the order of 30% in incurred expenses.
Improving Well Economics Through Reservoir Characterization and Optimized Completion Design in Horizontal, Unconventional Reservoir Development
Authors: Schubarth Stephen , Bozeman Tim , Lestz Robert
Published: October 2020

Completion designs in horizontal, multi-stage wellbores is a complex problem and has many potential scenarios depending on the desired well performance. Up until recently the industry has been focused on improving early-time productivity; 90-day cumulative production, 24-hour initial potential (IP) or achieving a target daily rate. Many operators are now refocusing on a desired economic outcome; achieving free cash flow, improving return on investment and increased net present value. Our paper will discuss the effects that different completion design changes have on these desired results and present examples of past well performance and new well performance utilizing these changes.

Our methodology will include the analysis of producing well histories to determine average reservoir permeability and completion effectiveness as described by the number of created, producing transverse fractures and the average effective length of those fractures. From this characterization of the reservoir and past completions we will forward model completion design scenarios to determine the effect changes in design have on the performance parameters we wish to achieve. The process used includes hundreds of completion design scenarios which are compared to each other to find the design which maximizes the desired economic result. Multiple examples of this will be presented.

Increasing early-time production performance has resulted in increasing capital expenditure. Several completion design parameters lead to increases in this performance parameter (IP); increasing lateral length, increasing stage volume and decreasing stage spacing. However, all of these changes increase the capital spent on the completion. To achieve improved economic performance parameters, balancing the total capital expenditure against the revenue generated becomes the primary focus. What may have worked in the past to meet past goals does not work to meet new, economic focused goals. The most important parameter we must know when designing the completion is the reservoir permeability. This value determines the reservoirs ability to deliver hydrocarbons to the well and how effective the reservoir can be to creating the revenue necessary to pay for the capital spent. Identifying the balance between capital spent and revenue generated leads to completion designs that reduce well cost while maximizing economic parameters versus maximizing early-time production alone.

The results and conclusions from this paper will run contrary to the industry's past trends in completion design. However, the focus on economic improvement can be a pathway to our industry to achieve better economic results. Our industry has provided increased energy independence for our nation, but far too many companies are suffering financially while doing so. Billions of barrels of oil have been produced, yet many are going broke.
Case Study: Intelligent RSS Improving Drilling Performance on Three Mile Laterals in the Appalachian Basin
Authors: Tilley Jim , Nair Vakkeyil Naveen , Hamoudi Lotfi
Published: October 2020

Longer lateral length in unconventional wells has proven to increase hydrocarbon recovery and lower overall development costs for oil and gas operators in North America. The application of rotary steerable system (RSS) technology aids this effort by improving and sustaining penetration rates to reduce well time and maximize reservoir drainage. A new "intelligent" RSS has been deployed to enhance drilling efficiency with industry-leading operating limits, automated steering controls, and a global lifecycle maintenance system to drive reliability.

The new RSS bottomhole assembly (BHA) consists of an advanced downhole motor, a matched bit design, and high-speed geosteering control. An automation process helps operators meet the challenges of drilling time and wellbore placement in long laterals. High rate of penetration (ROP), rotation per minute (RPM) and weight on bit (WOB) limits are controlled by sophisticated sensor technology that enables precise steerability. The RSS platform includes multiple directional sensors and real-time processors capable of reducing hole tortuosity and optimizing reservoir exposure while drilling. It also includes automated inclination and azimuth control features. Furthermore, a structured, pre-job design process evaluates critical engineering risks and mitigates those risks using a systematic methodology.

The initial testing of the new RSS on a test beam qualified its ability to operate at high speeds and high loads. Multiple holes were drilled in cement blocks to benchmark performance. Beam testing was followed by full-scale testing at a dedicated drilling rig, where over 40,000 ft was drilled in a variety of configurations, including vertical, curve, and lateral trajectories. After the extensive field testing program, the intelligent RSS was utilized to drill multiple ~14,000-ft, 8.5-in. lateral hole sections in the Utica Shale. A significant reduction of drilling time was achieved in these long laterals, with an average ROP of 245 ft/hr. A record 5,300 ft were drilled in 24 hours, beating previous wells by 600 ft. The activation of inclination and azimuth control delivered a smooth, high-quality wellbore with minimal tortuosity. Inclination was maintained within +/− 0.5° and azimuth +/− 1°. The outstanding performance of the innovative BHA enabled the longest one-run lateral to be drilled with an RSS.

The new, intelligent RSS has successfully demonstrated it can decrease well time and drilling costs, while increasing wellbore placement accuracy. The improvement in drilling efficiency and lateral length capability will enhance unconventional asset value across North America, and elsewhere around the world.
Integrated Reservoir Characterization with Spectroscopy, Dielectric and NMR T1-T2 Maps in Freshwater Environment, Case Studies from Alaska
Authors: Shi ZhanGuo , Akindipe Tunde , Wendt Brett L. , Garcia German
Published: October 2020

Hydrocarbon identification and evaluation with conventional triple-combo logs and Archie-based equations in freshwater environments has been a challenge for petrophysicists. In the first case study from Alaska, shallow reservoir information from non-Archie based technologies including total organic carbon (TOC) from spectroscopy measurements, hydrocarbon volume derived from dielectric and NMR logs were used for quick hydrocarbon bearing zones identification, decision making on fluid sampling and early determination of oil properties. The high-resolution NMR T1-T2 maps, derived from the latest inversion, revealed the presence of viscous oil.

Another targeted formation is a laminated shaly sand sequence, also in a freshwater environment. The array resistivity logs show a low contrast profile and it is more challenging for fluid identification and evaluation. Relatively high resistivity anisotropy from 3D induction suggest the formation is potentially hydrocarbon bearing. TOC from spectroscopy and water filled porosity from dielectric compared to the total porosity are direct indicators of the presence of hydrocarbons in the formation, but the interpretation is complicated by water-based mud (WBM) filtrate invasion. The stacked T1-T2 maps generated immediately after NMR logging for selected intervals, clearly showed the presence of light oil. This was confirmed by the latest wireline formation testing in the next logging run.

Instead of quantitative formation properties evaluation this paper focuses on qualitative fluid identification with non-resistivity-based technologies, particularly with T1-T2 maps. NMR T1-T2 fluid mapping has been traditionally used for unconventional reservoir and is well discussed in various literatures. In our case, this technique has been applied for conventional reservoirs in the freshwater environment.
Experimental Evaluation of Solvents for Improved Oil Recovery in Shale Oil Reservoirs
Authors: Ozowe Williams , Quintanilla Zach , Russell Rod , Sharma Mukul
Published: October 2020

Despite recent technological advances in horizontal drilling and hydraulic fracturing, primary production from unconventional oil reservoirs is usually less than 10 percent of the original oil in place. This low recovery has made it essential for operators to test methods that aim to improve recovery efficiency and recover incremental oil from existing wells. One of such methods is the use of solvents for improved recovery in shale oil reservoirs via cyclic gas injection also referred to as a "huff-n-puff" process. Previous laboratory studies have demonstrated promising results on unpreserved shale core plugs using CO2, N2 and C1 as solvents, however, none have shown recovery results using ethane or higher molecular weight gases for cyclic gas injection.

This paper presents improved oil recovery results from cyclic gas injection experiments using C2 and n-C5 in comparison to N2 on unpreserved Eagle Ford crushed samples and core plugs with n-C12 as the oil phase. Core plugs and crushed preserved shale samples were vacuum dried and then re-saturated with n-C12 at 6000 psi for 48 hours, then huff-n-puff experiments were conducted using n-C5, C2 and N2. Recovery factors obtained using n-C5 at injection pressures of 2000 psi and 5000 psi showed that oil recovery increased with an increase in surface area to volume ratio. For the same surface area to volume ratio, oil recovery is higher at higher injection pressures. A comparison of recovery factors between C2 and n-C5 show that C2 was more effective than n-C5 because it showed higher recovery factors at 2000 psi and 5000 psi injection pressure. NMR T2 distributions also showed that C2 was able to recover more oil from the small and intermediate pore sizes without leaving behind any residual fluid in the small pores unlike n-C5. The higher recovery factors obtained for C2 are a result of its lower viscosity and because it is able to expel more oil out of the shale pore space as it flashes to gas upon depressurization compared to n-C5. Comparing N2 recovery results to both C2 and n-C5 at 5000 psi injection pressure demonstrated that N2 yielded the lowest recovery factors because it is essentially immiscible with the oil. These experimental results can be used as the basis for scaling up to field scale huff-n-puff gas injection pilots.