bluuebunny/crossref_metadata_2025_split huggingface dataset:
Validating BHA Analysis Models with Real-Time Measurements for Improved Drilling Performance
Authors: Smith Mark , Broglie, P.E. Ryan , Gandikota Raju , Frenzel Mark 
Published: October 2020

Abstract
A West Texas operator historically used four to seven PDC bits to TD their Ward County, Wolfcamp B laterals. Formations there are lithologically more challenging when compared to the same interval in adjacent Reeves County. Drilling performance in Reeves County Wolfcamp A laterals averages approximately 1,091 Feet/Day while those in Ward County seldom make 600 Feet/Day. Often daily progress is less than that. The objective was to improve Ward County lateral drilling performance.
In the study presented here, we examined the BHAs, bits and motors in consecutive Wolfcamp B laterals on the same pad which used 7 and 5 bits to reach TD respectively. Several of these PDC bits were Damaged Beyond Repair (DBR) as illustrated later. We demonstrate the process of utilizing Time Domain Analyses (TDA) as an accurate method to identify and analyze the nonlinear, dynamic behavior of drilling systems. These enhanced models allow the engineer to explore a full range of alternative BHA responses based upon current drilling conditions. They account for most of the specific details of downhole equipment such as the bit, the rotary steerable systems (RSS) or steerable mud motor, the MWD and their interaction with the hole. The software used allows virtual sensors to be placed anywhere along the drill string to evaluate the dynamics for additional insights.
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.