bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Impact of Regional vs. White Sand on Long Term Multi-Fractured Horizontal Wolfcamp Well Production
Authors: Shelley Robert 
Published: September 2022

Abstract
Proppant selection is an important aspect of hydraulic fracture completion design. Recently, the industry has moved toward the use of lower cost regional sand as the propping agent for multi-fractured horizontal well completions in the Permian Basin Wolfcamp. An evaluation of early time production data indicates that there is minimal difference in first year well production with the use of regional vs white sand. These comparisons are the subject of SPE 199751, Shale Frac Designs Move to Just Good Enough Proppant Economics. However, does this conclusion hold up when evaluating longer term well production. The subject of this paper is a follow-up study which incorporates re-allocated production and new data to facilitate the evaluation of regional vs white sand on longer term well production.
A database consisting of reservoir, completion, frac and production data from 297 Multi-Fractured Horizontal Wolfcamp B Completions was assembled. New production allocations and previously unavailable production data are incorporated to allow comparisons of two and three year cumulative oil, gas and water. A Self Organizing Mapping (SOM) methodology was used to determine relevant well groups of like reservoir characteristics in which valid comparisons of regional vs white sand well production can be made. This type of approach is intended to normalize on differences in well reservoir characteristics and compensate for inconsistencies in the data that could impact comparisons of regional vs white sand well production.
Within this database there is a wide variation in reservoir characteristics and completion design. These wells were completed by many different operators using lateral lengths up to a high of almost 15,000 ft., proppant intensities from 500 to 4,000 lb./ft. and frac stage spacing from 59 to 769 ft. In the performance of this project, it became apparent that reservoir characteristics along with completion design factors have a dominate impact on multi-fractured horizontal Wolfcamp B well production. It was critical to factor out these non-sand type factors to quantify the influence of regional sand usage. As we would expect, wells with the most pay thickness, greatest permeability along with relatively higher pore pressure, effective porosity and low water saturation have the greatest potential for hydrocarbon production. The most productive completion types have longer length laterals, more frac stages (closer spacing), more proppant and fluid intensity.1
Based on this evaluation, the use of lower cost regional sand as the fracturing propping agent results in a negative 4% impact on first year well production. After 3 years of production this negative impact has increased to over 7% compared to white sand completions. In areas with better reservoir quality rock, the negative impact of regional sand use can be more significant. Conversely in areas with poor reservoir quality rock, the use of regional sand use has a less significant impact on well production.
Quality Isotope Analysis at the Wellsite: Two Case Studies that Validate GC-C-IRMS Mud Gas Isotope Logging for Deepwater Exploration and Development
Authors: Furghieri Bylaardt Caldas Priscila , Snatic Jonathan , Kronenberger Kurt 
Published: September 2022

Abstract
Geochemical analysis of gases produced during the drilling process is a common study on oil and gas exploration and development wells. This process typically includes the use of gas sample containers or other vessels that allow for single point samples to be collected for shipment to an offsite laboratory. Laboratories use high precision devices to obtain valuable information for reservoir characterization including stable carbon isotope ratios. In recent years there have been efforts to provide similar analyses during the drilling process, using ruggedized equipment suitable for wellsite deployment. This paper demonstrates that a Gas Chromatograph-Combustion-Isotope Ratio Mass Spectrometer (GC-C-IRMS) analyzer, using similar technology to what is most widespread in offsite laboratories (Dashti et al, 2018), can be successfully deployed to the rig site.
This type of advanced gas analysis, commonly known as Mud Gas Isotope Logging (MGIL), provides continuous sampling of stable carbon isotopes of methane (δ13C1), ethane (δ13C2), and propane (δ13C3). The service, performed with a GC-C-IRMS analyzer, was proven and validated for an operator through two case studies. 98
The first case compares real time data with discrete gas sample tubes analyzed in an offsite laboratory. It shows how accurate results are possible, even with the presence of artificial gases generated by drill bit metamorphism (DBM) (Wenger et al, 2009). This example also demonstrates how the service enabled immediate analysis for operational decisions by indicating the presence of biodegraded thermogenic fluid.
The second case study demonstrates how this wellsite service could corroborate the geological prognosis in a complex field influenced by salt tectonics. In this basin an upthrown reservoir changed the typical behavior observed in conventional wells of increased oil maturity with depth. Stable carbon isotope readings obtained in real time, integrated with cuttings analysis, indicated the presence of out of section lithology. This information allowed for estimating the thermogenic fluid maturity of reservoirs and diagnosis of geological formations that were out of sequence in terms of age (uplifted).
Analysing Down Hole Scale Deposition in Offshore ESP Wells: A Case Study on Formulating an Effective Mitigation and Inhibition Strategy
Authors: Uniyal Rishabh , Jaruhar Suman Kumar , Sarkar Manoj Kumar , Devshali Sagun , Parida Dibyajyoti , Bhoye Sushil , Kanwar Manav 
Published: September 2022

Abstract
Analysis of recovered scale samples deposited within Electrical Submersible Pumps in offshore wells was carried out. The primary objective includes the identification of root cause of deposition and suggesting remedial measures for removal and prevention.
Many wells in an offshore field in ONGC are facing an acute problem of decrease in pump efficiency and ultimate failure of Electrical Submersible Pumps due to deposition of inorganic scale. The methodology for carrying out the study consists of a detailed Compositional Analysis of a sample of scale retrieved from inside the ESP of one of the affected wells. Additionally, X-Ray Diffraction analysis of the debris and compositional analysis of produced water sample from the same well were also carried out. The results of the experiments were corroborated by software simulation in Scale Prediction Software. Experiments were also carried out to identify a suitable inhibitor which could operate at high bottom hole temperatures experienced in the affected wells for preventing any future deposition.
Based on the compositional analysis of the scale and simulation runs using the produced water analysis, it was established that deposition of hard, adherent sulphate scale was the primary reason behind the choking and subsequent failure of the ESPs. In-situ conditions leading to deposition of the scale including variations in the operating environments and the effect of pump sizing have also been discussed.
The paper analyses the problem of inorganic scale deposition in offshore ESPs of ONGC utilising actual scale samples retrieved while dismantling the pump. An attempt has been made to provide an insight into the driving mechanism behind deposition inside the pump and various factors leading to it. The paper also details extensive lab experiments carried out to identify suitable inhibitors for high temperature application.
A Systematic Approach to Simulation Hydraulic Fracture Propagation by Implementing Natural Fracture Modeling in Unconventional Reservoir
Authors: Qu Jianhua , Zhang Boning , Deng Qi , Luo Bo , Xue Heng , Huang Jing , Huang Xingning , Guo Songyi 
Published: September 2022

Abstract
Junggar Basin is a typical superimposed oil and gas bearing basin in western China, where Mahu Depression is the largest oil-gas accumulation zone and exploration area. On April 23rd, 2013, the peak daily oil production of Mahu No.1 well reached 52 tons, achieving a significant breakthrough. On August 23rd of the same year, the high yield of Mahu No.18 well opened a new chapter of oil and gas exploration in the slope belt of the Mahu Depression. Since then, CNPC (China National Petroleum Corporation) has increased the exploration and development process of the Mahu Depression, establishing the exploration theory and technology system of the conglomerate reservoir in the depression area. Finally, the exploration and discovery of a supergiant conglomerate oil field (1 billion tons) were achieved. However, a series of development problems were exposed, which was due to the lack of in-depth research on reservoir geomechanics and distribution law for natural fractures: 1) The Hydraulic fracture propagation law is not clear; 2) In the process of fracturing, there exists an obvious phenomenon of non-uniform fluid inflow and expansion in various clusters of fractures; 3) Serious interference occurs between wells during the fracturing operation. Therefore, it is necessary to strengthen the study of geomechanics and distribution law for natural fractures in unconventional oil reservoirs, so as to provide technical support for the optimization of the horizontal well fracturing scheme, improvement of well pattern deployment parameters, and adjustment of oil reservoir development scheme, which further leads to cost reduction and development efficiency improvement while increasing single well production in unconventional oil reservoirs.
Systematic Evaluation of Stoneley Mobility and Its Petrophysical Application Conditions
Authors: Saif Mohamed , Ma Shouxiang , Naqeeb Ibrahim , Ghosh Krishnendu , Abdallah Wael 
Published: September 2022

Abstract
In this study, a comprehensive workflow of estimating formation mobility using Acoustic Stoneley wave was evaluated, with diverse subsurface conditions and drilling environments including hole size, mud type, formation lithology, and formation fluids. The outcome of this exercise aimed to compare inverted Stoneley mobility and that from formation testing. The parameters tested with high significance on Stoneley mobility are mud acoustic slowness, mud acoustic attenuation, and the mud cake membrane stiffness. Analysis applied on these parameters showed a variation of uncertainty as well as sensitivity to mobility, with mud cake membrane stiffness being the most uncertain, and mud acoustic slowness and attenuation being the inputs with high sensitivity.
The findings of this study suggest that Stoneley mobility inversion can be used to quantitively estimate a continuous mobility log in clastic formations, a great value with many applications such as optimizing formation testing depths and, on a multiwell scale, in permeability characterization. It is therefore recommended that the Stoneley mobility be integrated in integrated studies for clastic reservoirs, serving as an intermediate measurement between the high resolution and accurate core permeability and formation testing mobility, and that derived from Drill Stem Tests; all are discrete measurements. It is also observed that, when comparing with formation testing results, applying the same Stoneley mobility inversion in heterogeneous carbonate formations seems challenging, an area for further study.
A Novel Correction Method for Pressure Transient Analysis Results of Horizontal Wells in Stratified Carbonate Reservoir with High Permeability Zone
Authors: Ma Ruicheng , Zhao Zeqi , Li Yong , Zou Chunmei , Hu Dandan , Chen Yajing , Zhang Leifu 
Published: September 2022

Abstract
High permeability zone (HPZ) formed by sedimentation and diagenesis has been founded in numerous oil fields in Middle East. Meanwhile, horizontal well have been applied universally in these oil fields. To obtain wellbore status and reservoir properties, pressure transient analysis (PTA) is a convenient and economic surveillance method. However, when it comes to stratified reservoir, heterogeneity between layers should be noticed. Log-log plot of actual data will be far form ideal analytical solution with homogeneous hypothesis. Therefore, the interpreted results would not be representative for wellbore and reservoir condition. In this research, we proposed a novel correction mathematical model and correction workflow for PTA results of horizontal wells in stratified carbonate reservoir with HPZ. This research innovatively imports production performance analysis and other monitoring methods to PTA in the view of flow field. This new approach holds favorable potential to provide accurate wellbore status and reservoir parameters for making the most use of surveillance budget.
Significance and Implications of Diagenetic Nodular Anhydrite on Sandstone Reservoirs Quality
Authors: Khalifa Aqeel , Tarabbia Paul , Alrowaie Mohammad A. , Soua Mohamed 
Published: September 2022

Abstract
Diagenetic nodular anhydrite observed in fluvio-aeolian-lacustrine and glacial sandstones has significant implications to reservoir quality. This type of nodular cement is spatially and volumetrically variable within these reservoirs. Its presence impacts subsurface formation evaluation and porosity calculations. Thus, the investigation of these nodules was carried out using: core image analysis; thin sections petrography; micro computed tomography (MicroCT) scans; bulk rock X-Ray Diffraction (XRD); sulfur & strontium isotope analyses. Where core was unavailable, geochemical data and resistivity-based image logs were used to expand the anhydrite characterization to derive field wide distributions.
Bulk rock XRD and thin section-based petrographic studies indicate that the mineralogy of the study sandstones is dominated by quartz (&gt;90%), with minor clay, and the presence of variable amounts of localized anhydrite as diagenetic nodular cements. The habitat of anhydrite nodules displays a substantial size variation, with nodules ranging from millimeters to several centimeters in scale. The larger nodules are easily identified visually in core samples and on borehole image logs. To investigate the origin of the anhydrite, sulfur and strontium isotope analysis were used to understand the relative timing of the nodule's development within the paragenetic sequence.
Results from the sulfur and strontium isotopic analyses are consistent with the understanding that the anhydrite nodules are a late stage emplacement. A semi-quantitative "Anhydrite Abundance Index" (AAI) was calculated across key wells within the fields to establish the anhydrites regional distribution. The AAI uses the dry weight fraction of calcium and sulfur from geochemical logs to determine the volume of anhydrite. These volumes were further calibrated to volumes obtained through geochemical analysis of core samples, which is key to calculating the correct anhydrite volume required for formation evaluation. Regional distribution mapping created from this volume data suggests a widespread presence of the anhydrite nodular cementation.
Understanding the relative abundance of anhydrite volumes is important when investigating the reservoir quality, especially if underestimating its presence may affect log-based porosity calculations and subsequently permeability calculations. The in-place quantification of the anhydrite nodular cement in 1D also enabled research to further the understanding of post-depositional, geochemical and geographic controls on the subsurface modelling and reservoir quality prediction.
An Evaluation of Pressure Control Methods During Riser Gas Handling with MPD Equipment Based on Transient Multiphase Flow Modeling and Distributed Fiber Optic Sensing
Authors: Wei Chen , Chen Yuanhang , Santos Otto , Kunju Mahendra , Mahmud Shahriar , Almeida Mauricio , Sonnemann Paul 
Published: September 2022

Abstract
During the past decade, the increased use of Managed Pressure Drilling (MPD) equipment has significantly improved the safety and efficiency of gas influx management. However, it is still not clear to the industry what should be the safest and most effective pressure control method for removing gas influxes out of a riser. The objective of this study is to perform a systematic evaluation of different pressure control methods for riser gas handling, including the constant surface backpressure method, the constant riser bottom pressure method, and the fixed choke and constant outflow method.
A transient multiphase flow simulator based on a Drift Flux Model was developed to simulate riser gas handling events in a Water Based Mud (WBM) system. Multiple sets of full-scale experimental data were used for the calibration and validation of the simulator. In the full-scale experiments, riser gas events were simulated by injecting gas into the bottom of an experimental well, followed by applying different pressure control methods. Besides conventional downhole and surface pressure and flow measurement instrumentations, a Distributed Fiber Optic Sensing (DFOS) system was used for the high-resolution monitoring of gas influxes in the annulus.
The performance of different pressure control methods was evaluated based on the simulation results, including the behaviors of surface and riser bottom pressures, peak surface outflow rates, and the time required for riser gas handling. The numerical simulations carried out in this study can help better understand the different pressure control methods and improve the design of riser gas handling strategies.
Case Study: Enhanced Compression Pumps with Mixed Flow Stages for Unconventional Shale Plays
Authors: Martinez Villarreal Paola , Escobar Patron Katherine , Rosales Ballesteros Eder 
Published: September 2022

Abstract
The challenges of unconventional reservoirs have driven electric submersible pump (ESP) providers to continue making improvements to the mechanical design of the pump stages. These improvements enable covering wider operating flow ranges and maximizing production without the need to replace the artificial lift system with a different method such as gas lift or rod pumps.
In 2016 and 2020, two new pump types were introduced as a solution for unconventional wells. This case study summarizes the results of the analysis of 52 ESPs installed with the new pump types in the Midland Basin from 2019 to 2021 for a leading operator in the basin. The operator's well test data showed a declining production averaging from 1,300 to 100 BFPD, with water cut from 40% to 99% and gas-oil ratios up to 9,000 SCF/STB.
This paper presents the results of how the re-engineering of a standard mixed-flow stage becomes a solution to improve the performance of the ESPs when producing from unconventional shale plays where the downhole environment is extremely harsh. The re-engineering of the standard mixed-flow stage produced a stage characterized by high hydraulic performance and superior efficiency. The study's conclusions can also be applied to conventional shale plays with more benign conditions.
To develop the new stages used in the two new pump types, an engineering team conducted an extensive study considering the available run life data and the results of the top failure modes of the ESPs when operating at low flow ranges in unconventional wells. The engineering team considered a stage design to optimize the operation in the low-flow-rate region by a better distribution of downthrust and stress management of the pump's internal components.
Electronic Data Captured at Bit is Utilized to Improve Drilling Practices and Performance in Laterals
Authors: Lepe Juan Pangtay , Anderle Seth , Anderson Victoria , Greene Allen , Lane Tyler , Grandstaff Brad 
Published: September 2022

Abstract
When drilling laterals, the horizontal portions of an unconventional well, one of the primary unknowns has been how much weight and torque is effectively being transferred from surface to bit, and how that affects performance. The introduction of high-frequency vibration, motion, and strain sensors integrated into the drill bit has yielded new insights into drill bit behavior. This paper presents a recent field study, in which these downhole measurements were utilized to develop a solution for improving drilling performance in the lateral section.
Operators often use computer-controlled "auto-driller" settings, either weight on bit (WOB) or rate of penetration (ROP) mode, to drill through lateral sections. While higher instantaneous ROP can be achieved by using WOB mode, it can create inconsistent performance, thus, leading to dysfunctions.
In this case, a high resolution, at-bit vibration, motion, and strain sensor was introduced to characterize dysfunctions and drill bit behavior in the interval of interest. Data was captured during multiple drilling modes across multiple wells to conduct an engineering analysis and determine appropriate drilling practices to enhance drilling efficiency.
The same drill bit equipped with the at-bit sensor was used to drill two lateral intervals with the same target formation in the same well pad. Both lateral runs made it to total depth (TD) in a single run.
During the first run, overall higher dysfunctions (axial and lateral+torsional) were observed when WOB mode was used in contrast to ROP mode. Therefore, for the next run, ROP mode was recommended along with a higher ROP setting. The same consistent vibration levels were observed but at an overall higher ROP, while also improving the drill bit's dull condition.
When drilling in WOB mode, spikes in downhole WOB were observed on connections when tool joints would pass through the rotating head. However, this was not shown on surface WOB measurements.
When cross-plotting differential pressure and torque-on-bit, a gradual decrease in torque was observed throughout the run with similar differential pressure indicating a loss in drilling efficiency.
As a result, when applying the optimized drilling practices learned from these runs using the innovative at-bit sensor, a 20% overall ROP increase and dull conditions improvement were observed.
This paper describes how novel features were placed in an at-bit sensor capturing continuous 1,024 Hz data to visualize dysfunction, motion, and strain downhole, and to determine the effect of drilling practices, and how they are related to drilling performance, leading to recommendations that improve performance. Detailed field data from different runs, in which revised drilling practices helped manage dysfunctions and enhance overall drilling performance, will be presented.