bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Application of Downhole Seismic Imaging in Identifying Natural Fracture Systems; An Integrated Approach Utilizing Core and Borehole Image Data
Authors: Amer AimenAi , Sajer Abdulazziz , Al-Adwani Talal , Salem Hanan , Abu-Taleb Reyad , Abu-Guneej Ali , Yateem Ali , Chilumuri Vishnu , Goyal Palkesh , Devkar Sambhaji 
Published: March 2019

Abstract
Producing unconventional reservoirs characterized by low porosities and permeabilities during early stages of exploration and field appraisal can be challenging, especially in high temperature and high pressure (HPHT) downhole conditions. In such reservoirs, the natural fracture network can play a significant role in flowing hydrocarbons, increasing the importance of encountering such network by the boreholes.
Consequently, the challenge would be to plan wells through these corridors, which is not always easy. To add to the challenge, well design restrictions dictate, the drilling of only vertical and in minor cases deviated wells. This can reduce the possibility of drilling through sub-vertical fracture sets significantly, and once seismic resolution is considered, it may seem that all odds are agents encountering a fracture network.
This article addresses a case where a vertical well is drilled, in the above-mentioned reservoir setting, and missed the natural fracture system. The correct mitigation can make a difference between plugging and abandoning the well or putting it on production.
The technique utilized is based on a borehole acoustic reflection survey (BARS) acquired over a vertical well to give a detailed insight on the fracture network 120 ft away from the borehole. Integrating this technique with core and high-resolution borehole image logs rendered an excellent match, increasing the confidence level in the acoustically predicted fracture corridors.
Based on these findings new perforation intervals and hydraulic stimulation are proposed to optimize well performance. Such application can reverse the well decommissioning process, opening new opportunities for the rejuvenation of older wells.
Multi Stage - Open Hole Completions: Continuous Successes in Placing Multiple Fractures in a Single Tight Gas Sandstone
Authors: Arevalo Alfredo , Buenrostro Adrian , Espinosa Mauricio , Harbi Abdulaziz 
Published: March 2019

Abstract
Tight sandstone reservoirs under this project have been a challenge to stimulate due the high breakdown pressure required to create the fracture, and a challenge on production recovery due fast decline observed in some of these wells. Exploring Multi Stage Fracturing completion in horizontal wells in these tight sandstone reservoirs increases the overall reservoir exposure to stimulation treatments by Hydraulic Fracturing, and expects a better and longer production performance. This paper evaluates the recently deployed Open Hole – Multi Stage Fracturing completions (OH-MSF) over tight sandstone gas reservoirs.
KSI Field Fast Track to FID
Authors: A. Al-Hashemi A. , Jabri Gharbi , Khudhuri S. , Marjibi I. Tobi , Hamed Tope 
Published: March 2019

Abstract
This paper discusses KSI project which is the first in-house study on QA Cluster, aimed to accelerate delivery. This abstract spotlights the surface & subsurface integrated work results on fast track from DG1 to FID within 1.5 years by utilizing data from analogue fields & replication of surface concept & facility design.
For the subsurface, an extensive analogue study was conducted. Then simple 1D analytical model used to generate well by well forecast. A small box model constructed to test different water flood development sensitivity & define the optimum spacing, type of pattern & water injection depth where the outcome compared with 3D simulation model & they match.
For the surface, a small Well Test Unit (WTU) is leased to maximize the oil production from KSI field & provide an early view of reservoir waterflood uncertainty. The full field surface facility concept is a replication from H analogue field. This replication leads to accelerate the on stream date by 24 months.
KSI is a green field which is one of the Lower Shuaiba pancake reservoir where it transferred from exploration with a high UTC project & very long schedule.
It was identified that the key critical success factors are accelerating initial oil production & reducing Capex by using analogue field data, optimized phased-development, replication for facility design, & optimized well design & well spacing.
Comparing the KSI field with analogue fields, resulted on chosen a line-derive waterflood as development concept which was validated by running a box model.
The good match achieved between 1D analytical model used at DG2 & 3D simulation model used at DG3 indicated that the analytical model is sufficient as promise for Field
Development Plan (FDP). However the numerical model will be needed for easily future waterflood management.
Changing the well completion design from single horizontal to dual lateral is resulted in reducing the CAPEX (Drillex) by 54%. The replication of surface facility resulted on achieving two years ahead of initial schedule.
The in-house study & replication of surface facility led to reduce the total project CAPEX 7%, increase NPV by 77%, reduce the project UTC by 21% & accelerated the schedule by 2 years as below figure 1
Hydraulic Fracturing Treatments in the Permian Basin: Distillation of Best Practices in the Spraberry and Wolfcamp Formations
Authors: Othman Amro Abdelrahman , Amao Abiodun Matthew 
Published: March 2019

Abstract
Hydraulic fracturing is being used globally to unlock hydrocarbon resources in unconventional reservoirs. However, the efficient utilization of resources in most treatment designs is debatable. A study of hydraulic fracturing treatments in 56 vertical and horizontal wells representing 1,151 treated stages in the Wolfcamp and Spraberry formations of the Permian Basin in West Texas was conducted in this paper. Intrinsic treatment strategies and operational methodologies used by the well operators were evaluated with the objective of extracting and deducing insights into criteria that characterize operational virtuosity, efficiency and inefficiency.
Treatments of vertical wells were studied with 25 wells in both formations, in the Midland basin. 18 wells were studied in Spraberry horizontal well treatments, while horizontal Wolfcamp treatments were studied with 13 wells in the Delaware basin. Well completion records, treatment reports and well files were reviewed for treatment parameters on each well. The study concentrated on indices like, proppants types and amount; fluid types and volumes pumped; treatment rates and pressures; productivity and treatment cost. Empirical and statistical analysis using correlations and analysis of variance were then conducted and used to identify the best practices that actively and positively increased production rates and decreased production costs in each of these formations and well types.
The Spraberry is very fine-grained sandstone, siltstone and carbonates with interbedded shales in the studied area. The Delaware Wolfcamp is a complex formation with carbonates, mostly limestone, and interbedded organic rich mudstones in varying proportions. Results show that the use of 20/40 white as a proppant is not economical, in both formations either in vertical or horizontal wells, because of the huge increase in treatment costs. Use of 100 mesh and 40/70 white proppant in both formations was amenable to better production rate. Results show that usage of crosslinked gel increases treatment costs drastically. Slickwater was found to improve production rates, although huge volumes were needed for large proppant amounts. The use of HCl acid as spearhead in formations with high carbonate content like the Wolfcamp was found to improve treatment results. Increasing the number of stages increases treatment cost, but increasing the perforated intervals correlates positively with production rate.
Performance Analysis of Acid Fracturing Treatments in a Sour Gas Carbonate Reservoir
Authors: Eze Samuel Okorie , Ayoola Olakunle T. , Hussain Baleegh A. , Khaldi Humoud H. 
Published: March 2019

Abstract
This paper presents a new insight into the factors that affect the initial productivity of Acid Fracturing (AF) treatments in a sour gas carbonate reservoir.
Acid Fracturing is a stimulation technique used to improve the productivity or injectivity of wells. It involves pumping acid into a formation at above fracture pressure, and can treat deep into the formation. Despite the benefits of acid fracturing, conditions are not always favourable for acid fracturing. This could be due to reservoir or well limitations for example, very low formation permeability, formation temperature especially in dolomite formations, and/or well completion integrity.
In this application, a total of 12 wells were stimulated after initial completion by acid fracturing. The treatment design is a single stage Pad-Acid treatment which involves pumping 1) pre-acid, 2) gelled water, 3) main acid, 4) diverter, 5) repeat of steps 2 to 4 as required, then followed by 6) a post-acid flush and 7) over-flush. Optimisations made on the treatment design as the campaign progressed include use of specially formulated diversion system, ramp up of acid injection rates and volumes.
The analysis of pre and post stimulation productivity performance show the following: An average productivity improvement of 9 times the pre stimulation productivity,A direct relationship between productivity improvement and increasing the rates/volumes of acid injection during the treatment,That treatment volume did not always result to productivity increase but the manner and sequence of fluid injection were of greater effect on productivity.Fluid diversion system blended with particulates show greater increase in productivity than wells treated with diversion systems with no particulates.
Based on the results, it can be concluded that, an optimized method of ramping up acid injection rate/volume as well as careful selection of diversion system can lead to productivity improvement of up to 9 times the pretreatment productivity in Carbonate reservoir stimulation.
Recognizing Abnormal Shock Signatures During Drilling with Help of Machine Learning
Authors: Ignova Maja , Matheus Justo , Amaya Darwin , Richards Edward 
Published: March 2019

Abstract
Drilling generated shocks and vibrations (torsional, axial, and lateral) are among the main causes of failures in the drilling industry; because they affect the rate of penetration, directional control, and wellbore quality. Rotary steerable system tools are equipped with measurement devices such as magnetometers, accelerometers, and shocks and vibration sensors from which statistical information is obtained, such as root-mean squared error, maximum peaks, and peak levels. From these statistics, whirl, bit bounce, and stick/slip severity are inferred. Often, the derived statistics are not enough to distinguish between normal drilling versus abnormal drilling for a location in the wellbore or to determine whether the shocks and vibrations are the result of poor drilling practice, formation disturbances, or mechanical failures of the bottomhole assembly, including the bit.
Machine learning methods were used for analyzing the high-frequency radial shock burst data, which compresses and classifies the data; i.e., good drilling and abnormal drilling. The method is capable of further clustering the data into whirl or no whirl, bit-bounce or no bit-bounce, formation change or no change, and/or faulty equipment and parts; thus, assist in the robust post-failure analysis of existing data sets and prevent catastrophic failures in real time and improve the trajectory control.
Rock Mechanical Characterization of Unconventional Source Rocks
Authors: Lee Ji Soo , Jacobi David , Alnajar Zainab 
Published: March 2019

Abstract
Rock strength is an important property to measure for determining its effect on drilling, wellbore stability, and potential well completions associated with hydraulic fracturing of unconventional reservoirs. The industry traditionally relies on elastic moduli measured from core plugs to determine the stress anisotropy to predict the extent of hydraulic fractures. This provides some estimate of the expected stimulated rock volume in unconventional reservoirs. Rock strength however based on the finding of this study could also be a factor that needs to be considered for designing hydraulic fracturing plans to stimulate production from the rock volume. However, rock strength is difficult to measure in highly laminated source rocks comprising unconventional reservoirs. The existence of weak, horizontal bedding planes within the laminated rock fabric creates anisotropy that influences the rock strength values obtained. Moreover, drilling and extracting intact horizontal, vertical, and diagonal core plugs to test the effects of anisotropy on the rock strength is difficult to achieve. Often, the plugs fracture during extraction due to the laminated fabric. To compensate for the challenge of extracting intact core plugs from these lithofacies, this study proposes that rock strength can be estimated without the need of extracting core plugs. Instead, a new method is demonstrated where non-destructive rebound hardness measurements are collected across a specifically gridded, slabbed rock surface to provide an estimate of the rock strength. The collected rebound hardness values are converted into unconfined compressive strength values using an empirical algorithm. The empirical algorithm was developed using unconfined compressive strength values measured from core plugs correlated to rebound hardness numbers measured from the face of those same core plugs. The derived unconfined compressive strength values are then used to represent the source rock's mechanical characteristics which can be presented as a contour map across the surface. These results have been correlated to the mineralogy of the rock surface, quantified and mapped using micro-X-ray Fluorescence elemental maps. Differences in unconfined compressive rock strength can then be correlated to the changing mineral content of the rock surface. This non-destructive estimation of rock strength was conducted to address the challenge of relating core scale measurments to reservoir scaled analysis to improve hydraulic fracturing designs in unconventional source rocks.
Real-Time High Data Rate Bidirectional Fiber-Optic Telemetry for Harsh Environments
Authors: Stark Daniel , Schaecher William , Maida John , Wiecek Bogdan 
Published: March 2019

Abstract
Data telemetered in harsh environments are traditionally compressed, filtered, and processed before being transmitted, if telemetered at all. The user then has limited information about the status of monitored systems; however, the user's knowledge can be improved by real-time raw information transmission.
In harsh environments, data are traditionally transmitted over dedicated lines, through variations in a power source, or wirelessly. These methods suffer from signal attenuation and dispersion over long lengths, leading to lower data rates. Optical fiber systems, however, have low attenuation, little dispersion, and can use a variety of communication schemes, such as varying signal amplitudes, phases, or wavelengths. In particular, quadrature amplitude modulation (QAM) or pulse amplitude modulation (PAM) methods common for fiber telemetry backhauls can achieve greater bandwidths in harsh environments to realize real-time data retrieval without the need for processing.
This paper reviews the current state-of-the-art fiber-optic telemetry systems for harsh environments and discusses a proof-of-principle demonstration using higher-order optical modulation techniques to obtain data rates that are orders of magnitude greater than those achieved by electrical telemetry equivalent systems. The demonstration consisted of optical and electrical components that operated at temperatures up to 200°C and transmitted data along 18 km of fiber with over 10 dB of optical margin. The current state of the project and its application to a wide variety of possible field uses are explored.
Additionally, the use of fiber communications is reviewed to help improve data delivery to users in the energy industry, a topic of growing interest. It also highlights the innovative approaches for developing real-time, high-data-rate, bidirectional optical fiber telemetry for harsh environments.
Evolution of a Lab-Optimized ASP Formulation for a High Temperature and High Salinity World-Class Clastic Reservoir in the Middle East
Authors: Al-Murayri Mohammed T. , Kamal Dawood S. , Baroon Hadeel F. , Shahin Gordon T. , Shukla Shunahshep R. 
Published: March 2019

Abstract
This paper discusses the evolution of an Alkaline Surfactant Polymer (ASP) formulation for a challenging sandstone reservoir in North Kuwait. This is an on-shore reservoir, with no gas cap, featuring a moderately high residual oil saturation to waterflood of approximately 20-30%. Moreover, the reservoir has a light oil (API Gravity 30-35) with low Total Acid Number (TAN) and is undergoing a maturing waterflood – thus making it amenable to ASP implementation. However, the high reservoir temperature (90°C), in-situ brine salinity (&gt;250,000 ppm) and divalent ion concentration (&gt;20,000 ppm) place the reservoir at the upper threshold of ASP technology implementation.
In addition, the oil has a high emulsification tendency and was observed to form very stable brine-oil emulsions when sampled from the field. This was due to the high concentration of heavier components such as waxes, resins and asphaltenes, some of which are surface-active and tend to interfere with the action of synthetic surfactant at the oil-water interface making ASP formulation development for such oils very challenging. Furthermore, addition of polymer to improve the ASP/oil mobility ratio caused phase separation of the aqueous phase likely because the water-soluble polymer preferentially dissolves in brine while pushing out the hydrophobic surfactant. The methodology followed in this work was to select a surfactant with a high alkyl tail length to solubilize the heavier hydrocarbons in the oil, blend it with a more hydrophilic surfactant to increase the optimal salinity to match the target injection water salinity and overcome the surfactant phase separation issue when polymer was added to the formulation. The ASP formulation was successfully tested in the field in a Single Well Chemical Tracer Test (SWCTT) and was successful in reducing the remaining oil saturation from 0.24 ± 0.02 at the end of water flood to 0.06 ± 0.05 at the end of the chemical flood.
Analysis of Water/Oil Ratio in Complex Carbonate Reservoirs Under Water-Flood
Authors: AlOtaibi Shabab , Cinar Yildiray , AlShehri Dhafer 
Published: March 2019

Abstract
Knowing the source of excessive produced water from oil wells in complex carbonate reservoirs under water-flooding sheds light for engineers to optimize development plans and better design remedial actions for enhanced water management. Although oil-well water production has been studied extensively, and hence different techniques have been introduced, only a few have addressed the source of produced water. Chan (1995) was among first to develop diagnostic plots to analyze the water-oil ratio (WOR). Chan plots (double-logarithms of WOR & its time derivative WOR’ vs. time) can, for example, indicate whether produced water comes through water coning or water channeling. Yet, these plots were obtained from conceptualized black-oil simulations which should be validated by more diverse field data. In this paper, Chan diagnostic plots were scrutinized using a suite of diverse field data that include permeability, production logs (PLT) and pressure transient analysis (PTA) from many vertical and horizontal wells with different completions. In this study, we demonstrated that more benefit of using Chan plots to diagnose water source can be gained through incorporating other field data into the analysis such as core data, PLT, and PTA. The diverse examples presented in this study revealed that near-well reservoir characteristics play a major role in shaping WOR & WOR’ plots rather than the well being whether vertical or horizontal. We suggest that, for a more accurate Chan analysis, only the production data at constant total liquid rate should be used. The second derivative of WOR may be utilized to identify the concavity of the WOR curve or the slope of the WOR’ curve.
Sour Fluids Management Using Non-chemical H2S Scavenger
Authors: Dhulipala Prasad , Jani Jagrut , Wyatt Melanie , Leidensdorf Jeremy , Chakraborty Soma 
Published: March 2019

Abstract
The objective of this study was to develop and apply a non-chemical based environmentally preferable hydrogen sulfide scavenger that addresses secondary issues caused by current chemical scavengers like triazine and glyoxal and to confirm its ability to mitigate sulfide in different applications. Recombinant DNA and protein expression technologies were exploited to develop this novel H2S scavenger.
This non-chemical scavenger (NCS) is generated by cloning the cDNA sequence from a thermophilic organism and expression of the encoded protein in suitable vector. Non-chemical based formulation was developed and blended in a pilot plant. The efficacy of the scavenger was evaluated in sour brine, crude oil and mixed production fluids from different sources. Sulfide concentrations before and after reactions in headspace were measured by using Dräger gas detection tubes (ASTM D5705). Corrosion testing was performed using kettle tests. Field assessment of the scavenger was carried out by treating sour oil at the Bakken oil field as per the field testing plan.
In this study, H2S mitigation was addressed using a novel non-chemical scavenger generated from thermophilic bacteria from lab scale to pilot scale. Functional studies conducted by treatment of soured brine and oil revealed 72% and 90% reduction in H2S concentration respectively. The scavenger showed a 75% reduction of sulfide in simulated mixed production samples containing 30:70 ratio of brine and oil. Limited testing of this scavenger in field showed reduction of headspace sulfide from 400 ppm to 2 ppm. In addition, the field data showed less than 0.5% BS&W. The scavenger also showed no significant increase in corrosion during the scavenging reaction.
These studies confirm that this novel non-chemical scavenger can be successfully used to mitigate H2S in various systems without causing adverse effects that were seen with chemical scavengers. A non-chemical scavenger has several advantages such as meeting environmental regulations, reducing, or eliminating secondary effects like solids formation, corrosion, scaling, and health hazards that are associated with current chemical scavengers.