bluuebunny/crossref_metadata_2025_split huggingface dataset:
Leveraging the Power of Historical Data and Already Emerged Technologies to Unlock the Unconventional Resources Potential in MENA Region
Authors: Sharma P.. , Khanapurkar P.N.. N. , Thakar A.. 
Published: February 2021

Abstract
With worldwide increases in the demand for hydrocarbons, finding and developing unconventional resources has become a global necessity. Outside North America, shale gas discoveries have been made in recent years; however, significant commercial production has been limited to North America. Finding and developing unconventional resources outside North America is the next big challenge for the oil and gas industry.
Although the reported potential of unconventional gas resource volumes in the Middle East and North Africa (MENA) region is almost similar in size to that in the US, exploration and development of such resources is currently limited. Unconventional reservoirs have very different and distinct requirements from conventional reservoirs. The more “unconventional” a targeted resource, the more difficult it is to develop. Furthermore, for these difficult resources, highly specialized technologies have to be applied because of the unique requirements.
Key challenges specific to the MENA region include the following: Limited exposure to unconventional sources leads to lack of infrastructure and high cost.Reservoir characteristics (rock and fluid properties) and geomechanics.Implementation of directional/horizontal drilling and completion technologies suited for the region.
The most challenging aspect is using hydraulic fracturing (fluid availability and management, fracturing fluid and proppant selection, fracturing design, equipment) as it incurs the highest cost and deploys the maximum technological efforts. This paper highlights these associated challenges in developing unconventional resources and offers a potential approach to evaluate unconventional resources. Additionally, public data are reviewed and emerged technologies are used to unlock the potential of unconventional resources in MENA.
A major service company has exhaustive and varied data from different geographies and resource types captured in its MENA state-of-the-art data center. A potential approach is included that extrapolates historically available data relevant to directional drilling, fracture treatment design and analysis, and fluid management to MENA conditions to facilitate understanding and overcome challenges associated with unconventional resources.
Combined Application of Pressure Coring and Desorption Analysis for Barnett Shale Gas Evaluation
Authors: Cerri R.. , Di Martino S.. , Balossino P.. , Gioacchini L.. , Colombo I.. , Spelta E.. , Bartosek M.. , Bjorum M.. 
Published: February 2021

AbstractShale gas reservoir quality evaluation is a technical challenge as conventional log interpretation methods and even core measurements may be inadequate or inaccurate. Only through a robust integration of core and logs data, a reliable estimation of the gas in place can be obtained and the interval with the best petrophysical and geomechanical characteristics (sweet spot) identified.Total GIIP estimation is derived from core and log analyses and can be complemented by measuring desorbed gas from selected core samples. Total gas content is the combination of measured and estimated gas components: lost gas, desorbed gas and residual gas. Lost gas is the most critical component being usually extrapolated from desorbed data to time zero using linear and/or polynomial curve fitting.Total gas can now be directly measured by using a new controlled pressure coring technology able to capture a full sized core and retain all the hydrocarbons contained in the rock, eliminating gasses and/or liquids lost during conventional coring techniques.The characterization of the lower Barnett Shale described in this paper was achieved by coring the whole sequence: several samples from conventional cores were taken for desorption analysis and three pressure cores were placed to target the main shale facies identified from the integrated reservoir model.Core gas data from both desorption and pressure coring were integrated for a more reliable total gas estimation; consistent relationships among handling time, gas content and method used for deriving lost gas were also observed. Obtained total gas values were in good agreement with calculated gas volumes from logs.In addition, the combined application of pressure coring and desorption analysis in the Barnett Shale has allowed to improve well site procedures for optimal core data acquisition and to define the best approach for a robust shale gas evaluation.
The Impact of Nanoparticles Adsorption and Transport on Wettability Alteration of Intermediate Wet Berea Sandstone
Authors: Li Shidong , Torsæter Ole 
Published: February 2021

AbstractNanoparticles as part of nanotechnology have drawn the attention for its great potential of increasing oil recovery. From authors' previous studies (Li et al., 2013a), wettability alteration was proposed as one of the main Enhanced Oil Recovery (EOR) mechanisms for nanoparticles fluid, as adsorption of nanoparticles on pore walls leads to wettability alteration of reservoir. We conducted a series of wettability measurement experiments for aged intermediate-wet Berea sandstone, where the core plugs were treated by different concentration and type of nanoparticles fluid. Nanoparticles transport experiments also were performed for core plugs with injection of varying concentration and type of nanoparticles fluid. Pressure drop across the core plug during injection was recorded to evaluate nanoparticles adsorption and retention inside core, as well as desorption during brine postflush. Both hydrophilic silica nano-structure particles and hydrophilic silica colloidal nanoparticles were utilized in above two experiments.The results of wettability alteration experiments indicated that hydrophilic nanoparticles have ability of making intermediate-wet Berea sandstone to be more water wet, and basically the higher concentration the more water wet will be. And different type of nanoparticles has different effect on the wettability alteration process. For nanoparticles transport experiments, the results showed that the nanoparticles undergo both adsorption and desorption as well as retention during injection. Pressure drop curves showed that absorption and retention of nano-structure particles inside core was significant while colloidal nanoparticles did not adsorb much. Permeability impairment was observed during nano-structure particles fluid injection, but on the contrary colloidal nanoparticles dispersion injection made core more permeable.
Geological Model Coupled with Geomechanics Makes an Impact on Fracturing Stimulation and Field Development Strategy of a Tight Gas Formation in the Sultanate of Oman
Authors: Bate Kevin , Lane Mauricio , Moiseenkov Alexey , Nadezhdin Sergey 
Published: February 2021

Abstract
Appraisal drilling of a recently discovered Cambrian-aged gas field in Oman is indicating that the field may have significant amounts of gas locked in a challenging deep, hot, and highly pressured reservoir environment. The low porosity and permeability values of the Amin reservoir allow the classification of the reservoir as a tight gas sand. The variability of reservoir properties, both spatially and vertically, makes it difficult to standardize perforation and fracture stimulation design which, in turn, complicates delineation of a development plan for the project. One of the difficulties relates to uncertainty in vertical propagation of hydraulic fractures. Fracture height based on evaluation of radioactive tracer logs indicates that vertical barriers to fracture propagation may relate to specific geologic zones in the reservoir. The mapping of the reservoir zones into undeveloped areas of the field would allow selection of primary and secondary production targets based on the specific physical properties of the individual zones. To assume that no barrier to fracture propagation exists between separate production units may lead to attempts to stimulate them synchronously, which would be disadvantageous for several reasons, such as premature screenouts and incomplete coverage of gas-bearing layers. Reserves booking and allocation can also be jeopardized should the fractures propagate into undesired zones.
Understanding Unusual Diagnostic Fracture Injection Test Results in Tight Gas Fields - A Holistic Approach to Resolving the Data
Authors: Naidu R.N.. N. , Guevara E.A.. A. , Twynam A.J.. J. , Rueda J.. , Dawson W.. , Moses E.. , Rylance M.. 
Published: February 2021

Abstract
Hydraulic fracturing is a commonly used completion approach for extracting hydrocarbon resources from formations, particularly in those formations of very low permeability. As part of this process the use of Diagnostic Fracture Injection Tests (DFIT) can provide valuable information. When the measured pressures in such tests are outside the expected range for a given formation, a number of possibilities and questions will arise. Such considerations may include: What caused such inflated pressures? What is the in-situ stress state? Was there a mechanical or operational problem? Was the test procedure or the test equipment at fault? What else can explain the abnormal behaviour? While there may not be simple answers to all of these questions, such an experience can lead to a technically inaccurate conclusion based on inadequate analysis.
A recently completed project faced just such a challenge, initially resulting in poor hydraulic fracturing efficiency and a requirement to understand the root causes. In support of this, a thorough analysis involving a multi-disciplinary review team from several technical areas, including petrophysics, rock/geo-mechanics, fluids testing/engineering, completions engineering, hydraulic fracture design and petroleum engineering, was undertaken. This paper describes the evolution of this study, the work performed, the results and conclusions from the analysis.
The key factors involved in planning a successful DFIT are highlighted with a general template and a work process for future testing provided. The importance of appreciating the impact of the drilling and completion fluids composition, their properties and their compatibility with the formation fluids are addressed. The overall process and technical approach from this case study in tight gas fields, will have applicability across similar fields and the lessons learned could help unlock those reserves that are initially deemed technically or even commercially unattractive due to abnormal or unexpected behaviour measured during a DFIT operation.
Predicting Barik Formation Production from Seismic, Khazzan Field, North Oman
Authors: Stiteler T. Chris , Philip M. J. 
Published: February 2021

Abstract
Prediction of areas of good reservoir deliverability has been achieved by the integration of production data, petrophysical analysis, palaeocurrent analyses, core data and 3D seismic data. The key data in this comparative analysis are derived from a petrophysical workflow, which is calibrated to surveillance data and dynamic well test data. These data include porosity, porosity-thickness (PhiH), permeability, and permeability-thickness (KH).
The results of this initial integration are compared with extractions from numerous seismically-generated attribute maps at each well location and used to define preferred seismic PhiH and KH maps. These can be utilised for well planning and further integrated with geocelluar reservoir models.
Additional geological interpretation confirms that trends within the Barik depositional system can be recognised on seismic, defining areas which have the potential to have similar thickness, depositional facies and most likely, similar potential production within them.
This has led to optimisation of the drilling schedule, allowing rescheduling of wells from areas that are now understood to be potentially poor to areas having higher potential, thus increasing efficiency.
Additionally, this work indicates that wells having low production on test conform to areas where low production is predicted, but some wells in the predicted areas of moderate to high production show higher prediction errors than other wells within the same area. This methodology clarifies where differences between predicted and actual measurements occur, allowing the second phase of integration aimed at improving predictions and mitigating risks.
Performance Evaluation of A Horizontal Well with Multiple Fractures Using A Slab Source Function
Authors: Yang Daoyong , Zhang Feng , Styles John A. , Gao Junmin 
Published: February 2021

Abstract
A novel slab source function has been formulated and successfully applied to accurately evaluate performance of a horizontal well with multiple fractures in a tight formation. A semi-analytical method is then applied to solve the newly formulated mathematical model by discretizing the fracture into small segments, each of which is treated as a slab source, assuming that there exists unsteady flow between the adjacent segments. The newly developed function has been validated with numerical solution obtained from a reservoir simulator and then extended its application to a field case. The pressure response together with its corresponding derivative type curves has been reproduced to examine effects of number of stages, fracture conductivity, and fracture dimension under various penetration conditions. The fracture conductivity is found to mainly influence early-stage bilinear/linear flow regime, while a smaller conductivity will force more fluid to enter the toe of the fracture than its heel. Penetrating ratio will impose a significant impact on the pressure response at the early stage, forcing the bilinear/linear flow to the radial flow.
Improvement of Impact Strength of Polyglycolic Acid for Self-Degradable Tools for Low-Temperature Wells
Authors: Okura Masayuki , Takahashi Shinya , Kobayashi Takuma , Saijo Hikaru , Takahashi Takeo 
Published: February 2021

Abstract
Recent increases in the stage count of hydraulic fracturing has increased the time and cost for well completion. Simplifying time-consuming processes is crucial for economic success. The use of degradable materials for components of downhole tools has several advantages, such as eliminating or simplifying the recovery process of the tools. Polyglycolic acid (PGA), a hydrolyzable polymer, is a suitable material for these components. PGA has already been used in frac balls because of its high mechanical strength and appropriate degradation characteristics. However, in low-temperature wells close to the glass transition temperature of PGA, there are problems with tool breakage during installation or stimulation because of the changes in the mechanical properties of PGA at low temperatures.
This paper focuses on the improvement of the impact strength of PGA. A study of modifiers identified the additives that are highly compatible with PGA. Morphological studies of mixtures showed finely dispersed additive domains within a PGA matrix. The impact strength of the mixture was twice as high as that of neat PGA. A formulation was identified that optimized the impact strength while retaining degradability, processability, and machinability similar to that of neat PGA. The improvement of the impact strength broadens the range of applications that PGA tooling is suitable for and helps to reduce the cost and time of the well completion process.
Direct TOC Quantification in unconventional Kerogen-rich Shale Resource Play from Elemental Spectroscopy Measurements: A Case Study from North Kuwait
Authors: Joshi Girija K. , Acharya Mihira N. , Steene Marie Van , Chakravorty Sandeep , Darous Christophe , Al-Azmi Mejbel S. , Dashti Qasem 
Published: February 2021

Abstract
The deep organic-rich calcareous Kerogen of North Kuwait, a continuous 50ft thinly alternating carbonate – organic-rich argillaceous sequence, is not only a source rock but has gained importance as potential reservoirs themselves of typical unconventional category. Resource play or Kerogen characterization relies on quantifying total organic carbon (TOC) and estimating accurate mineralogy. This paper describes the first attempt to directly measure total organic carbon of the Limestone-Kerogen sequence.
For the present study, empirical estimations of TOC have been carried out based on conventional log measurements and nuclear magnetic resonance (NMR). The introduction of a new neutron-induced capture and inelastic gamma ray spectroscopy tool using a very high-resolution scintillator and a new type of pulsed neutron generator for the deep unconventional kerogen resources have provided a unique opportunity to measure a stand-alone quantitative TOC value using a combination of capture and inelastic gamma ray spectra. In this process, Inorganic Carbon Content (ICC) is estimated by using elemental concentrations measured by this logging tool in addition to measuring Total Carbon, and this value is subtracted from the measured total carbon to give TOC.
The advanced elemental spectroscopy tool measurements were first used to determine accurately the complex mineralogy of the layered carbonate and organic-rich shale sequence. Extensive laboratory measurements of core / cuttings data were used to calibrate the petrophysical evaluation and capture the heterogeneity seen on borehole image logs. The final analysis shows considerable improvements compared to conventional empirical estimation. Once the mineralogy is properly determined, the log-derived TOC matches very well with core measured TOC.
This technique has provided a new direct and accurate log-derived TOC for Kerogen characterization. The application has a potential to be used for CAPEX optimization of the coring in future wells. This technique can also be applied in HPHT and High-angle horizontal wells, which can overcome challenging coring difficulties in horizontal wells.
Unconventional Gas Simulation Strategy and Workflow
Authors: Adil Imtiaz , MoG Jamila M. , Harthy Badar Al , Sebastian Herbert M. , Adams John R. 
Published: February 2021

AbstractNumerous technical publications were written in recent years on the effectiveness of reservoir simulation modeling in developing a tight gas resource. These papers question the applicability of existing numerical simulation methodologies to hydraulically fractured unconventional gas reservoirs. The rapidly changing dynamic flow behavior that occurs as fluids move from poor quality reservoir to a highly conductive fracture and then feed into an infinitely conductive wellbore creates complex solutions which are difficult to fully resolve with conventional reservoir simulation techniques. The lack of well to well dynamic interference during early stages of the production stacks the additional uncertainties around connected gas volume to the wellbore, thereby, increasing the chances of sub-optimal investment decision on well spacing, infill wells and number of fracs during the early stages of the field development.This paper proposes a reservoir simulation strategy and the workflow for unconventional gas reservoirs. The strategy outlines the need to systematically move from simple to complex modeling solutions while creating a learning loop. It proposes an early modeling focus on single wells in small sector models to understand the impact of stimulation and well design related uncertainties. The paper also identifies a learning stage that allows a progression to the next stage of simulation i.e. sector models. The workflow identified in the paper also presents the disadvantages of how an untimely progression from sector to full field modelling can negatively impact final investment decisions and the field development strategy.BP has successfully applied this framework in North America and this strategy has been outlined for reservoir simulation related work in the Sultanate of Oman to develop unconventional gas resources in Block 61.
Proppant Transport? Viscosity Is Not All It's Cracked Up To Be
Authors: Gomaa A.M. , Gupta D.V.S. , Carman P. 
Published: February 2021

Abstract
Post-treatment production analyses for hydraulic fracturing treatments with conventional crosslinked gel often indicate that the treatments do not achieve the designed stimulation effectiveness, which could be attributed to non-optimal proppant placement and/or significantly damaged fracture conductivity. Although conventional crosslinked fluids are observed to provide good proppant suspension in laboratory environments, they might not provide the desired proppant transport under downhole conditions. Crosslinked fluids are known to be difficult to clean up, and thus are notorious for imparting gel damage to proppant pack and formation. Surfactant gels have been developed to mitigate some of the issues.
Viscosity measurements are used as the main tool to judge and optimize the performance of both polymer and surfactant based fracture fluids, especially their ability to transport proppant. While efficient proppant transport is essential for successful hydraulic fracturing, recent laboratory work has shown that viscosity alone may not accurately assess proppant transport. The objective of the paper is to investigate and determine the minimum rheological properties required for efficient proppant transport. Thus, combinations of rotational and oscillatory measurements were conducted to better predict the proppant transport characteristics. Also, proppant settling tests were conducted at static and dynamic conditions. A strong correlation was established between fluid's elasticity and its ability to suspend the proppant with a required minimum elastic modulus (G') value to be greater than viscous modulus (G”).
Experimental results show that for two fluids that both have a close viscosity value (similar power law parameters); one fluid with G'&gt;G” while the other one G'&lt; G”, the fluid that has G'&gt;G” behaves as semi-solid material where it deforms instead of flowing when shear stress is applied, while the fluid that has G”&gt;G', flows when shear stress is applied and time to flow depends on viscosity. A proppant particle in a fluid undergoes shear stress due to its density. Therefore, for the fluid G”&gt;G', proppant settles as the fluid moves around it and the speed of settling depends on fluid viscosity, whereas for the elastic fluid (G'&gt;G”), fluid elasticity does not allow the proppant to settle. This observation was confirmed for both polymer and surfactant based fracturing fluids. Additives can be divided into categories that may enhance or reduce fluid elasticity based on their effect on the internal structure of the fluids. For example, breakers tend to significantly reduce the fluid elasticity, even when viscosity reduction is minimized. Data obtained from this study can be used as a guideline to optimize and select the fluid that has ability to carry proppant for field treatment design.