bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effects of Variable Perforation Configurations on Proppant Trasport and Distribution in Slickwater Fluids
Authors: Alajmei Shabeeb , Miskimins Jennifer 
Published: October 2020

Abstract
This paper investigates the effect of variable perforation configurations on proppant transport, settling, and distribution across different perforation clusters in multistage horizontal wells. The results are compared to other previously published data (Ahmad and Miskimins, 2019) using different proppant sizes and densities. A 30-foot horizontal laboratory apparatus with three perforation clusters is used to simulate a multistage horizontal well. Low viscosity fresh water is used as the carrier fluid to transport the proppant. This research incorporates the influence of testing various injection rates and proppant concentrations on proppant transport of 100-mesh brown sand. Different perforation configurations are used to test the perforation effect on proppant transport using similar injection rates and proppant concentrations. A 200-gallon tank is used to mix the proppant before injecting the slurry mixture using a slurry pump. The apparatus also incorporates a variable frequency drive, a flow meter and pressure transducers. Sieve analysis is then conducted to identify the proppant distribution exiting from each cluster at different perforation configurations.
It commonly assumed that the injected proppant is distributed evenly across the perforation clusters and that the distribution of fluid and proppant is identical. However, this research shows that this is not always the case. The results show uneven fluid and proppant distributions between clusters when altering the perforation configurations, injection rates, and proppant concentrations. Sieve analysis also shows different size distribution of the settled and exited sand through different clusters and individual perforations. Such information is beneficial to understanding transport in horizontal, multi-stage completions and how such impacts the overall treatment efficiency.
Application of United Nations Framework Classification for Hydrocarbon Reserves and Resources Volumes for a Mature Oil Reservoir in Kuwait
Authors: Al-Ghnemi Mohammad , Al-Sane Amal , Dhote Prashant , Bora Anup , Al-Bahar Mohammad , Purewal Satiner , Walker Jacob , Dharanidharan Balagopal , Hornbrook John 
Published: October 2020

Abstract
United Nations Framework Classification (UNFC) for Energy and Mineral Resources is a unique instrument for harmonizing industry business processes, efficient capital allocation with policy framework and government oversights. The core competency of UNFC is focusing on objectives of Sustainable Development Goals (SDGs) while managing the natural resources required for the present and future needs of society.
The company manages the upstream oil and gas sector, with significant expertise in managing exploration and production of hydrocarbon resources in diverse geological, engineering, and commercial environment. Present day activities span a large spectrum from pure reconnaissance for resources to producing from very mature fields with increased geologic, engineering, and commercial complexities. KOC uses Resource and Reserves Management System (KOC-RMS) for accounting and reporting of reserves and resources, which is based on principles of Petroleum Resources Management System (PRMS). PRMS [AZ1]is a framework for classifying and categorizing estimates of petroleum reserves and resources and it is used by most of the upstream oil and gas companies worldwide.
UNFC provides common language for classification and reporting of solid mineral and petroleum resources, with main emphasis on socio-economic viability, technical feasibility, and maturity of a project. There have been continued efforts for bridging the gap between PRMS and UNFC systems, including the mapping of PRMS guideline updated in 2007 being to the UNFC system updated in 2009. This effort produced clearly marked similarities between the two systems and there is an effort currently underway to map the PRMS guidelines updated in in 2018 to the recently updated UNFC. This integration will help in comparing renewable energy resources with non-renewable energy.
The objective of the present case study is to assess the applicability of UNFC for Energy and Mineral Resources management system for a mature oil reservoir. The results of this UNFC case study identified producing, justified for development, and contingent projects with limited social or environment impediments to development.
The novelty of this study is the first known application of the UNFC approach to a petroleum reservoir of the Middle East and shows applicability to similar oil fields around the world. This approach can assist in the identification of all technical and non-technical aspects, such as social and environmental issues associated with development, and may be used to reflect the hydrocarbon resource maturation and reserves progression framework of a reservoir.
A Field Pilot of Huff-n-Puff Gas Injection for Enhanced Oil Recovery in Permian Basin
Authors: Ganjdanesh Reza , Eltahan Esmail , Sepehrnoori Kamy , Drozd Hunter , Ambrose Raymond 
Published: October 2020

Abstract
Unconventional oil wells exhibit rapid decline in oil production rate and low ultimate oil recovery, even though the lateral drilling and completion technology have advanced drastically in the past decade. The petroleum industry has been seeking to develop economic enhanced oil recovery methods to improve the overall recovery factor. The gas huff-n-puff process has been performed and shown the potential of improving the recovery factor from tight oil reservoirs. The objective of the study was to investigate the performance of huff-n-puff EOR in Midland Basin. The studied section of the field contains 2 horizontal producers. The wells produced on primary production for 3 years. The sector was selected as a candidate for performing gas huff-n-puff to enhance the oil recovery factor. Recently, this huff-n-puff EOR project has been performing in the studied volatile oil field in the Permian Basin.
In this study, compositional reservoir simulation was used to predict the performance of enhanced oil recovery. A sector model was built for the area selected as the prospective candidate for gas injection. An Embedded Discrete Fracture Model (EDFM) was used for modeling the fractures and stimulated reservoir volume (SRV). A Peng-Robinson equation-of-state model was prepared based on the early produced samples from the wells. A thorough phase behavior analysis was conducted to understand the miscibility of the injected field gas and the in-situ fluid. A Bayesian Assisted History Matching (AHM) algorithm with a neural-network-proxy sampler was applied to quantify uncertainty and find the best model matches for the pair of wells in the Wolfcamp B and C formations of Midland Basin.
From 1400 total simulation runs, the AHM algorithm generated 100 solutions that satisfy predefined selection criteria. Even though the primary production were the same for the two wells, the forecasts were dissimilar. It is discussed that the dissimilarity in huff-n-puff performance between two wells is caused by interwell communications. The well interference through fracture hits play an important role in the studied reservoir. The field data show the pressure communication between the two wells. Also, the injected gas was observed in the offset wells about one month after the start of injection. Several long fractures were added to the reservoir model to capture the characteristics of fracture interference. The prospects of EOR were proven decent for the wells of interest. We reported 29% and 82% incremental recovery for the P50 predictions of wells BH and CH, respectively. The results of field operation have been in agreement with the simulation forecasts after two cycles of gas injection and production.
Changing the Way: Integrated Artificial Lift Strategy Overcomes Waterflooding and Mature Field Challenges Increasing 58% of Total Oil Production
Authors: Gallegos Johanna , Enriquez Luis Carlos , Reyes Carlos , Correal Alvaro , Villalobos Jorge , Fun Sang Byron , Torres Richard , Villa Carlos , Bonilla Christian 
Published: October 2020

Abstract
The artificial lift strategy described in this document addresses new challenges resulting from an accelerated implementation of secondary recovery in a mature oilfield. New technologies and best operational practices were implemented to handle challenges such as high pressure and water flowrates in source water wells, extended-life ESP to enable production across a wide production range to cover the response of the waterflooding, increasing solids production, heavy oil, and installations of ESP in deep and tortuous wells.
This technical and strategic approach covers artificial lift designs for water injection in well-to-well configurations located in the same platform. This approach reduces the requirements for surface facilities. For oil producers, ESP robustness must be enhanced to handle wide range and aggressive reservoir conditions. Slim ESP applications to allow taking full advantage of waterflooding. A novel concept applied to recirculate hot water making possible produce deep heavy oil reservoirs and updated workflows and equipment for remote surveillance of the ESP systems and reservoir.
The integrated approach of the strategy allows its application in either brownfield or greenfield. Putting such strategy into action resulted in an incremental production of 30,000 bopd from waterflooding using more than 60 ESP installations of wide range and reducing workover interventions representing savings of 4.5 MMUSD. Additionally, direct well-to-well injection in 22 water producer wells allowed direct injection of 100,000 bwpd at roughly 2,000 psi at the well head and savings of 14 MMUSD in surface facilities.
Hole Cleaning Efficiency of Sweeping Pills in Horizontal Wells - Facts or Philosophy?
Authors: Czuprat Oliver , Faugstad Anne Marte , Byrski Piotr , Schulze Kai 
Published: October 2020

Abstract
More than 35 million m3 of oil have been produced from the Mittelplate oilfield. Poor hole cleaning has been identified as a root cause for drilling problems in the horizontal sections of its ERD wells. Enhancing cutting removal in vertical wells, high-viscous pills are typically considered. However, literature is providing contradicting guidance of using sweep pills in deviated/horizontal wells. Thus, the purpose of this study is to provide an overview about the theoretical background on hole cleaning and to experimentally identify the best sweep pill for ERD wells.
An apparatus has been designed as a closed flow-loop system consisting of coaxial pipes forming a horizontal well with a drill-string inside, two mud tanks, and a mud pump. Two pressure sensors are placed along the horizontal section, providing complementary information about the moving sweeping pill. Different pills (high-viscosity, medium-viscosity, high-density and a high-viscosity/high-density combination pill) have been circulated and the recovered model cutting material from one cycle of circulation has been re-weighted.
To the best of our knowledge, it is the first time that such a fully scaled-down device including pressure sensors at the toe and heel of the horizontal section has been designed and used for the evaluation of sweep pills. It delivers an efficient and cost-effective method to optimize hole cleaning processes and prevent costly drilling incidents.
Hydrodynamics of Continuous Flow Plunger Lift
Authors: Sayman Ozan , Pereyra Eduardo , Sarica Cem 
Published: October 2020

Abstract
The distinctive characteristic of continuous flow plungers (CFP) is the ability to complete a plunger cycle without a pressure buildup period. The hydrodynamics of the fall and upstroke stages of the CFP lift is vital to determine operational envelope, select plunger, and optimize gas lift. This paper presents the results of an experimental and theoretical study conducted to develop fall and upstroke models with dimensionless parameters.
The fall motion of four sleeves with different height, weight, and outer diameter, three balls made from different materials, and a bypass plunger were tested in the static facility with four different fluids. The wall effect on settling velocity was defined, and drag coefficient results for balls were validated with the literature. The liquid holdup effect on the drag coefficient was investigated by injecting gas into the static liquid column. The 40-ft long dynamic facility is utilized to investigate fall and upstroke stages of a two-piece plunger for different gas and liquid flow rates. Experiments were performed with the deviation angles up to 40 degrees.
The drag coefficients of plungers for respective Reynolds numbers, the liquid holdup correction, and the wall effect on the settling velocity were obtained. The fall model was developed with dimensionless parameters for conventional and continuous flow plungers, which can estimate primarily fall velocity and maximum flow rate to fall against. The fall model was coupled with multiphase flow simulations for sensitivity analysis, and the results showed that plungers fell slowest at the wellhead in field conditions. Furthermore, upstroke experiments demonstrated the effect of gas and liquid flow rates and outer diameter, height, and weight of the sleeve on the plunger upstroke velocity. The model predictions for the upstroke stage match with experimental results from the dynamic facility, and it is further developed to estimate upstroke velocity, liquid slug removal from the wells in field conditions. The fall and upstroke models were used together to determine the operational envelope for CFP lift and plunger assisted gas lift (PAGL) for different plunger types. The liquid unloading mechanism of the CFP lift was also discussed.
The study is unique in defining the hydrodynamics of continuous flow plunger lift and PAGL operations. The models are constructed with dimensionless parameters allowing applicability to the field conditions. The experimental results also contribute to plunger selection and design. The study provides a better understanding of when to use and how to use continuous flow plunger lift.
First Worldwide Application of Metal Expandable Fracture Packers to Enhance Integrity and Reduce Deployment Issues While Utilizing Openhole MSAF Completions
Authors: Arias Rommel E. , Guizada Pablo , Gaby Mohamed , Riou Yoann 
Published: October 2020

Abstract
This paper presents the first application of metal expandable frac packers for multistage acid fracturing (MSF) completions. This technology significantly reduces deployment risk commonly associated with openhole (OH) MSF completions with the ability to rotate while running in hole without any risk of premature expansion or compromising integrity of the sealing mechanism. Additionally, it improves efficiency of fracturing operations in tight gas reservoirs with the ability to expand to larger borehole diameters than is possible with current isolation packer technologies.
The overall deployment method for this technology is similar to traditional openhole multistage fracturing completions that are industry standard. The main difference is that the isolation packer used is expanded by pressure to mechanically deform the metal sleeve to provide sealing against the open hole. The technology comprises an innovative material and design that can hold high differential pressure at high reservoir temperatures while maintaining permanent isolation in a relatively compact element length. The metal expandable frac packer completed an extended qualification process, including American Petroleum Institute (API) testing, to fulfil deployment and acid fracturing completion requirements.
The outcome was an overall successful deployment and stimulation operation of multistage completion with the metal expandable frac packer. The metal expandable frac packer provided the ability to deploy the lower completion in difficult wellbore conditions with ability to rotate. The metal expandable frac packer is set with pressure; therefore, there is no waiting time to have full differential pressure capabilities for the fracturing operations. This technology provided a flexibility factor for packer placement as the metal expandable packer technology can hold its rated pressure at larger borehole diameters. Since the mechanism of the metal packer is expansion by inelastic deformation, the metal expandable sleeve conforms perfectly to the geometry of the borehole, providing a highly reliable seal for high pressure fracturing operations. Through a complete diagnostic process, it was confirmed that the metal expandable packers successfully isolated each stage of the stimulation treatment.
Metal expandable frac packers unique testing was conducted in the laboratory and in field to qualify the technology with special focus on the chemical composition for the fluids encountered for the deployment, stimulation, and production environments including high concentration acid fracturing applications. The metal expandable sleeve technology utilizes a unique double-sleeve system for pressure compensation to enhance the sealing integrity of MSF stimulation operations and truly provide 10,000 psi under API 19OH V1.
Characterizing Gas-Water Transport Behavior in Tight Shale and its Application on the Well Productivity
Authors: Liu Ang , Liu Shimin , Sang Guijie 
Published: October 2020

Abstract
This study provides a systematic method to study the gas/water transport behavior and water retention behavior in gas shale reservoir using analytical and numerical modelling approaches. The critical water saturation determined from the relative permeability curve is regarded as the turning point between two gas production stages: Stage I and Stage II. At Stage I, the gas /water two phase flow dominates shale gas production period, while at Stage II the single gas flow and the flow of water in adsorbed phase are dominative. The improved permeability evolution model incorporates both the gas and water sorption-induced swelling strains. The permeability ratio is a time- and location-dependent parameter and its change can be divided into three stage, namely, the increase at early time, the decrease at mid-term time, and the increase at later production time. With gas depletion, gas pressure drawdown significantly dominates the evolution of permeability ratio. Continuously, the effect of sorption induced matrix shrinkage strain will become dominative with gas pressure decreases to low values. Due to the gas source supplement induced by gas desorption at Stage I, the gas production rate will temporarily increase but then will continuously decrease till to the lowest level at critical water saturation. At Stage II, the gas production rate is significantly influenced by residual water content in shale controlled by the flow of water in adsorbed phase. In addition, the effects of elastic properties (i.e. Young's modulus and Poisson's ratio), initial permeability and diffusion time on permeability ratio and gas/water production profiles were discussed. These results provide a first rational method for analyzing the gas/water transport behavior and water retention behavior with potential application of shale gas recovery.
On the Inference of Gas Diffusion Coefficient in Organic Matter of Shale Gas Reservoirs
Authors: Eltahan Esmail , Mehrabi Mehran , Sepehrnoori Kamy , Javadpour Farzam 
Published: October 2020

Abstract
Gas production from shale-gas reservoirs constitutes the largest portion of total gas production. The US shale reservoirs are tight and inherently heterogeneous with abundant presence of kerogenic material. Modeling fluid flow in shale reservoirs is complex and still an active field of research. The complexity arises from different flow physics such as pressure flow and diffusion. Many of the field performance forecasts constantly underestimate production from these reservoirs because most of the current models ignore important governing physics. This study provides new insights on diffusion in organic matter, in an effort to correct a main source of underestimation of gas production in shale gas models.
In an earlier study, we developed for the first time a detailed diffusion model and showed how pore size distribution and specific surface area of the pores in organic matter can significantly influence gas production. An important parameter controlling the rate of gas release is the diffusion coefficient of gas diffusing into organic matter which appears in the flow equations. One of the methods of estimating the diffusion coefficient is based on analysis of gas uptake into shale samples in a closed chamber. The coefficient is extracted by comparing experimental observations to the solution of diffusion equation in the domain of pore/kerogen interface. If the mathematical representation of the organic matter is inaccurate, the diffusion coefficient will be inaccurate as well, regardless of lab-measurements accuracy. The values reported in the literature are based on the slab-shaped mathematical representation of organic matter, assuming a single scale for diffusion characteristic length.
In this study, we implement a multi-scale diffusion model to estimate gas diffusion coefficient in organic matter. The previously reported evaluations are on the order of 10−20 m2/s. Reanalysis of the same set of experimental data using our detailed model suggests the interpretation of the coefficient is largely dependent on the diffusion-length scales being considered. We show that diffusion occurs over multiple time scales and the coefficient could be as much as four orders of magnitude higher than reported. The developed diffusion model is a robust and practical mathematical model and can be implemented in reservoir simulators. The findings of this study shed some light on why production forecasts constantly underestimate gas production from shale gas reservoirs.
Mapping Buried Steel Flowlines Using Geophysical Sensors on Small Drone Aircraft
Authors: Hammack Richard , Veloski Garret , Schlagenhauf Mark , Zorn Andrew , Wylie Luke , Campbell Nathan 
Published: October 2020

Abstract
This study evaluated magnetic surveys using small unmanned aerial systems (sUAS) for the mapping of small diameter, buried pipelines, particularly flowlines. The study found that 2-inch diameter, steel pipelines buried 3-ft. deep can be confidently mapped by a total field, atomic magnetometer flown at 8 m above ground level, the maximum sensor altitude tested. The study also suggested that spiral flightplans might be preferred over bidirectional, parallel line surveys (serpentine surveys) because of the increased likelihood that the magnetic sensor will cross pipelines at or near 90° angles, the preferred orientation to obtain narrow, but intense pipeline magnetic signatures.