bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Experimental Investigation of Gas Production Rates During Depressurization of Sedimentary Methane Hydrates
Authors: Almenningen Stian , Fotland Per , Fernø Martin Anders , Ersland Geir 
Published: April 2018

Abstract
Sedimentary methane hydrates contain a vast amount of untapped natural gas that can be produced through pressure depletion. Several field pilots have proven the concept with days to weeks of operation, but the longer-term response remains uncertain. This paper investigates parameters affecting the rate of gas recovery from methane hydrate-bearing sediments. The recovery of methane gas from hydrate dissociation through pressure depletion at constant pressure was studied at different initial hydrate saturations in cylindrical sandstone cores. Core-scale dissociation patterns were mapped with magnetic resonance imaging (MRI) and pore-scale dissociation events were visualized in a high-pressure micromodel. Key findings from the gas production rate analysis are: 1) The maximum rate of recovery is only to a small extent affected by the magnitude of the pressure reduction below the dissociation pressure. 2) The hydrate saturation directly impacts the rate of recovery, where intermediate hydrate saturations (0.30 – 0.50) give the highest initial recovery rate. These results are of interest to anyone who evaluates the production performance of sedimentary hydrate accumulations and demonstrate how important accurate saturation estimates are to predict both the initial rate of gas recovery and the ultimate recovery efficiency.
Status of Data-Driven Methods and their Applications in Oil and Gas Industry
Authors: Balaji Karthik , Rabiei Minou , Suicmez Vural , Canbaz Celal Hakan , Agharzeyva Zinyat , Tek Suleyman , Bulut Ummugul , Temizel Cenk 
Published: April 2018

Abstract
Data-driven methods serve as robust tools to turn data into knowledge. Historical data generally has not been used in an effective way in analyzing processes due to lack of a well-organized data, where there is a huge potential of turning terabytes of data into knowledge. With the advances and implementation of data-driven methods data-driven models have become more widely-used in analysis, predictive modeling, control and optimization of several processes. Yet, the industry overall is still skeptical on the use of data-driven methods, since they are data-based solutions rather than traditional physics-based approaches; even though physics and geology are often part of this methodology. This study comprehensively evaluates the status of data-driven methods in oil and gas industry along with the recent advances and applications.
This study outlines the development of these methods from the fundamentals, theory and applications perspective along with their historical acceptance and use in the industry. Major challenges in the process of implementation of these methods are reviewed for different areas of applications. The major advantages and drawbacks of data-driven methods over the traditional methods are discussed. Limitations and areas of opportunities are outlined. Recent advancements along with the latest applications, the associated results and value of the methods are provided.
It is observed that the successful use of data-driven methods requires strong understanding of petroleum engineering processes and the physics-based conventional methods together with a good grasp of traditional statistics, data mining, artificial intelligence and machine learning. Data-driven methods start with a data-based approach to identify the issues and their solutions. Even though data-driven methods provide great solutions on some challenging and complex processes, that are new and/or hard to define with existing conventional methods, there is still skepticism in the industry on the use of these methods. This is strongly tied to the delicacy and sensitive nature of the processes and on the usage of the data. Organization and refinement of the data turn out to be important components of an efficient data-driven process.
Data-driven methods offer great advantages in the industry over that of conventional methods under certain conditions. However, the image of these methods for most of the industry professionals is still fuzzy. This study serves to bridge the gap between successful implementation and more widely use and acceptance of data-driven methods, and the fuzziness and reservations on the understanding of these methods in the industry. Significant components of these methods along with clarification of definitions, theory, application and concerns are also outlined in this study.
Harrier Development: Successful Implementation of the World's First Offshore Multilateral Installation with Staged Acid Fracturing Performed on Both Laterals
Authors: Scott-Rampersad Ria , Norris Mark , Carval Rafael Guedes , Airnes Jamie , Bramald James , Oberhofer Rob 
Published: April 2018

Abstract
With a suppressed hydrocarbon sector over the past few years, operators, service providers and ancillary companies alike have been strongly challenged to collaborate, where feasible, on field development solutions which offer greater economies of scale and efficiency by reducing operational time and cost. This paper details the evolution of the Harrier field development plan (FDP) in the context of innovation within completion and stimulation treatment design which has successfully created value for this North Sea gas operator.
Originally, the project plan comprised of two development wells, each accessing separate chalk gas reservoirs - Ekofisk and Tor which were approved by the UK Oil and Gas Authority in 2012 under the Stella and Harrier FDP, with an estimated development cost of USD 250 million. During the conceptual phase, the project economics were not attractive even in a high oil price environment. Services providers were then invited to provide alternative solutions to significantly enhance the investment appeal of this opportunity with the aim of reducing capital and operating expenditure while enhancing both field recovery and accelerated production. One such provider was successful with the proposition of a revolutionary contraction of the FDP with a unique design concept of a single well development terminating in a dual lateral with each leg targeting a separate reservoir in which fourteen acid stimulation stages per leg were planned to greatly enhance productivity. After several months of intensive collaboration, the optimized well design was completed and the project was sanctioned with field development cost reduced by a full 50%.
The paper provides an overview of the stimulation design, based on the reservoir challenges encountered and the progression of the completion design explored, into its final fit for purpose realisation. Results in relation to achievement of well objectives, service delivery, change management during the execution phase and most significantly overall well performance are also provided.
The objective of this paper is not only to demonstrate the value created to the field operator, but also to illustrate how planning and developing a unique solution was strongly influenced by a cost sensitive environment for efficiencies gained, with regards to risk management and mitigation, along with contingency planning. Furthermore, through a multi-segment integrated approach experience, numerous lessons learnt and best practices were harnessed for use when venturing on similar projects championing technical innovation under economic and resource constraints.
Application of Bespoke Well Completion Architecture and Integrated Surveillance in the Development and Production of a High Saline Gas Field - UK North Sea
Authors: Otaru Gabriel , Haider Syed , Nilsen Anna 
Published: April 2018

Abstract
The development and production of some oil and gas fields is that it sometimes brings fluid chemistry challenges. These chemistry challenges exhibit themselves in flow assurance issues which if not managed well, can lead to loss of productivity and value. Building an engineering solution to manage these risks enhances mitigation. One other key activity in optimizing and achieving value in oil and gas development is integrated surveillance and reviews cutting across various disciplines.
Neptune E & P UK Ltd has developed and brought to production the Cygnus field. It is one of the biggest gas field developments in the UK North Sea in recent years. The formation water is very saline with total dissolved solids of approximately 320,000 mg/l2. The major risk identified with the Cygnus development was halite deposition as evidenced in analogue fields developed and produced in the Southern North Sea (SNS) area by other operators. The well architectures in these fields are simple and treatment for halite deposition is carried out by dumping fresh water manually from surface. However experience from these operators, indicates that this approach was not very efficient. This has resulted in a loss of productivity, and early abandonment of wells, with associated stranded reserves.
The Cygnus Field development adopted a combination of bespoke completion architecture, an integrated approach to surveillance and review of data streaming in from the wells. Details of methods employed include the ability to continuously inject deoxygenated fresh water into the wells to provide online water washes with the wells flowing. Continuous thermal data acquisition from Distributed Temperature Sensing (DTS) fibre permanently installed across the length of the well. Pressure and temperature data measurement from permanent down-hole gauges. Surface measurement of rate, fluid fractions, salinity and pressure / temperature provided by multiphase flow meters.
The integrated surveillance and review process uses data acquired from the well instrumentation. This is normally carried out as follows: Data set preparation and validationProduction Data AnalysisShort and Long-term production strategy
This strategy has allowed the operator to use the continuous data stream for well and reservoir analysis which has helped in optimizing production yielding high operational efficiency and availability.
Multi-Disciplinary Approach to Developing Challenging Heavy Oilfields with Basal Aquifers
Authors: Law Stuart , McDonald Andrew , Castillo Edgar , Mackay Eric , Fellows Susan 
Published: April 2018

Abstract
In the United Kingdom Continental Shelf (UKCS), a significant heavy oil prize of 9 billion barrels has been previously identified, but not fully developed. In the shallow unconsolidated Eocene reservoirs of Quads3 and 9, just under 3 billion barrels lie in the discovered, but undeveloped fields, of Bentley and Bressay. Discovered in the 1970s, they remain undeveloped due to the various technology challenges associated with heavy oil offshore and the presence of a basal aquifer. The Eocene reservoirs represent significant challenges to recovery due to the unconsolidated nature of the hydrocarbon bearing layers. The traditional view has been that such a nature represents a risk to successful recovery due to sand mobility; reservoir and near wellbore compaction; wormhole formation; and injectivity issues.
We propose improving the ultimate oil recovery by a combination of aquifer water production and compaction drive. By interpreting public domain data from well logs, the range of geomechanical properties of Eocene sands have been determined. A novel approach to producing the heavy oil unconsolidated reservoirs of the UKCS is proposed by producing the aquifer via dedicated water producers situated close to the oil-water contact. The location was determined by sensitivity analysis of water producer location and production rates. By locating water producers at the OWC with a production rate of 20,000 bbls/day of fluids, the incremental recovery at the end of simulation is increased by 4.1% OOIP of the total modelrelative to the ‘no aquifer production’, casesuggesting a significant increase in recovery can be achieved by producing the aquifer. A rate of 30,000 bbld/day located at the OWC was found to increase incremental recovery by 5.8 %OOIP relative to the ‘no aquifer case’. In all cases, as the reservoir fluid pressure is reduced, oil recovery increases via compaction and reduced water influx into the oil leg. This reduced pressure leads to a higher tendency towards reservoir compaction which is expressed as a change in mean effective stress and porosity reduction.
Controlling Parameters for Shale Gas Production Into a Well-Induced Fracture: A Fracture-Matrix Modelling Approach
Authors: Berawala Dhruvit Satishchandra , Andersen Pål Østebø , Ursin Jann Rune 
Published: April 2018

Abstract
The purpose of this paper is to investigate the main controlling factors of shale gas production in the context where well-induced fractures, extending from the well perforations, improve reservoir conductivity and performance. A mathematical 1D+1D model is presented which involves a high-permeable fracture extending from a well perforation, through symmetrically surrounding shale matrix with low permeability. Gas in the matrix occurs in the form of adsorbed material attached to kerogen (modeled by a Langmuir isotherm) and as free gas in the nano-pores. The pressure gradient towards the fracture and well perforation causes the free gas to flow. With pressure depletion, gas desorbs out of the kerogen into the pore space and then flows to the fracture. When the pressure has stabilized, desorption and production stop.
The production of shale gas and mass distributions indicate the efficiency of species transfer between fracture and matrix. It is shown that the behavior can be scaled and described according to the magnitude of two characteristic dimensionless numbers: the ratio of diffusion time scales in shale and fracture α, and the pore volume ratio between the shale and fracture domains β. Properties of fracture and matrix are varied systematically to understand the role of the fracture matrix interaction during production. Further, the role of fracture geometry (varying width) is investigated. Input parameters from experimental and field data in the literature are applied.
The product αβ expresses how much time it takes to diffuse the gas in place through the fracture to the well compared to the time it takes to diffuse that gas from the matrix to the fracture. For αβ ≪ 1 the residence time in the fracture is of negligible importance and fracture properties such as shape, width and permeability can be ignored. However, if αβ ≈ 1 the residence time in the fracture becomes important and variations in all those properties have significant effects on the solution.
The model allows intuitive interpretation of the complex shale gas production system. Furthermore, the current model creates a base which can easily incorporate non-linear flow mechanisms and geo-mechanical effects that are not readily found in standard commercial software, and further be extended to field scale application.
Oil Recovery Analyses and Formation Water Investigations for High Salinity-Low Salinity Water Flooding in Sandstone Reservoirs
Authors: Al-Saedi Hasan , Williams Ariel , Flori Ralph , Brady Patrick , Al-Jaberi Soura 
Published: April 2018

Abstract
Recently, we investigated the effect of Ca2+ in the formation water and its potential on low salinity (LS) water flooding (Al-Saedi et al. 2018). In this paper, we pursue to quantify the influence of formation water containing Ca2+ and Mg2+ on LS EOR. Berean sandstone cores were sequentially flooded with high salinity HS water and LS water at 90°C. During injecting brines, samples of the effluent were analyzed for pH. Oil recovery experiments with a double Ca2+ and Mg2+ concentration showed a lower LS water effect, meaning that the cores became more water-wet; however, the LS water effect was much greater when the amount of Ca2+ and Mg2+ in the HS water was decreased by half.
The results of this work isolate and relate oil recovery with the most effective factors that control LS water chemical mechanisms.
Reconstruction of 3D Porous Media Using Multiple-Point Statistics Based on a 2D Training Image
Authors: Wu Yuqi , Lin Chengyan , Ren Lihua , Tian Weichao , Wang Yang , Zhang Yimin 
Published: April 2018

Abstract
Macroscopic transport properties of porous media essentially rely on the geometry and topology of their pore space. The premise of predicting these transport properties is to construct an accurate 3D pore space. To date the methods of modeling porous media are divided into two main groups, direct measurements by some equipment and stochastic statistical methods. Direct measurements of pore structure can be acquired with current equipment such as X-ray computed tomography and laser scanning confocal microscopy, but the unavailability of the equipment and the high cost of the measurement make their widespread application impossible. Many stochastic statistical methods, such as truncated Gaussian random field and simulated annealing methods, reconstruct 3D porous media based on some 2D thin sections by means of lower-order statistical functions. However these functions cannot reproduce the long-range connectivity of pore structure. Therefore, this paper will present a stochastic technique of reconstructing 3D pore space using multiple-point statistics with the purpose of solving the proposed problems. The single normal equation simulation algorithm (SNESIM), one of the most common methods for discrete variable simulation in multiple-point statistics, is the main tool to reproduce the long-range feature of pore space. To test the method, Berea sandstone was used as a sample. In the simulation process, a 2D thin section was taken as the training image for providing patterns of pore structure and some pixels were extracted from it as the conditioning data. The models were reconstructed using the SNESIM algorithm that serves as the simulation engine. In order to test the accuracy of these reconstructed models, pore geometry and topology and transport properties of the reconstructed models were compared with those of the real model obtained by X-ray computed tomography scanning. The comparison result shows that the reconstructed models are good agreement with the real model obtained by X-ray computed tomography scanning in the two-point correlation function, the pore space features and single- and two-phase flow permeabilities, which verifies that the long-range connectivity of pore space can be reproduced by this method. Comparing with other stochastic methods, a more accurate stochastic technique of reconstructing 3D porous media is put forward when only some 2D thin sections are available.
Viscous Oil Recovery by Polymer Injection; Impact of In-Situ Polymer Rheology on Water Front Stabilization
Authors: Vik Bartek , Kedir Abduljelil , Kippe Vegard , Sandengen Kristian , Skauge Tormod , Solbakken Jonas , Zhu Dingwei 
Published: April 2018

Abstract
Polymer injection for viscous oil displacement has proven effective and gained interest in the recent years. The two general types of EOR polymers available for field applications, synthetic and biological, display different rheological properties during flow in porous media. In this paper, the impact of rheology on viscous oil displacement efficiency and front stability is investigated in laboratory flow experiments monitored by X-ray.
Displacement experiments of crude oil (~500cP) were performed on large Bentheimer rock slab samples (30×30cm) by secondary injection of viscous solutions with different rheological properties.
Specifically, stabilization of the aqueous front by Newtonian (glycerol and shear degraded HPAM) relative to shear thinning (Xanthan) and shear thickening (HPAM) fluids was investigated.
An X-ray scanner monitored the displacement processes, providing 2D information about fluid saturations and distributions. The experiments followed near identical procedures and conditions in terms of rock properties, fluxes, pressure gradients, oil viscosity and wettability.
Secondary mode injections of HPAM, shear-degraded HPAM, xanthan and glycerol solutions showed significant differences in displacement stability and recovery efficiency. It should be noted that concentrations of the chemicals were adjusted to yield comparable viscosity at a typical average flood velocity and shear rate.
The viscoelastic HPAM injection provided the most stable and efficient displacement of the viscous crude oil. However, when the viscoelastic shear-thickening properties were reduced by pre-shearing the polymer, the displacement was more unstable and comparable to the behavior of the Newtonian glycerol solution.
Contrary to the synthetic HPAM, xanthan exhibits shear thinning behavior in porous media. Displacement by xanthan solution showed pronounced viscous fingering with a correspondingly early water breakthrough.
These findings show that at adverse mobility ratio, rheological properties in terms of flux dependent viscosity lead to significant differences in stabilization of displacement fronts. Different effective viscosities should arise from the flux contrasts in an unstable front.
The observed favorable "viscoelastic effect", i.e. highest efficiency for the viscoelastic HPAM solution, is not linked to reduction in the local Sor. We rather propose that it stems from increased effective fluid viscosity, i.e. shear thickening, in the high flux paths.
This study demonstrates that rheological properties, i.e. shear thinning, shear thickening and Newtonian behavior largely impact front stability at adverse mobility ratio in laboratory scale experiments. Shear thickening fluids were shown to stabilize fronts more effectively than the other fluids. X-ray visualization provides an understanding of oil recovery at these conditions revealing information not obtained by pressure or production data.
Pore-to-Core EOR Upscaling for CO2-Foam for CCUS
Authors: Rognmo Arthur Uno , Fredriksen Sunniva Brudvik , Alcorn Zachary Paul , Sharma Mohan , Føyen Tore , Eide Øyvind , Graue Arne , Fernø Martin 
Published: April 2018

Abstract
An ongoing CO2-foam upscaling research project aims to advance CO2-foam technology that accelerate and increase oil recovery, with reduced operational costs and carbon footprint during CO2 EOR. Laboratory CO2-foam behavior will be upscaled to pilot scale in two onshore carbonate and sandstone reservoirs in Texas, USA. Important CO2-foam properties such as local foam generation, bubble texture, apparent viscosity and shear-thinning behavior with a nonionic surfactant were evaluated using Pore-to-Core upscaling to develop accurate numerical tools for field pilot prediction of increased sweep efficiency and CO2 utilization. On pore-scale, silicon-wafer micromodels showed in-situ foam generation and stable liquid films over time during static conditions. Intra-pore foam bubbles corroborated apparent foam viscosities measured at core-scale. CO2-foam apparent viscosity was measured at different rates (foam rate scans) and different gas fractions (foam quality scans) at core-scale. The highest mobility reduction (foam apparent viscosity) was observed between 0.60-0.70 gas fraction. The maximum foam apparent viscosity was 44.3 (±0.5) mPas, 600 times higher than that of pure CO2. The maximum apparent viscosity for the baseline (reference case, without surfactant) was 1.7 (±0.6) mPas, measured at identical conditions. CO2-foam showed shear-thinning behavior with approximately 50% reduction in apparent viscosity when the superficial velocity was increased from 1 ft/day to 8 ft/day.