bluuebunny/crossref_metadata_2025_split huggingface dataset:
Flow Path Characterization: A Deterministic Approach for Reconciliation of Flow Capacity Changes from Matrix and Fractures Productivity in Deep Jurassic Reservoirs in North Kuwait
Authors: Acharya Mihira N. , Chakravorty Sandeep , Rao Dhiresh G. , Joshi Girija K. , Pradhan San P. , Rao Narhari S. , Singh J. R. , Dashti Qasem M. 
Published: September 2013

Abstract
The Deep carbonate reservoirs of North Kuwait are broadly divided into deeper assemblage consisting of diagenitically modified dolomitic layer and shallower fractured-laminated tight limestone and Kerogen units. It is a challenge to establish and quantify the known phenomenon of dynamic changes in the flow path characteristics and properties of the reservoir rocks, as the natural stability condition are altered by production of reservoir fluid. The parameters of the flow path characterization become more uncertain in case of deep HP/HT digenetically altered reservoirs and fractured-tight limestone with laminated kerogen, then similar to the North Kuwait deep reservoirs.
In this study an integration of static data such as, borehole image, core and petrophysical evaluation with time lapse dynamic reservoir parameters like production, pressure data from buildup and pressure transient analysis was carried out to understand the flow path characteristic changes. A deterministic approach has been used to characterize the reservoir flow system and to estimate the fracture aperture for each time step. Thus the time dependent alternations in the flow path properties such as reduced fracture aperture and linked causative phenomena have been studied with multiple scenarios.
A detailed inventory and analysis of various well intervention operations between the time lapse measurements was carried out to distinguish the natural vs. work over induced causatives of flow path changes. This has assisted proper calibration of fracture properties for the static conditions, dynamic simulation and history matching. This workflow has also optimized the application of appropriate reservoir health checkups and remedial interventions. Cases of two representative wells completed in each of the deep reservoir assemblages are presented as examples to demonstrate the study.
Gas Lift Troubleshooting with Interactive Workflow and Rule Based Inferencing
Authors: Arellano Jose Luis , Khan Kashif , Istami Rashid , Partington Ben , Bakshi Amol 
Published: September 2013

Abstract
We describe a dynamic, real-time workflow for gas lift surveillance and troubleshooting that allows engineers to quickly identify a range of potential problems with the well and identify ways to optimize gas lift performance. This functionality has been implemented as a software program that makes innovative use of dynamic visualization, mathematical models, real-time data, and rule-based reasoning. The program logic uses PVT and multiphase flow correlations to allow engineers to understand the main variables that affect performance of the wells. The algorithms incorporate a simple set of IF-THEN rule-based inferencing to solve control problems in conjunction with the mathematical model. Based on real time data from field historians, recent well tests, and an up to date well model, the program estimates the current stability condition of gas lift wells with a single point of injection or multiple valves. For a given gas lift valve port size, productivity index and gas injection rate, it displays a stability map that provides an idea how much gas needs to be increased in order to improve the stability condition. The user (engineer) has the ability to dynamically vary parameters such as well head pressure, gas lift injection rate, orifice size, type of valve, etc., and thereby determine the best optimization approach. We describe a number of case studies where an application of this workflow logic improved gas lift performance.
Post-Treatment Assessment of Induced Fracture Networks
Authors: Taleghani A. Dahi , Gonzalez M. , Puyang P. , Lorenzo Juan M. , Le Calvez J. , Xu W. 
Published: September 2013

Abstract
An integrated methodology is proposed to generate a grid of potential paths for hydraulic fracture growth in naturally fractured reservoirs based on formation properties and recorded microseismic maps. The generated grid can be further used for treatment simulation to determine induced fractures geometry, height growth and respected proppant transport in the induced fracture network. For different realization of natural fracture distributions generated by computer simulations, cohesive interface technique is used to model evolution of induced fracture network. Microsesimic map is used to
Ultrasonic Curable Nanoparticles Strengthening Technique While Drilling
Authors: Xu Zichen , Jin Yan , Chen Mian 
Published: September 2013

Abstract
This paper proposes that nano-scale ultrasonic curable polymer and initiators can enter into the rock with drilling fluid in drilling process, in the presence of VDW force and electrostatic force, the polymer is absorbed and accumulates in fractures. Under the influence of ultrasonic transmitter set in the BHA, the initiator generates reactive free radicals to cure the polymer. In addition, the acoustic resistance in the fracture generates local high temperature, which can make the polymer crosslink and cure into a type of material of certain tenacity and strength, thus consolidate rocks near the wellbore as well as fill in fractures to strengthen the borehole wall. According to above theory, the study puts forward the design of ultrasonic curable drilling system and the design of downhole ultrasonic transmitter, and tests its properties. In addition, the study carries out the development of the ultrasonic curable system and the relevant downhole equipment and the application method, examines the application prospect of the technique from multiple aspects such as the impact of the fracture depth on the curing condition, the impact of the ultrasonic curable material on the permeability of the fractures, the impact on contact angle of shale surface and the impact on the strength of shale. The results show that the filter loss under HTHP is close to zero. This technique can effectively restrict the propagation of fractures, maintain the shale strength, and improve the strength of shale with faults. It is concluded from these tests that the ultrasonic strengthening technique can be applied to consolidate the caving section during shale gas drilling. The technology will be on trial in the shale gas drilling in West China, and is expected to be widely applied on unconsolidated sandstone and deepwater drilling to stretch the extension limits of the open hole.
Modeling Coupled Heat Transfer and Multiphase Flow during the Expanding Solvent Steam-Assisted Gravity Drainage (ES-SAGD) Process
Authors: Azom Prince N. , Srinivasan Sanjay 
Published: September 2013

Abstract
By solving a 1D heat conservation equation for single phase flow, Butler (1981) derived his classical SAGD equation which has excellent predictive capability at experimental scales but performs poorly at field scales. Several authors have tried to remedy this by acknowledging the existence of multiphase flow ahead of the steam chamber during SAGD, but have only empirically accounted for it using multipliers that seem to vary for each reservoir. Recently, by coupling the mass and energy conservation equations, Azom et al. (2013) solved this problem and showed that the multi-scale phenomenon is controlled by the classical Marangoni or thermo-capillary number.
In this paper, we extend the concept of thermo-capillary imbibition (Azom et al., 2013) to include the additional coupling of a solvent component mass balance to the mass and energy conservation equations in order to derive an expression for oil recovery during ES-SAGD.
Our results show that in addition to the thermo-capillary number, additional dimensionless groups like the condensate Lewis number, the ratios of the solvent's condensate to bitumen dispersion coefficient and solvent viscosity to bitumen viscosity at steam temperature influence multiphase flow and hence ES-SAGD flow performance. An important conclusion is that heterogeneity will have a complex effect on the ES-SAGD process as it causes more thermo-capillary imbibition (thereby decreasing bitumen rates) while at the same time causes the further transport of solvent into the bitumen phase (thereby increasing bitumen rates).
Our method involved accounting for capillary pressure in the conservation equations and decoupling it into its temperature and saturation components. This then forms the basis for coupling the mass and energy conservation equations. The solvent is assumed not to affect capillary behavior for the ES-SAGD process. The entire modeling was done in dimensionless space making the results applicable across varying scales and for a range of reservoir parameters.
This work presents a viable semi-analytical model for the ES-SAGD process while at the same time accounting for the effect of multiphase flow during the process. It is also important to note that currently no commercial simulator can model thermo - capillary behavior and hence cannot account for multiphase flow effects during non-isothermal recovery processes. Our model solves this problem for the ES-SAGD process and can be used together with the original Butler model as a fast ES-SAGD predictive model that also accounts for multiphase flow in any proxy-based history matching process.
Open Hole Fluid Displacement Analysis - Forward vs. Reverse Circulations
Authors: McNerlin B. , Gao Q. , Mohiuldin G. , Oakey N. 
Published: September 2013

Abstract
Angola is home to two of BP's largest subsea developments, Greater Plutonio and PSVM. High rate production wells have been achieved through the use of long open hole gravel pack completions, with alternate path screen design. Since the screens are deployed in conditioned oil based mud, the open hole is displaced to aqueous fluid prior to gravel packing the well. The early Greater Plutonio wells extensively utilised what is referred to as the ‘conventional,’ ‘forward,’ or Heel-to-Toe technique to displace the oil based fluid to water based. However, depletion of some of the reservoir sands increased the likelihood of screen plugging in wells with long open hole sections, as demonstrated by a handful of incidents. Also, the tight pore pressure to fracture gradient (PPFG) windows and small screen gauge sizes in the PSVM development made the ‘forward’ technique less suitable to adopt as a basis of design. As such, both projects developed a different displacement technique referred to as ‘reverse’ or Toe-to-Heel circulation to overcome the issues of sand control screen plugging and small PPFG windows. Work was performed to confirm that service tools could maintain full functionality, the fluid pill train properties were appropriate, and that hydraulic models could adequately predict the ECDs generated during the displacement. Eight open hole gravel pack wells, across both projects, have now been successfully completed using the Toe-to-Heel technique. Using the data from these wells, along with the existing data set from the earlier Greater Plutonio wells, it has been possible to determine a set of guidelines which indicate which technique is best suited under certain conditions.
This paper briefly describes the history of the two projects, details the operational differences between both methods, describes the evolution of the modelling work done for ECD prediction, including several pros and cons associated with each method. The actual displacement data is also presented, and is compared with the predictions from the initial modelling simulations. The development of even more accurate modelling techniques is also discussed.
Successfully Managing Mature gas Fields in the Netherlands
Authors: Yavuz Ferhat , Jansen Floor 
Published: September 2013

Abstract
Many Dutch gas fields are in the mature or tail-end production phase. Operating and producing these assets presents operational and financial challenges. Lower production rates, combined with ageing infrastructure, not only require effective management of expenditure but also implementation of emerging technologies to ensure sustained gas production. Liquid loading and salt precipitation are two major issues in managing mature gas fields in the Netherlands. Additionally the Dutch mining regulations require the use of sub surface safety valves (SSSV) which brings economic and operational challenges.
In 2012, EBN carried out an analysis on the historical production performance of all Dutch gas fields. During the last ten years operators have implemented various "End of field life" (Eofl) techniques, which and these have proved to be very effective. The commonly applied Eofl techniques are foam injection (batch and continuous), velocity strings, fresh water injection, jet pumps, plunger lift and mobile well head compressors.
Over the last ten years annual gas production from the small fields (i.e. all fields except Groningen) was between 30 to 40 Bcm/yr. (1050 - 1400 Bcf/yr.) from some 750 wells. Eofl techniques were applied to approximately 200 wells. So far an additional 2.5 Bcm (70 Bcf) has been recovered. These techniques did not only increase recoverable reserves from the specific fields, but also extended the life of infrastructure. They facilitated extra recovery whilst enabling continued operation of the assets for an extra five years.
From the analysis the authors conclude that the Eofl techniques were successful, even though to date they have only been applied on a small scale. The most common production issues are: liquid loading, salt and scale deposition and water breakthrough. The focus in this paper is on liquid loading and salt and scale deposition. The potential for improvement of recovery factors has a significant economic value. It is expected that operational experience and know-how will reduce the underlying costs in the near future.
Development of a Compact Topside Processing Plant
Authors: Mikkelsen René , Verbeek Paul , Akdim Mohamed Reda 
Published: September 2013

Abstract
Compact separation technologies have been gradually introduced into topside facilities during the last decade. Deployments have typically been motivated by a need to debottleneck facilities in mature fields, where a compact unit could be installed into a congested process plant without major reconstruction. While the advantages of compact separation technologies are generally acknowledged, the lack of data regarding performance, flexibility and reliability - as well the absence of process simulation tools - has until now resulted in a limited utilization of compact processing concepts in new field developments.
In close collaboration with a major oil operator a program has been established with the aim of developing a Compact Topside Gas/Oil/Water Processing Plant, with high efficiency and reliability, capable of handling the new oil properties and high CO2 content that characterizes the recent Pre-Salt discoveries. Inline ultra-compact separation technologies have been combined with optimized vessel designs to achieve a flexible and reliable processing plant for future FPSO's.
During the conceptual design phase extensive process simulations of the complete processing plant have been performed. Dynamic performance modelling has been included into these simulations for each component, allowing detailed predictions of plant performance in the presence of transients. This has been used for design optimisation, evaluating impact of component failure, as well as the development of a control and automation philosophy. Feedback from existing installations has been used to perform a Technology Maturity Assessment of each new technology incorporated in the compact topside facility and to establish a reliability database. For any technology not ranked at the highest Technology Readiness Level the gaps and required qualification activities have been identified.
This paper presents the activities executed during the development of a novel topside facility based on compact separation technologies, including Technology Maturity and Reliability Assessment, as well as capabilities of new process simulation tools.
Simple and Cost-Effective Hydrate Prevention for Flowback After Hydraulic Fracturing: Kinetic Hydrate Inhibitor (KHI)/Methanol Mixture
Authors: Huff T. , Cook S. , Trebing R. , Glover M. , Garza T. , Thieu V. 
Published: September 2013

Abstract
A mixture of KHI (Kinetic Hydrate Inhibitor) and methanol has demonstrated significant success in preventing hydrate formation for gas wells within a Wyoming field. Prior to this treatment method being utilized, gas hydrate blockage formation, in surface flow lines and production equipment, was an operational risk and a costly source of downtime during flowback operations following hydraulic fracturing. The well start-up phase, following a shut-in period, was particularly hydrate-prone due to the higher pressure and lower temperature conditions created by the shut-in itself. Flowback of new high pressure wells through separation equipment, rather than to a pit or tank, also increased the likelihood of hydrate formation due to the presence of back-pressure. Increasing occurrence of hydrates was associated with the use of ‘Green Completion’ separation equipment, which was being used in order to comply with the Wyoming Department of Environmental Quality requirement that emissions associated with natural gas flaring and venting during fracturing flowback are to be minimized. Due to delays and mitigation costs resulting from surface hydrate blockages, the operator has estimated an overall increase in flowback costs of more than $500,000 for wells completed over a nine-month period using this ‘Green Completion’ approach.
KHI, methanol and controlled mixtures of both chemicals were all considered as potential hydrate prevention methods. Laboratory results suggest that mixtures of KHI and methanol are in fact a more cost-effective solution than methanol alone. In turn, the presence of methanol actually enhances the effectiveness of KHI at these high sub-cooling values of up to 20 °F.
During high pressure well start-up, KHI and methanol was injected into surface lines at rates of 5 to 10 gph, for a dosage rate of between 2 to 10% in the water phase. The inhibition was stopped once the production stream had warmed up to a temperature outside the stable hydrate formation region, usually within 4 hours of initiating the start-up. These injections required only minimal additional equipment in order to safely deploy the inhibition chemistry. Following the successful treatment of 11 wells, the KHI/methanol mixture has become the prevention technique of choice for this Wyoming gas field.
This work is particularly relevant to onshore US wells that are hydraulically fractured. Applicable Federal EPA requirements mandate that, starting January 2015, operators in all states must reduce VOC emissions during fracture flowback operations. Compliance with this requirement may increase the frequency of hydrate blockages, and this simple and cost-effective hydrate prevention technique offers significant benefit in these situations.
Design, Installation, and Initial Performance of Ultra-High-Rate Gas Deepwater Completions - Tamar Field, Offshore Israel
Authors: Healy John , Sanford Jack , Dufrene Kerby , Fink Josh , Reeves Donald , Hopper Tim 
Published: September 2013

Abstract
A case history from Offshore Israel is presented that describes the successful delivery of five (5) ultra high-rate gas wells (+250 MMscf/D) completed in a significant (10 TCF) gas field with 7 in. production tubing and an Open-Hole Gravel Pack (OHGP). Maximizing gas off-take rates from a gas reservoir with high flow capacity (kh) requires large internal diameter (ID) tubing coupled with efficient sand face completions. When sand control is required, the OHGP offers the most efficient as well as the most reliable, long-term track record of performance. A global study of ultra high-rate gas wells was made to select and finalize the design concept after which the commensurate engineering rigor was applied. This paper will highlight key accomplishments within various phases of a completion delivery process for critical wells. The completions were installed with minimal operational issues (Average NPT ≈4%). Production commenced on March 31, 2013 without incident thus far. Each well is designed for production rates in excees of 250 MMscf/D.
Perforating Instrumented and Smart Well Completions: Available Technology, Testing, Development, and Lessons Learned
Authors: Blount C. G. , Grubb S. A. , Kable W. , Lynch P. H. , McCracken S. M. , Smith B. E. 
Published: September 2013

Abstract
Increasing numbers of ‘smart’ and instrumented wells are being completed worldwide. Many of these types of completions will require perforating as part of the initial completion and many more may require perforating at some time during the life of the well. Even completions that do not require perforating, such as common packer/sliding sleeve open hole completions, still rely on perforation technology to provide a back up contingency.
This paper identifies challenges and methods developed to mitigate problems associated with and to enable perforating instrumented and smart wells. This paper will also review the tools and techniques available to perforate these types of completions, while avoiding damage to pipe external control lines, cables, gauges, fiber optic lines, and other critical completion equipment. Discussions will cover a brief history and limitations of currently available tools and techniques. Details of testing and tool developments will be discussed followed by lessons learned from a multi-well field program.
The instrumented ‘smart well’ development program discussed in this paper includes six wells ranging from a 2,600' measured depth vertical well to 3 horizontal completions with measured depths exceeding 16,000'. The program included running over 20 logs ranging from magnetic based detection tools to ultrasonic tools, and perforating 129 separate intervals. Results of testing available tools and details of development of new equipment, tools and techniques will be discussed. No external cables or other smart well components were damaged during the 129 perforating operations.
Geomechanics of Hydraulic Fracturing Inferred from Composite Radiation Patterns of Microseismicity
Authors: Rutledge J. T. , Downie R. C. , Maxwell S. C. , Drew J. E. 
Published: September 2013

Abstract
Hydraulic-fracture microseismicity sometimes exhibit fairly uniform radiation patterns as revealed by systematic patterns of P- and S-wave first motions and amplitude ratios. These patterns suggest a predictable failure condition and allow composite source mechanism information to be obtained from sparse receiver coverage. Commonly, one of the nodal planes is aligned close to the hydraulic fracture. We present two case studies and interpret the composite radiation patterns in terms of expected stress conditions near the hydraulic fracture. In the first case, strike-slip failure is prevalently aligned with SHmax direction in a series of hydraulic fracture injections in the Cotton Valley tight sands. We interpret the alignment of nodal planes with principal stress direction as a preference for extension-shear fracturing. A preference for extension-shear fracturing requires conditions of low differential stress and high pore pressure, a condition produced immediately adjacent to a hydraulic fracture. In the second case dip-slip nodal planes are aligned with SHmax and hydraulic fracture direction in the Barnett shale. The alternate failure plane for a near-vertical dip-slip mechanism is a horizontal fracture plane. We interpret the uniform Barnett radiation patterns as an indication that shearing prevalently occurs on bedding planes, driven by and accommodating hydraulic fracture opening.