bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of Methods to Improve Matrix Stimulation of Horizontal Carbonate Wellbores
Authors: Nasr-El-Din Hisham A. , Shedd Daniel , Germack David , Penny Glenn 
Published: November 2015

Abstract
Acid stimulation of horizontal wellbores in high temperature and/or low permeability formations is complicated due to the need to balance acid reaction rates with the rate of formation penetration. At high bottom hole temperatures, uncontrolled acid spending rates result in inefficient or even damaging treatments. It is advantageous to add materials which slow the reaction of HCl or use alternative acids which are useful as alternative stimulation fluids, such as organic acids and chelants due to their inherently lower reaction rates. The slower reaction rate with carbonate minerals allows for optimal wormhole growth at the limited rates available in long horizontals. This study investigates the complementary use of acid or chelant systems together with a microemulsion delivery system to achieve the desired performance. These delivery systems can significantly increase the efficiency of HCl and chelant stimulation treatments of low-permeability carbonates by optimizing diffusivity and minimizing pressure to cleanup.
Horizontal core flow experiments were conducted by injecting solutions of 15 wt% HCl and 10–20 wt% alternative acids through low permeability (&lt; 10 md) limestone cores. High permeability cores were also investigated by injecting 15 wt% HCl through high permeability (150–200 md) Indiana limestone cores. These experiments were conducted with and without the addition of a microemulsion additive and at core injection rates from 0.2 – 20 cm3/min corresponding to 0.25 to 5 BPM per 100 ft of a horizontal wellbore.
Significant performance advantages were found with the addition of the microemulsion delivery system. The treatment volume required for wormholes to propagate the length of the test core was reduced at all flow rates at or above the optimum rate. Core penetration was more efficient when using the microemulsion, without an increase in pumping pressure. Initiation and extension of wormholes was improved, as compared to the experiments without the microemulsion, in which more conical wormholes tended to form at the inlet face. The reduction in treatment volume necessary to reach breakthrough with the microemulsion present also suggested a more efficient treatment.
The complementary use of a microemulsion delivery system with acids and chelants has been shown to enhance acid stimulation treatment potential in long horizontal wellbores with high temperature or low permeability formations. This system can be used to optimize wormhole penetration while maintaining an optimum injection rate across long horizontal intervals where the maximum achievable injection rate is relatively low.
Integrated Workflow for Selecting Hydraulic Fracture Initiation Points in the Khazzan Giant Tight Gas Field, Sultanate of Oman
Authors: Spain David R. , Naidu Raja , Dawson William , Merletti German D. , Kumar Rajeev , Guo Dai Yu 
Published: November 2015

Abstract
Core-calibrated petrophysical rock typing for gas rate deliverability profiling, coupled with field-calibrated mechanical stress models, represents a significant step forward in optimizing the value of hydraulic fracture stimulation in the Khazzan field unconventional tight gas reservoir. Our Mechanical Earth Model (MEM) is an important component of the integrated workflow currently being used for selecting intervals for successful hydraulic fracture initiation. When incorporated into an integrated subsurface performance prediction strategy, this technology enables optimization of well targeting, increased reserve recovery, and capital efficiency.
The interaction of regional tectonics and local lithology controls the stress profiles of the layers in the Barik tight gas reservoir in the Khazzan field. Core measurements show a significant effect of rock fabric and diagenesis on effective gas permeability, elastic properties, and rock strength. The ability to incorporate lithology, rock fabric, and pore geometry in our dynamic to static calibrations provides new insights into our predictions of rock mechanical properties and reservoir quality, which are used to obtain calibrated "fracture initiation" profiles from core, log, and downhole stress measurement information.
The MEM is calibrated using an integrated wellbore stability analysis and horizontal stresses are refined by honoring the observed borehole breakouts, formation breakdown and closure pressures. The models show that the adjacent layers in Khazzan field are under higher stress than the pay zones, which enhance fracture height containment and lateral fracture penetration. Previous studies have suggested that there are unequal horizontal stresses which are potentially due to tectonic effects. However, in some cases the magnitude of stress variation and reversal in stress-ordering across minor depths is problematic and confirms the pitfalls of oversimplified assumptions and models used in stress profiling in unconventional reservoirs. This work highlights the magnitude of stress variations within the formation and illustrates an integrated methodology to assist the decisions on selecting hydraulic fracture locations.
Integrated Production Testing Framework to Improve Next Generation Production Workflows
Authors: Rao Subba Rama , David Richard Mohan 
Published: November 2015

Abstract
Production Test data is a critical parameter for several production operations and reservoir management workflow. High quality Production test data is vital for better understanding of the flow behavior and rates to ensure optimized production and maximize the asset value.
Current Production Testing practice in oil industry includes separator testing or MPFM at well heads or at degassing station. However, the frequency of testing varies between one to three months for each well which may not sufficient to realize the full potential of Digital Oil Field (DOF) workflows. Virtual Flow Metering (VFM) technique along with well model results shall provide continuous well rates that would significantly improve the quality of decisions made through the production workflow. This brings in a varied Production testing environment for different well categories and types.
In order to continuously provide the real time production parameters to the DOF workflows, it is essential to integrate the different Production testing techniques through an Integrated Production Testing Framework. In this paper, the authors discuss an Integrated Production Testing Framework that comprise of validated real time and historical data, integrated workflows and the enabling technologies that includes calibrated well models, trained neural network models and visualization tools. Production test data obtained using traditional methods (PTS) and MPFM will be at low to medium frequency. VFM using neural network model estimates the flow rates continuously between the actual tests at a high frequency. This framework is suitable for production, injection wells that are installed with MPFM, PTS, water cut meters and covers different production testing scenarios Like PLT, ESP testing, Long-term MRT and step rate injectivity testing.
The framework enables implementation of continuous estimated rates, exception based alarms, automatic well test validation, track well test operations, guidance for reservoir monitoring program, KPI monitoring, precise back allocation leading to better production optimization and reservoir management across oil and gas producing assets.
This paper discusses an integrated approach to manage different Production testing methodologies to streamline the usage of the data for different workflows..
On the Prediction, Prevention and Remediation of Asphaltene Deposition
Authors: Khaleel Aisha , Abutaqiya Mohammad , Tavakkoli Mohammed , Melendez-Alvarez Ariana A. , Vargas Francisco M. 
Published: November 2015

Abstract
Asphaltene deposition is a flow assurance problem that threatens the continuous production of crude oil. This problem is likely to get worse because of the current tendency to produce from deeper waters and also due to the implementation of enhanced oil recovery operations based on miscible injection of CO2 or hydrocarbon gas.
In this article we present a review of the asphaltene precipitation and deposition problem in oil production, and we describe the commercial techniques used for its determination and quantification as well as their limitations. We also discuss the important progress achieved concerning modeling tools with enhanced capabilities that have been developed to forecast the occurrence and the magnitude of this problem. Prompt recognition of potential asphaltene deposition issues, either for new fields or as part of enhanced oil recovery projects, is necessary to implement successful prevention or mitigation strategies. Unfortunately, current commercial inhibitors have mixed results in the field and in some cases are responsible for worsening the deposition problem. After a thorough investigation we have elucidated a multi-step mechanism of asphaltene precipitation, aggregation and aging, which explains the poor performance of some chemicals and the limited capabilities of the current testing protocols. We provide some ideas for a new generation of asphaltene inhibitors and, for the cases in which asphaltene deposition has already occurred, we also provide a list of common techniques and best practices used for its remediation.
With this work we aim to provide the reader with a broad understanding of this complex problem and to offer a starting point for the development of cost/effective strategies to manage asphaltene deposition in increasingly complex environments.
Lean Workflow for Selection and Implementation of Smart Choke Control to Resolve Slugging in Operations
Authors: T'Joen C. , Groote G. A. , Haandrikman G. , Moeleker P. J. , Cole D. J. , Henkes R. A. 
Published: November 2015

Abstract
In mature fields, pipelines are often oversized for their operating conditions. This is because their design was primarily based on the early and plateau production and less on late life production. This oversizing may lead to slugging issues, whereby flow fluctuations cause liquid handling problems in the receiving facilities, which can lead to system trips. The purpose of this paper is to describe the workflow, which includes identifying the operational problems, designing the slug control system, and commissioning and monitoring of the control system. The Smart Choke developed by Shell1 is able to mitigate the effects of slugs and has now been installed at several locations worldwide. It is an active slug control system: the topside choke acts only if surges are observed, reducing the peak flow rate into the separator. Between slugs, the choke valve opens, reducing the imposed backpressure. Since flow fluctuations are reduced, operation is again possible without risking excessive separator liquid levels.
The workflow consists of the following steps: (i) If slugging leads to production deferment or to operational problems, a feasibility study is done to assess the benefits of installing a Smart Choke. To this end, the key design and production data are collected in a single data sheet that is analyzed by flow assurance experts, (ii) The analysis may include using dynamic multiphase flow models. The models are used to reproduce the slugging behaviour as seen in the field and to assess the adequacy of the Smart Choke. (iii) If the results indicate a positive outlook, and the asset agrees, the implementation needs to be planned and executed. This requires further data gathering on the choke actuator, the pipework for a suitable transducer location, and the platform control system. (iv) The flow assurance and process control experts go to the platform to help commissioning the Smart Choke, which includes tuning of the controller parameters. (v) Once in operation the Smart Choke performance is monitored remotely by the experts using PI Process Book.
In addition to pipeline systems already in operation, implementation of a Smart Choke can also be considered for pipeline projects in the development phase. When in the hydraulic assessment risks are identified with respect to slugging, the decision for full implementation can be postponed, but the production system is made "Smart Choke ready" by reservation of weight/space at a pipe segment at the outlet of the pipeline upstream of the separator. When slugging occurs in a later phase of the field life the spool piece can be replaced by the required Smart Choke hardware without doing any hot work.
Improvement of Decision Making Cycle by Introduction of a Centralized Data Gathering System - Offshore field case from Turkmenistan
Authors: Espinoza R. , Rivadeneira I. Jaramillo 
Published: November 2015

Abstract
Since the award of the PSA for the redevelopment of the fields within the Cheleken Block in Turkmenistan, production has increased from under 7,000 bopd in year 2000 to an impressive 100,000 bopd by mid-2015. Pressures, volumes, temperatures and densities, among other production data is recorded in hourly basis through the field. The excessive man power required to collect, validate and process these thousands of data points on daily basis, made justifiable the introduction of an automatic data gathering system. This system allowed to substantially reduce the time required for data input and validation and therefore making easier and faster the decision making process. Most of the wells produce by natural flow and therefore, they are very sensitive to GOR and water cut changes as well as waxes deposition. Faster decision making in all processes that control these parameters, allowed to reduce downtime and maximize field production capacity.
Integrated Shutdown Management Project to deliver Superior and Sustainable Asset Performance
Authors: Binthabet Hussain Ahmad , Loganathan Lawrence 
Published: November 2015

Abstract
ADMA-OPCO conducted a multi-disciplinary/stakeholder taskforce to analyse learnings from past 10 years of shutdown history across all assets. It was revealed that whilst there were evidence of strong accountability and ownership of safe shutdown execution, inadequate planning and disciplined scope control contributed to shortfalls in overall shutdown performance. It was also identified that approaching shutdown as Integrated Shutdown Management Project (ISMP) provides significant step change towards successful and sustainable future shutdown both short tem and long term.
How to Utilize Hydraulic Fracture Interference to Improve Unconventional Development
Authors: Kurtoglu Basak , Salman Ahmad 
Published: November 2015

Abstract
As unconventional reservoir development progresses, tighter well spacing improves recovery at the risk of an increase in well-to-well hydraulic fracture interference. During stimulation, fractures dilate along preferential planes of weakness that extend into an existing offset well"s producing volume. This can result in water penetration and stress reorientation. The objective is to show how to analyze pressure and rate responses from fracture interference data to impact operations, adjust field development, and identify future upside potential.
The methodology starts with identifying whether fracture interference during hydraulic stimulation is beneficial (positive frac interference) or detrimental (negative frac interference) to offset producers. The impact of hydraulic fracture interference is then quantified by performing multi-phase production data analysis. The system alteration is measured by calculating the changes in well productivity and estimating incremental loss or gained volume for the pre-existing producer due to a frac interference event. This information is utilized to build full field development scenarios by modifying the drilling and completion schedule and well spacing so that the most profitable strategy is obtained.
We identify that the drivers of fracture interference consists of (1) areal variation of reservoir properties, (2) pressure depletion due to the initial generation of wells, and (3) distance between producer and infill wells. The first development scenario evaluates the impact of deferred or gained production due to a frac interference event for different geological areas. The following case high-grades acreage based on areal variation of reservoir properties by delaying the development of deferred or lost production areas due to a negative frac interference event. The last scenario captures the opportunity for a tighter well spacing in areas with positive frac interference event. Based on the learnings derived from each scenario, the most profitable development strategy is presented for a typical unconventional reservoir. Furthermore, a new re-stimulation selection criteria is proposed to capitalize on the benefits of fracture interference. Conclusions are drawn from analyzing multiple multi-stage horizontal wells from the South Texas Eagle Ford and North Dakota and Montana Bakken reservoirs.
In this paper, our results extend beyond retrospective studies by quantifying reservoir changes using a multi-phase approach and utilizing these results to impact development. Prior studies limited the classification of fracture interference as negative consequences of development. However, our investigation indicates that with improved understanding, we relate the impact of these events to development scheduling, confirmation of well spacing, and high-grading acreage to mitigate risks and harness the benefits of fracture interference as a mechanism of passive re-stimulation.
Enhanced Problem Solving in a High Reliability Context
Authors: Gandolfo Joseph A. 
Published: November 2015

Abstract
There is a veritable sub-economy within our industry of professionals, academics, consultants and others deeply invested in analyzing, understanding and solving the age-old problem of improving the reliability, availability and predictability of our production assets. The hard data for production availability is well known within each company and is not the subject of this paper so will not be discussed or presented here but would not be a stretch to quote numbers on the order of +10% loss in availability due to reliability events as a common performance number in our industry. So how could it be that the cost and value of lost availability of our oil and gas producing assets (Not to mention the downstream refining and chemical processing assets) attributed to component and system breakdowns is still quite staggering today almost 30 years after the first academics penned the term "High Reliability Organization"? When we posed this question in Shell 10 years ago it lead down a very interesting path that began to point out what may be missing in our engineering/technical formulations and paradigms that may be contributing. This paper attempts to talk about the part of this journey that lead us to see "Problem Solving" in a much different light.
Integrating Latest Logging-While-Drilling and Geomechanics Technologies to Deliver the First Ratawi Shale Horizontal Well in North Kuwait: A Case History
Authors: Turky Huda A , Azim Shaikh Abdul , Abdulkarim Anar , Samie Mohamed , Aki Ahmet 
Published: November 2015

Abstract
Integration of logging-while-drilling (LWD), nuclear magnetic resonance (NMR), and azimuthal acoustic tools with a geomechanical study resulted in successful drilling of the first horizontal Ratawi Shale well in Kuwait. This tool combination was used for the first time in Kuwait as a part of the bottom hole assembly (BHA), in addition to conventional formation evaluation tools, to acquire porosity without using radioactive sources.
A deviated 8.5-in. borehole section of a well was planned through unconsolidated sand-shale sequences by kicking off from vertical and landing at an inclination of 90°. This geological section is typically crucial from a borehole stability point of view. Borehole deterioration and significant variations in pore pressure can create a high risk of becoming stuck-in-hole. The use of conventional porosity tools in a LWD BHA with installed radioactive sources would significantly elevate the risks to an environmental-hazard level. Additionally, even retrievable-based sources become problematic for successful extraction in high angle wells. Use of sourceless porosity was the perceived solution.
LWD NMR and azimuthal acoustic tools, free of radioactive sources, were run for the first time in a LWD tool combination, with the primary objective to measure porosity, pressure prediction, and possible anisotropy using a centralized four-axis acoustic caliper.
Previous experiences in the same geological setting encountered borehole enlargements by approximately 5 in. after only 15 to 16 hours. LWD helped bypass this issue and acquired high-quality data before borehole enlargement occurred. Additionally, indications of the presence of possible rock anisotropy were observed. The results were then correlated and matched to offset well data and existing field geomechanics knowledge.
Well placement within a sweet spot of 6- to 8-ft thickness in the 6.125-in. lateral section was challenging and required the integration of at-bit measurements as well as distance-to-boundary geosteering tools to reach this objective.
This paper discusses the planning, design, and execution using LWD, NMR, and azimuthal acoustic tools in this well. It also discusses the viability, integrity, and robustness of logged data as well as interpreted results. Optimization of real-time drilling operations and petrophysical data acquisition requirements are also investigated to improve future field development and overall reservoir management strategies.
Advanced Modeling of Well Tubulars Erosion by Solids Including Multiphase Effects
Authors: Wang J. , Troshko A. , Buechler S. , Tavarez F. 
Published: November 2015

Abstract
Solids erosion of well tubulars can be a major factor impacting production rate limitations. It is well known that erosion rate is very sensitive to production rate. Thus, large uncertainty in erosion rate predictions can result in conservatism in lifetime erosion predictions. As a result, operators may unnecessarily reduce production rates due to fears of an erosional failure of the well tubulars.
The best way to predict erosion is through experimental testing; however, in many cases experimental testing can be unrealistic prompting the use of various erosion predictive models to improve well design and production practices. Erosion is a complex phenomenon and even with the most comprehensive and accurate models based on Computational Fluid Dynamics (CFD) prediction of erosion rate is often only a ballpark estimates without proper validation. Furthermore, many wells produce both gas and liquid resulting in different multiphase flow regimes. The location of each phase in the flow stream can have a significant impact on erosion rates. For example, it is known that the presence of thin liquid films along tubular walls in gas flows can significantly reduce erosion rates. Thus, complex modeling of multiphase flow must be incorporated into erosion models in order to accurate capture erosion rates.
This paper presents a comprehensive CFD-based model applicable to various well completion types. Our model incorporates solids erosion as well as various multiphase flow regimes. The model was validated extensively against experimental data and shown to improve on previously published erosion patterns and trends in terms of both erosional hot spot locations and erosional rates. This improved model can significantly reduce the uncertainty in solid erosion prediction for use in the selection, design and optimization of well tubulars and completion equipment (e.g. wire wrap screens and inflow control devices).