bluuebunny/crossref_metadata_2025 huggingface dataset:
MPFM Commissioning Optimization: A Case Study
Authors: AlDabbous Mohammad S. , Al-Kadem Mohammad S. , AlMashhad Ali S. , AlSadah Hassan A. , Alzahrani Mohammed S.
Published: November 2015

Multiphase flow meters (MPFMs) are being widely employed in the oil and gas industry for a higher rate test frequency in the producing wells and for continuous production monitoring. But after the installation and before it provides services, a MPFM experiences a lengthy process that is comprised of meter calibration, settings configuration and wellhead sampling for liquid density checking. To accomplish this process is often challenging in offshore fields due to the adverse weather conditions and the high costs of offshore activities. That has hindered the MPFM commissioning activities in many Aramco offshore fields and consequently affected the testing requirements.

A MPFM is an intelligent metering device which is very sensitive to the fluid's PVT properties, fluids densities, H2S and CO2 contents. A typical calibration of a MPFM in Aramco offshore fields often requires taking fluid samples from each individual well for the fluid density check and determination of mass attenuation of oil due to the fluid density variations in a field. An offshore MPFM often covers the testing requirements for all 6 to 8 producers on a platform. Hence this method always takes a long time to take wellhead fluid samples for completing the calibration process of a single MPFM, and tends to lag far behind their planned commissioning schedule.

In 2013, thirty seven new MPFM were installed in 37 different platforms covering more than 122 wells in one Aramco field. A commissioning and calibration campaign was launched early this year with a different approach after carefully analyzing the PVT properties of the produced fluids. In this approach the typical calibration work was first performed on 3 wells, and then the same settings and parameters were copied and uploaded as a batch to those remaining MPFMs covering other 119 wells in this field. This method significantly reduced the time for marine boat support. Furthermore, those 119 wells are being remotely flow tested in a batch via Supervisory Control and Data Acquisition (SCADA) to verify if any further adjustment is required. Due to H2S and CO2free in the produced fluids, and the almost constant liquid densities throughout the area in this field, the accuracy of the MPFM measurement can't be compromised by taking this process. The paper describes a new method that significantly reduced the total time for the 37 MPFM calibration and commissioning jobs and saved the costs.
Owning Risk to Improve Equipment Integrity
Authors: Henry Neil S
Published: November 2015

Many applications of risk based practices are used in industry for inspection and Process Safety Management. There are benefits to integration of the two processes and ensuring relevant local data is included, to show how risk can be managed by effective "ownership".

In the process of carrying out numerous studies for a range of petrochemical industries, it has become clear there is a relationship and synergy of these techniques which can strongly influence the mechanical integrity of assets. It has been found that focussing on the consequences of an event may unduly influence risk management practices, when trying to ensure integrity of process equipment. In many cases, the probability of a failure and its scale, from a small leak to a major failure, are not fully utilised to help define accurately the integrity risks for process equipment.

The observations used in preparing this paper, have been drawn from both failure investigation and integrity reviews. These suggest a lack of confidence in understanding the potential for deterioration of assets. This in turn results in difficulty to assess where the true risk of a loss of containment is greatest and how it can be managed. Examples of combining the information used for risk based inspection or process hazard studies are shown, and how this knowledge may be applied in practice are given.

Application of operational experience is used to demonstrate these principles and their influences on equipment condition. The basis of the approach is to start from understanding real deterioration risk and working on prevention to reduce probability, rather than assigning a theoretical value, then trying to manage the consequential risk.
Improving the Accuracy of Onshore Pipeline Remaining Life Assessments and Optimising Field Verification Activities from Detailed Assessment of Corrosion Metal loss Feature Interactions
Authors: Morris J. R. , Regis R. T. , Upadhyay S. H. , Rajashekar V. K. , McNaughtan D.
Published: November 2015

This paper discusses approaches to improve the accuracy of onshore pipeline remaining life assessments and optimise the targeting of locations for field verification activities via detailed assessment of reported corrosion metal losses and corrosion feature interactions. The overall aim is to show how confidence in assessments can be increased while ensuring adherence to industry standards.

Evaluation of interactions between corrosion features is a necessary consideration as specified in industry standard fitness-for-service (FFS) methodologies. In accordance with developed FFS standards, if corrosion features are sufficiently close together, they should be considered to act as a single, larger feature. However, in the authors' experience, detailed assessment of corrosion feature interactions is not always performed. This can lead to overly optimistic/pessimistic results, and a subsequent lack of focus for future field verification activities with respect to inspection locations and techniques.

FFS assessments are often based on results from in-line inspections (ILIs), which, depending on the pipeline condition, can report many thousands of individual corrosion features. In the case of heavily corroded pipelines, where corrosion damage is reported along approximately the same orientation (for example at 06:00, the bottom of the line), inadequate consideration of corrosion feature interactions could significantly overestimate the maximum allowable safe pressure of the pipeline. In contrast, conservatively assuming a grooving metal loss morphology and simplifying FFS calculations to assume infinitely long corrosion can appreciably lower calculated safe pressures, resulting in premature remediation activities (such as repairs, de-rating). In both cases, neither method of assessment allows specific targeting of field verification activities as areas of maximum corrosion interaction will not have been determined.

This paper will demonstrate the benefits of performing a detailed assessment of corrosion feature interactions during an integrity assessment in comparison to overly optimistic or simplified assumptions, and show the benefits of such detailed assessment with respect to future field verification activities.
Robotic Inspection Solutions for Petrochemical Pressure Vessels
Authors: Bos Barend van , Mallion Adam , Wilson Craig , Zwicker Ekkehard , Schler Andreas , Black Timothy
Published: November 2015

Virtually all equipment in the oil, gas and petrochemical industry requires some kind of periodic inspection. Pressure vessels are an important part of the production process; currently the inspection of these are being done by human inspectors that require entry into the vessels. The working environment inside these vessels is potentially dangerous, and substantial precautions must be taken ensure the safety of the inspectors. These precautions take considerable time, making the inspection both very costly and hazardous.

Robotic technology offers a safe alternative to human entry, and is now advanced enough to perform inspections remotely, minimising human entry thus increasing safety.

The PETROBOT project has brought together inspection methods and robotic technology to reduce risks and cost involved in inspection of pressure vessels. PETROBOT comprises the complete value chain, from robot and inspection technology providers, to inspection service providers and end-users. The project has developed robotic deployment platforms and adapted industry standard inspection techniques to demonstrate the benefits of remote pressure vessel inspection.

This paper presents the use case and progress made under PETROBOT for the inspection of pressure vessels. Two different, yet complementary robots have been developed, one a magnetic crawler; the other, a snake-arm robot. The two systems enable robotised inspection capabilities in a variety of pressure vessel designs. The robots carry a payload consisting of inspection tools: a camera for visual inspection, structured light for profilometry, and an ultrasonic transducer, and an eddy current transducer.

These novel inspection technologies have been integrated into the robotic systems and have been tested and verified on artificial defects, as well as real pressure vessels in a laboratory environment. During the final stages of the PETROBOT project, they will be deployed in real installations of the participating end users.
Successful Chemical Water Shut-Off Treatment in an Omani Field Heavy-Oil Well
Authors: Dupuis Guillaume , Bouillot Jerome , Templier Arnaud , Zaitoun Alain
Published: November 2015

This paper relates the successful water shut-off treatment of a heavy-oil Omani well combining the use of microgel and gel.

As many sandstone reservoir with strong aquifer in Southern Oman, this vertical well faced early water breakthrough along with sand production. Water cut increased dramatically until reaching 100%. The average permeability was around 500 mD but effective permeability ranged from milli Darcy to several Darcy. Due to well characteristics (several perforation intervals, gravel pack, etc…), it was not possible to identify and isolate the water production zones, which oriented the strategy towards the use of RPM products (Relative Permeability Modifiers). The treatment consisted of microgel and gel injections which were bullheaded into the whole open interval. After the treatment, the water cut dropped from 100% to 85% and sand production was stopped over a period of time superior to one year. The treatment was cost effective, producing more than 9000 bbl of extra oil in one year.

In this paper, we describe the treatment design methodology combining laboratory study and near wellbore simulations, and the optimization of injection sequences. Finally, the treatment execution is detailed followed by the presentation of the results obtained since the realization of the operations.

The results show that combining low-risk approach and low-cost RPM technology is an attractive way to restore productivity of watered out wells, in which conventional water shut-off zone isolation is not feasible.
Alternative Conveyance Method for Log Data Acquisition in Abu Dhabi Onshore Oil Fields - A Case Study
Authors: Ahmed Basma Ali , Celma Rafael , Dhache Ali , Mostafa Hassan , Chinchayan Gustavo , Farouk Omar El
Published: November 2015

One of the major challenges in Abu Dhabi onshore oil fields is the substantial increased water production with time. This is mainly attributed to unforeseen the presence of sub seismic faults and fractures along the drain hole. To address this, smart completions are being introduced to control water production by moderating the flow profile across the completed interval, whereby water and gas breakthrough are delayed in producing wells and injection rates are optimized in water and gas injectors across the full wellbore face. The smart completion design is supported by dynamic and static reservoir information. In this study, production logging tool (PLT) data was available to benchmark and confirm the results from dynamic simulation modeling. However, geologic features that cause the uncontrolled water inflow were not confirmed due to lack of lack of image data.

A novel methodology has been implemented allowing resistivity image acquisition in workover wells by utilizing a compact memory tool that addresses the challenge of accessing old wells in Abu Dhabi onshore oil fields. The poor condition of the well is a result of prolonged production, post-stimulation and subsequent borehole degradation. The technique consists of acquiring data using drill pipe with significant savings in rig time and a higher chance of accessibility when compared to alternative techniques. This technique also protects the tool from becoming stuck and incurring damage during entry, thus improving data acquisition quality and minimizing the possibility of re-runs. When compared with common pipe-conveyed wireline alternatives (TLC) in previous wells, up to 33% savings in logging time was observed with a much safer operation.

The procedure was achieved with success in terms of image data quality and execution time. In the absence of core data, the microresistivity imaging technique gives the best possible picture of the rock. It has been effective in characterizing rock fabric required for structural analysis (including fracture identification and fault identification and analysis), geomechanics, sedimentology (including paleocurrents analysis and facies determination) and image petrophysics applications such as identifying vuggy secondary porosity. A quick- turnaround in data processing allows the introduction of detailed fractures and fault interpretation, which in turn allows optimization of the completion design.
Liquid Waste Management in E&P - Cairn India Case Study
Authors: Ray Rimjhim , Kapadia Gautam , Sambasivam Srikrishna
Published: November 2015

With an average gross operated production of 211,671 boepd in FY2015, Cairn India Limited (CIL) is the largest private sector producer of crude oil in India. In FY 14-15, around 120 wells were drilled in Mangala, Bhagyam and Aishwariya alone. Waste water generation in Operations has seen a massive increase in recent years because of increased production and an aggressive drilling campaign.

CIL operates on Zero Surface Effluent discharge philosophy making it imperative to deliberate on waste water disposal strategy. Managing the huge volumes of waste water in a sustainable manner is a challenge. Accordingly, waste water treatment plant for reuse and waste pits and guard ponds were created to evaporate waste water. Due to waxy nature of oil in waste water, high level of suspended solids and bacterial degradation, natural evaporation is almost negligible. Waste water accumulation over a long period of time has resulted in inventory buildup of all the pits. It has become business critical requiring strategic focus to ensure business continuity and sustainability.

Given the challenges of waste water management in onshore Oil & Gas operations, the paper describes the various technologies available in the market and tested by Cairn, results of market studies carried including pros and cons of each option, followed by pilot-scale implementation of the chosen technologies. The paper not only describes the success of the pilot studies and the related technical aspects, but also the commercial, socio-economic and stakeholder challenges and the approach to applying the selected option for full-field implementation. The paper concludes with suggested way forward for full-field implementation including associated challenges and success factors.

The objective of this paper is to share the experiences of an operating company with other oil & gas Companies worldwide on various aspects relating to waste water treatment and management in onshore oil & gas operations. The typical process for an Oil & Gas Operator is to evaluate all aspects, right from technology finalization to economic optimization and finally develop an integrated roadmap for the entire project. A firm methodology was adopted to validate the technical as well as the commercial aspects of the project. The final treated water is put for reuse thereby delivering twin benefits in terms of handling waste water in a sustainable manner as well as optimizing the water footprint.
Managing Process Safety Through Effective Integrity Management
Authors: Holthoon Evert van
Published: November 2015

Shell Upstream has been through a significant journey to establish and/or confirm Design Integrity, Operating Integrity, Technical Integrity and to strengthen Integrity Leadership. This covers existing assets as well as design, construction and startup of large projects.

This paper aims to provide a fresh perspective on the pivotal role of Integrity Leadership, needed to deliver the journey to Goal Zero, No Harm and No Leaks. The paper covers: What it takes to understand Process Safety Performance, and how to develop local as well as global insights across a large asset baseIndustry benchmarking, and the opportunity it presents for PS Performance benchmarking.Shell's perspective on more effective application of Learning from Incidents (LFI), using a more engaging and reflective learning setup. The reflective learning material for Process Safety, "I own my barrier", was released in April 2015.New insights gained from PS culture surveys.The role of Leaders at different levels in the organization to manage and improve Process Safety performance. What it takes to move from a Calculative to a more Proactive culture in existing assets.
Planning of Low Salinity Water Flooding with the use of Novel Laboratory and Numerical Simulation Studies
Authors: Othman F. , Aljehani A. , Kanfar M. F. , Abdel Azim R. , Ding H. , Gholizadeh N. , Rahman S. S.
Published: November 2015

In this paper, we present an integrated approach to study the effect of low salinity water flooding on the oil recovery. This is achieved in four steps: first, we have extended our multiphase fluid flow simulation in porous matrix discrete fractures by integrating the electrochemical model. The electrochemical model estimates disjoining pressure from the knowledge of which in turn is a function of different chemical species and their concentration, pH and temperature. Next, the film thickness, which is controlled by different chemical species is determined by using atomic force microscopy and compared with the values estimated by the chemical model. In the third step, we carried out low salinity water flooding on fractured carbonate core samples using a combination of different ions and their concentrations and recovered oil was measured. In these laboratory experiments water floods in core samples with single fractures are simulated to study the effect of heterogeneity (discontinuity) on oil recovery. In the final step we have used our multiphase flow simulator to study low salinity water flooding in laboratory core scale. The results of this study are evaluated by comparing with the results obtained in the laboratory.

The results of this study show that the water film thickness is directly related to brine concentration. There exist, however, an optimum concentration at which maximum thickness can be reached. Above this optimum concentration water film thickness gradually decreases. Core flood tests have shown similar results, that is maximum oil recovery can be obtained at an optimum brine concentration.
A Semi-Analytical Model for Extended-Reach Wells with Wellbore Flow Splitting; a Production Optimization Scheme
Authors: Al Qahtani Abdullah , Al Hashim Hasan , Al Yousef Hasan
Published: November 2015

Well design have evolved noticeably during the last decade from the design of conventional vertical wells to extended-reach/multilateral horizontal well design using directional drilling technology. Evolving horizontal well design range from simple horizontal wells with single wellbore to complex multilaterals with multiple sublaterals (fishbone wells). Furthermore, advancements in horizontal well drilling allows horizontal wells to be drilled several thousands of feet long. However, field experience and flow meter surveys on long horizontal drain-holes revealed that the frictional pressure losses in the wellbore is an important factor limiting the effective length of long horizontal wells and consequently hindering the full use of the entire length of the horizontal wells. The frictional pressure losses may be comparable with the drawdown at the producing end of the well rendering a portion of the horizontal drain-hole unproductive.

Well completions have also been advancing to cope with the technological advancement in horizontal well drilling and new equipment for monitoring and subsequent selective control have been developed to optimize the productivity of the horizontal wells. The complex architecture of those wells generally makes them more expensive to drill and complete. Therefore, these wells must be planned efficiently.

For these reasons we present a viable method to produce these long horizontal wells and laterals from the two ends (heel and toe) by using U-shape wells. The introduction of the U-shaped wells is driven by the need to maximize flow contribution from the entire drain-hole lengths. To confirm the viability of this idea, a rigorous semi-analytical model was developed to study the performance of the U-shape horizontal well under different production scenarios. The model incorporates the impact of wellbore hydraulics into the solution, and the U-shaped wells can be produced from both ends at constant rates to predict the pressures at the two ends. The model was used to calculate the flow profile along the horizontal section under different production scenarios. Furthermore, the model can be used as an optimization tool to maximize the benefits from long horizontal drain-hole as it allows producing the two wings at different flow rates. The U-shape wells can also be optimized to have more uniform flux distribution along the horizontal drain-hole in reservoirs subjected to water drive. The developed model can also be used to evaluate the reservoir parameters in such well architecture by calculating the classical horizontal well performance and reservoir characteristics by measuring wellbore pressure at one or both wings.
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

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 (< 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

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

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

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

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

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

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

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

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

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

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).
Integrating Seismic and Well Data into Highly Detailed Reservoir Model through AVA Geostatistical Inversion
Authors: Sulistiono Denny , Vaughan Richard , Ali Mohamed , Rasoulzadeh Shervin
Published: November 2015

Building a reservoir model by integrating seismic angle stacks and well data has been challenging for oil and gas companies. Seismic data contain very detailed information of reservoir properties lateraly but lack vertical resolution while well data provide very detailed information vertically but lack horizontal information. One established method of integrating these two kinds of data is deterministic seismic inversion. Deterministic seismic inversion has proven to be a good method in delineating the reservoirs at seismic resolution but it has limitation in analyzing thin reservoirs and it only pruduced one result. Geostatistical seismic inversion method has the ability to integrate many types of data and produce multiple relaizations of the results. The realizations are at much higher details than seismic data and are able to capture thin reservoirs.

An AVA geostatistical seismic inversion workflow was successfully implemented to produce highly detailed reservoir models of Abu Madi reservoir sands in Nile delta, Egypt. Abu Madi Formation is composed of lacustrine turbidite deposits in semi-isolated basin and can be subdivided into Upper and Lower reservoirs. Intraformational shale baffles occur quite commonly within Abu Madi Formation which acted as barriers of pressure depletion between the Upper and Lower reservoirs. Well data analysis has demonstrated the complex pattern of the stacked reservoir sand zones of heterogeneous reservoir parameters and pressure trends. The main objective of the study was to produce reservoir models that could be used to understand the observed pressure depletion trends within the Upper and Lower Abu Madi reservoirs which have great significance for effective field management.

Seismic angle stacks and well data were integrated through AVA geostatistical inversion to produce highly detailed lithotype and elastic property results at 0.5 ms vertical sampling. Thesse models have successfully captured the shale baffles. Lithotype and elastic property realizations were used to co-simulate for reservoir (engineering) properties of Effective Porosity and Volume of Clay. The Effective Porosity and Volume of Clay realizations were then ranked to provide the P10, P50 and P90 models to be used as input for dynamic flow simulation. Five permeability rock types were derived based on extensive SCAL database and used to define the permeability and saturation models. These detailed engineering models were used for dynamic flow simulation and successfully predicted the pressure depletion trends in the Abu Madi reservoirs.