bluuebunny/crossref_metadata_2025 huggingface dataset:
An Effective Iterative Workflow towards an Improved History Match of a Highly Heterogeneous Giant Offshore Carbonate Reservoir - Challenges and Lessons Learned
Authors: Obeta Chukwudi , Shekhar Ravi , Al Breiki Sameeha , Al Naqbi Amna , Hermann Rolf , Ottinger Gary , Li Dachang , Al Neyadi Abdulla , Al Shehhi Budoor
Published: November 2018

The subject reservoir has been on production for decades and suffered early water breakthrough due to significant geologic heterogeneity. The existing dynamic model was last history matched in 2010, and the match quality had deteriorated over the last few years of production life. Significant volume of new data had become available, including SCAL, cores, wireline logs, production and surveillance data which were recently leveraged to update the static model based on new geomodelling best practices. The justification for progressing to history match the new static model was the business need for a fit-for-purpose tool required to support the life cycle development and management strategy for the reservoir which is evolving from 5-spot flood scheme to line drive utilizing state of the art pilot well technology.

Water channeling is an important phenomenon in the stratigraphically zoned reservoir, and since some of the diagenetic features are co-located at the same intervals, identifying which are key actors for fluid flow was one of the greatest challenges encountered, hence the adoption of fluid travel time concept for mapping and tracking of preferential flow pathways, and for accelerated history match learnings. Intensity attribute measured in count per foot for diagenetic features underpinned spatial permeability modification for model calibration. However, history match changes which include facies intensity modification, footprint and geometry adjustment, permeability magnitude, etc were not just expedient on achieving history match but were all data supported and fed through a closed iterative geo-engineering loop for geologic plausibility and consistency verification prior to been incorporated in the dynamic model.

A good history match was achieved for all calibrated parameters, and the near-perfect vertical conformance prediction of 10 recently acquired water saturation logs is a confirmation of the integrity and predictive capability of the New Generation Model.
Application of STAMP to Process Industry
Authors: Aglave Amit , Chaudhuri Debopam , Johnson Stephen
Published: November 2018

Objectives/Scope

Hazard identification is one of the most important activities carried out in the Safety Instrumented System (SIS) safety lifecycle [1]. Proper hazard identification and analysis of its risk lays the foundation of the SIS design.

Methods, Procedures, Process

The common method for a structured study for the hazard identification is Hazard and Operability Study (HAZOP) study. The concepts of HAZOP are well evolved and applied for over five decades. The basic premise for HAZOP considers plant design is mature enough and sufficient design information on the plant operation is available. HAZOP process involves breaking down of complex process into simpler sections which are termed as nodes. These individual nodes are then studied for identifying the potential hazards and operability problems.

STAMP (System-Theoretic Accident Model and Processing) [2] is accident causality model based on systems theory. STPA (System Theoretic Process Analysis) is one of the STAMP based tool which is a relatively new hazard analysis technique based on an extended model of accident causation. STPA is a proactive analysis method that analyzes the potential cause of accidents during design development so that hazards can be eliminated or controlled. Conventional studies like HAZOP considers deviations or component failures as cause for what may go wrong and cause accident. STPA assumes that accident may also be caused due to unsafe interactions of the system components, none of which have failed.
Data-Driven Analytics: A Novel Approach to Performance Diagnosis Using SpatioTemporal Analysis in a Giant Field Offshore Abu Dhabi
Authors: El Faidouzi Mohamed Mehdi , Ouzzane Djamel Eddine
Published: November 2018

The field of data-driven analytics and machine learning is rapidly evolving today and slowly beginning to reshape the petroleum sector with transformative initiatives.

This work describes a heuristic approach combining mathematical modeling and associated data-driven workflows for estimating reservoir pressure surfaces through space and time using measured data. This procedure has been implemented successfully in a giant offshore field with a complex history of active pressure management by water and gas.

This practical workflow generates present-day pressure maps that can be used directly in reservoir management by locating poorly supported areas and planning for mitigation activities. It assists and guides the history matching process by offering a benchmark against which simulated pressures can be compared. Combined with data-based streamlines computation, this workflow improves the understanding of fluid flow movements, help to identify baffles and assists in field sectorization.

The distinctive feature of this data-driven approach is the unbiased reliance on field-observed data that complements complex modeling and compute-intensive schemes typically found in reservoir simulation. Conventional dynamic simulation and the tracing of streamlines require adequate static (e.g. permeability tensor) and dynamic models (e.g. pressures for each active cell in the system).

Alternatively data-driven streamlines are readily available and calibrated.

This paper presents innovative algorithms and workflows to the relatively limited existing body of literature on data-driven methods for pressure mapping.

In this case study, new insights are effectively revealed such as inter-reservoir communication, enabled a better understanding of the gas movement and supported the change in production strategy.

The paper is organized as follow. After a general overview of the field studied, this paper describes in detail the workflows used to interpolate pressures in space and time along with cross-validation results. Various applications of the pressure predictions are presented in the sections thereafter.
Development of a New Reservoir-Friendly Drilling Fluid for Higher Gas Production
Authors: Al-Yami Abdullah , Al-Jubran Mohammed , Wagle Vikrant , Al-Mulhim Marwan
Published: November 2018

Drilling gas reservoir requires high mud density to balance the reservoir pressure. To formulate such fluids, calcium carbonate (CaCO3) was used because of its high acid solubility. However, due to the high concentration of CaCO3 required for high density drilling fluid, sticking might occur which might result in fishing and/or sidetracks operations. To minimize sticking problems, barite (BaSO4) is added with CaCO3 to reduce the amount of solids needed to formulate the drilling fluid. However, barite can cause potential damage because it does not dissolve in commonly used acids.

Drilling fluids were developed at a wide range of densities using CaCl2 salt with Manganese Tetroxide (Mn3O4). No similar formulations were developed before to the best of the authors’ knowledge. The properties of small particle size (D50=1 microns), spherical shape and high specific gravity (4.9 g/cm3) of Mn3O4 make it good weighting material to reduce solids loading and settling compared to CaCO3 (2.78 g/cm3 and D50=10 microns) and BaSO4 (4.20 g/cm3 and D50=20 microns). The objective of this study is to show the lab work involved in designing water-based drilling fluids using CaCl2 / Mn3O4.

The experimental work in this paper involved rheological properties, thermal stability, API and HT/HP filtration. The data generated from this study showed that Lignite and Vinyl amide/vinyl sulfonate copolymer are recommended to provide good rheological stability and filtration control for CaCl2/Mn3O4 drilling fluid. Polyanionic cellulose polymer and starch can used to formulate KCl/Mn3O4 drilling fluid with good properties at 300 °F.
Challenges of Gas and Oil Mega-Projects: Suhar Refinery
Authors: Kalyanam Sunder
Published: November 2018

EPCC for the Suhar Refinery Improvement Project in Oman

Objectives/Scope: Please list the objectives and/or scope of the proposed paper. (25–75 words)

The Suhar Refinery Improvement Project is one of the largest oil and gas projects ever awarded in Oman. Valued at US$ 2.1 billion, this was truly a ‘mega project in region’ and was executed by Petrofac in Joint Venture with Daelim and successfully completed in 2017.

Methods, Procedures, Process: Briefly explain your overall approach, including your methods, procedures and process. (75–100 words)

Petrofac and Daelim provided a turnkey Engineering, Procurement and Construction and Commissioning (EPCC) solution, which involved upgrades and improvements at the existing facility as well as the addition of new refining units. Delivered through a lump-sum turnkey model, Petrofac leveraged more than three decades of EPC expertise in Oman to shape its local delivery and reduce supply chain costs. Petrofac formed an integrated team with its partner Daelim, the client and JV partners to create a seamless approach, this included a focus group initiative toward flawless start-up as well as the utilisation of common systems, procedures and processes.

Results, Observations, and Conclusions: Please describe the results, observations and conclusions of the proposed paper. (100–200 words)

On completion Sohar's existing output increased by more than 70% to exceed 185,000 barrels per day as well as significantly improving environmental performance. The project's safety performance was exemplary, achieving more than 53 million man-hours without a lost time incident, with a peak project manpower of 14,000.

The creation of In-Country Value (ICV) was a guiding principle throughout, involving the training and development of Omani nationals and the support of local supply chains. The Suhar Refinery Improvement Project was on the winning nomination list that aided ORPIC to win the ICV Strategy Award in 2016. Resourcing was a critical component of the project both in terms of manpower levels required and the drive towards ICV.

Novel/Additive Information: Please explain how this paper will present novel (new) or additive information to the existing body of literature that can be of benefit to and/or add to the state of knowledge in the petroleum industry. (25–75)

This paper aims to showcase the ability of major contractors to work in unison, sharing knowledge and capabilities, to reduce the challenges faced in the execution of mega projects; as well as the role of local content in successful implementation of major projects enabling the development of a capable local workforce.
Enhanced Life Cycle Costing Approach to Tubing Material Selection - New Cost and Revenue Drivers Identified from Experience with Non-Metallics Downhole
Authors: Radhakrishnan Gokulnath , Sharma Ashwani Lata , Venkataraman Eswar , Fernandes Alwyn
Published: November 2018

ISO 15663 Lifecycle cost (LCC) analysis principles are commonly applied to evaluate the viability of downhole tubing materials. This includes the initial CAPEX, operating or maintenance OPEX, Replacement costs and Revenue impact of tubing failure. Increased implementation of Glass Re-informed Epoxy (GRE) Lined tubing has provided significant evidence of flow assurance benefits of the system. This paper will present a modern adaptation of LCC analysis based on operator data and quantification of these benefits and savings.

With over 100,000 GRE Lined completions worldwide there are numerous reported cases of flow enhancements and savings besides corrosion mitigation. The paper is based on extensive research of data collected with agreement from operators representing cost savings or additional revenue that can be factored into LCC analyses with a fair degree of accuracy. Overall operational savings that operators have derived from flow assurance benefits of GRE Lined Tubing, such as improved thermodynamics, scale mitigation, reduced pressure drop, etc. are substantiated using field data from downhole logs, analysis of produced fluids and inspection of retrieved GRE Lined tubing.

Operators have reported higher temperature at well head in Oil Producers after steel tubing was replaced using GRE Lined Steel tubing. This has been associated with savings in separation costs at the surface. There are several reports of higher flow rates and reduced pressure drop across GRE lined tubing which translates to higher injectivity or production. Operators have numerous references of improved and stable flow rates for longer durations when compared to bare steel tubing due to the mitigation of carbonate scale deposition which would impact flow dynamics. Such cases represent significant improvements to production efficiency and, consequently, the overall return on investment in the asset.

The findings of research on multiple operator flow enhancement case references, while implementing GRE Lined Tubing, are illustrated graphically to represent savings and/or additional revenue in comparison with graphical representations of traditional LCC calculations models based on ISO 15663 key drivers i.e. CAPEX, OPEX, Revenue Impact and Replacement Costs.

It is anticipated that this paper will influence a paradigm shift that guides operators to consider the impact of flow enhancement, improved thermodynamics, improved injectivity and/or production, simplification of surface facility requirements and other fringe benefits, in addition to CAPEX, OPEX and Revenue, while evaluating the LCC of tubing material alternatives.
Advanced Assisted History Matching of a Large Mature Oil Field Based on a Huge Number of Grid-Block Level Parameters and Saturation Functions
Authors: Almuallim Hussein , Ganzer Leonhard , Uematsu Hiroshi , Bellah Samir , Virlan Viorel
Published: November 2018

Constructing reservoir models that are consistent with geophysical and geological static data is well understood. A persisting challenge is to condition such models to the available production dynamic data through the process of history-matching. A new algorithm is utilized to identify influencing grid-block properties based on analytical sensitivity calculations. The derived sensitivities allow efficient modification of grid-block properties and saturation functions to improve the history-match. This innovative approach preserves the geological model features, because changes are done at the grid-block level and are only as small as needed to achieve a good match.

Usually, the number of parameters is so immense that engineers have to either restrict their attention to a small subset of the parameters (and likely missing crucial ones), or unnecessarily pay extremely high simulation costs. In this paper, we employ a new assisted history-matching technique that computes the parameter sensitivities analytically and for each grid-block. Here, the derivatives of the mismatch with respect to each parameter are rigorously computed based on the black-oil simulator's fluid flow equations. Hence, a single simulation run followed by a derivatives calculation session is sufficient to detect how each parameter affects the mismatch, and consequently, to decide how (or whether) to change each parameter to improve the match.

This technique was successfully applied to history-match a mature oil field in the Middle East. Two sets of parameters are modified: The permeability in 3 directions per grid block, and relative permeability curves for about 50 saturation regions. The goal was to match water-cut for individual wells.

With this analytical technique, excellent improvement in the match was achieved after only a dozen simulation runs and within a couple of days. Because the modifications are at the grid block level and minimal (only as and where needed), the technique preserves the original geological features of the model to a great extent. Eliminating the need of manual local modifications (e.g. box multipliers) is an important advantage of the method. The relative permeability curves have been tweaked successfully for numerous saturation regions using Corey model parameters. The ability to adjust many curves successfully using just a few simulation runs represents a significant advancement in the field of assisted history-matching.
Cutting-Edge Solutions for Sour Gas Treatment- A Retrospective Study by Kuwait Oil Company
Authors: Al-Ghanem Fahad , Al-Jabri Saleh , Abdul Hameed Mohamed Rizwan , Al-Saeed Mohammed , Al-Otaibi Mohammed
Published: November 2018

Kuwait Oil Company (KOC) owns and operates several Oil & Gas fields and Pipeline networks in Kuwait and is responsible for exploration, development, production and operation of Kuwait's Hydrocarbon assets. The oil fields in the western part of the state predominantly produces high sour gas and normally the compressed sour gas is transported to downstream refineries for treatment, wherein the Acid Gas Removal Plants extract the sulfur contents in the gas received by treating it with regenerative Amine based treating processes for removing acidic impurities such as H2S, CO2 and organic Sulphur compounds.

The country has been long battling with the limitations in downstream sector such as limited handling capacity, unplanned shutdowns, and delay in their expansion projects. This created huge bottlenecks for the upstream unit of KOC which consequently resulted in operational disturbances and gas flaring beyond the company's global flaring target of < 1%.

To overcome these challenges, a comprehensive study was carried out for sour gas handling in the State of Kuwait and installation of Gas Sweetening Facility (NGSF) within KOC was considered imperative. However, the process of project delivery was a great challenge due to emerging operational approaches and conflicts with expansion projects in refinery. Thus, breakthrough solutions were set out deploying appropriate core technologies. This paper discusses the challenges at length and the innovative solutions implemented which were intended to optimize the production and utilization of gas in support of energy requirements for the State.
Asphaltene Precipitation: A Review on Remediation Techniques and Prevention Strategies
Authors: Al-Qasim Abdulaziz , Al-Anazi Amer , Omar Abdulrahman Bin , Ghamdi Muataz
Published: November 2018

In the last few years, large efforts have been made to develop advanced and smart technologies that can predict and prevent asphaltene precipitation. In the history of asphaltene deposition science, two schools of thought have emerged to predict the phase behavior of asphaltene. One school uses colloidal science techniques, believing that asphaltene exists in oil at a colloidal state. The other school adopts thermodynamic methods, believing that the asphaltene occurs in oil in a true liquid state.

The main drawdowns of asphaltene deposition in some reservoirs that are prone to asphaltene precipitation are the alteration of reservoir rock's wettability, and the plugging of the formation, flowlines and separation facilities. Different production strategies have been developed to eliminate or reduce the asphaltene precipitation. As asphaltene properties are dependent on its composition, as well as the reservoir temperature and pressure, thermodynamic and kinetic control strategies are utilized to control the pressure and temperature of the system or the conditions of solid formation. Common intervention techniques include stimulating the well periodically using a mixture of acid, xylene, and mutual solvent. Advancement in the asphaltene flocculation-inhibitor treatments allows it to be used in treating the asphaltene in the reservoir without damaging the formation. There are some limitations and environmental restrictions on the current conventional intervention techniques associated with using low flash-point chemicals. These limitations can be resolved by using environmentally friendly techniques, such as laser energy to disturb asphaltene particles.

This paper will discuss the asphaltene precipitation and deposition phenomena, preventive and detection techniques, and intervention methods and their limitations, providing a comprehensive overview on the current practice in asphaltene remediation and prevention.
Drilling Waste Management – Solutions that Optimise Drilling, Reduce Well Cost and Improve Environmental Performance
Authors: Phillips Laurie , Morris Andrew , Innes Gareth , Clark Adrian , Hinden Pierre-Marie
Published: November 2018

This paper highlights the value associated with the thermal processing of drill cuttings offshore, at source, on an operational and economic basis for a single well drilling campaign.

Treating materials at source eliminates the requirement to transport drilling wastes long distances onshore for treatment and/or disposal, significantly reducing logistics costs and the likelihood of safety and environmental incidents.

The paper outlines a safe, efficient and reliable at source drilling waste management solution that increases operational efficiency, supports well cost reduction initiatives and exceeds regulatory requirements.

It also demonstrates that mobilizing this solution as an onboard drill cuttings processing spread for a one- well drilling campaign is cost-effective.

The paper draws on a detailed case study in which thermal drill cuttings processing technology was mobilized for a one-well drilling campaign on the Orlando field in the UK North Sea, under a contract between TWMA and the Licence Operator but managed by the Well Operator AGR Well Management (AGR).

Using a process of thermal desorption, the solution allows the recovery of three elements from the drill cuttings: oil, water and solids. Recovered base oil, which retains its full original quality, can be reintroduced to the drilling mud system, and recovered water and solids can be safely dispersed on location as they are processed to well within UK environmental tolerances and regulatory requirements. Using the technology on the Orlando development well enabled a reduction in drilling waste handling and reduced downtime, due to the elimination of wait on weather, reducing rig non-productive time by allowing continuous drilling during adverse weather conditions. It also reduced handling, storage, offshore lifting and skip to shore vessel requirements, for the 17 ½" and 12 ½" sections, saving an estimated $640,000 in vessel costs alone (based on the market rates at that time).

Thorough planning meant initial challenges relating to delivery of equipment was quickly mitigated and support from TWMA, in close co-operation with AGR and the operator, helped to reduce the operational time-table and costs.

The drilling waste management operation was completed within time and on budget with zero Lost Time Incidents and zero loss of containment to the environment during operations.
Integrating Surface and Subsurface Models in an Automated Workflow Process for Asset Performance Analysis in Burgan Digital Oilfield –SEK
Authors: Rane Nitin , Al-Shammari Baraa , Desai Sameer , Al Sabea Salem , Pandey Mukul , Ibrahim Assem Mohammed , Chacko Rebin
Published: November 2018

Oil and gas companies face major challenges for meeting increased energy demands around the world. There is a sharp decline in production from existing fields and at the same time, discovery of large new fields has become increasingly difficult. As a result, oil and gas operators around the world are implementing various strategies to find ways of increasing recovery from existing reservoirs

With ultimate average recovery factor for oilfields on a worldwide basis of about 35%, companies are trying to improve recoveries through new technology initiatives such as integrated digital oil field approaches, which integrate reservoir and production system together for continuous monitoring of asset performance and production; optimization, and control of wells and fields.

Comprehensive workflows and collaboration environments are key elements of any successful digital oil field operation. They integrate a multitude of data sources and applications, capture the knowledge of production processes, and enable improved decisions. These workflows help overcome the complexity of today’s asset management operations.

Kuwait Oil Company implemented such initiatives in one of its assets in Burgan oilfield which involved instrumentation at well site, a SCADA system for data acquisition and control, integrated asset management workflows together with state-of the art collaboration center enabling faster diagnostics for well and facility performance. The integration of surface and subsurface models in an automated workflow process allows quick review of well health and assists in planning for short- and long-term production optimization actions.
Smart Hybrid Technology for Water Injector Wells: Installation, Commissioning and Data Interpretation Challenges - Case Study from a Middle Eastern Field
Authors: Rachapudi Ramarao Venata , Alshehhi Shamma , Saadwai Omar , Ayidinoglu Gokhan , Dodan Cornel , Khaled Moutaz Faysal , Quintero Fernando , Mubarak Saber , Gali Appala Raju , Mohammed Samy , Ikogho Brume
Published: November 2018

Effective reservoir management is critical to the success of water flood developments. Continuous monitoring of downhole parameters such as pressure, temperature and flow profile in water injector wells is vital in order to optimize the water-flood sweep efficiency and to avoid early water breakthrough in nearby oil producer wells. The target field has three stacked tight carbonate reservoirs with low reservoir energy and as such is being developed with water injection scheme from day one. As such, effective monitoring of downhole injection parameters is important from an early stage.

A common industry practice to monitor these parameters is to install Permanent Downhole Gauge (PDHG) and Distributed Temperature Sensing (DTS) system. Recently, a new smart Hybrid Technology has been developed to measure the downhole data at surface. This paper describes the successful application of this hybrid technology in a green onshore oil field development. Details are presented about the well bore segmentation design of the DTS system, the hybrid cable installation and the operational challenges with the hookup to the wellhead control system. The paper also presents the data acquired during commissioning job, and interpretation of the temperature data which was used to generate the injection profile along the wellbore. Finally, a strategy for future implementation of the DTS system is discussed.

Overall, this technology showcases the application of the smart hybrid completion for real-time monitoring of the water injection profile, including the pressure and rates along with injection volume per segment in the horizontal section. Real-time data from the hybrid technology has been integrated to digital oil field implementation to enhance the real time decision making to optimize the injection rates and to allow the operator to implement the decisions without any delay. This technology optimized the cables requirement and maximized the utilization of cable for multi-application environment to support acquiring Pressure, DTS and DAS data to generate real time injection profile.
Improving the Accuracy of Virtual Flow Metering and Back-Allocation through Machine Learning
Authors: Shoeibi Omrani Pejman , Dobrovolschi Iulian , Belfroid Stefan , Kronberger Peter , Munoz Esteban
Published: November 2018

In this study we have investigated a fully data-driven approach (artificial neural networks) for real-time back-allocation and virtual flow metering in oil and gas production wells. The main goal of this study is to develop computationally efficient data-driven models to determine the multiphase production rates of individual phases (gas and liquid) in wells using existing measured data in fields. The developed approach was tested on simulated and field data from several gas wells. Two different type of artificial neural networks (ANNs) were tested on simulated and field data to assess the accuracy of estimations for steady-state, transients and dynamics in productions due to cyclic operation (shut-ins and restart). The results showed that ANN was capable of accurately estimate the multiphase flow rates in both simulated and field data. The accuracy of the production rates estimation depends on the type of neural networks employed, production behavior (steady-state or transients) and uncertainties in data.
Artificial Intelligence in HSE
Authors: Hojageldiyev Dayanch
Published: November 2018

Artificial Intelligence (AI) is a relatively new concept for oil and gas industry. Yet, its agile nature and massive potential give a promise for constantly evolving oil and gas business in tackling such issues as environmental protection. AI systems utilize a variety of technologies making it possible to produce comprehensive, nonetheless easy-to-use tools, which can be used by Health, Safety and Environment (HSE) professionals in their daily activities. This paper examines a so-called HSE AI Assistant - another tool aimed to provide support to HSE professionals in getting instant answers to questions on a variety of regulatory topics in occupational health, safety, and environmental protection. This AI tool will utilize latest NLP technologies to retrieve data from a bank of up-to-date HSE regulations and standards, and provide answers to required questions. The tool is a much more efficient alternative to traditional search engines and closed intranet data retrievals, as the AI system has an ability to understand human questions, hunt for applicable data in attribute files, and produce the most relevant answer to the questions. The system utilizes latest machine learning technologies, and has a capability of constant learning and evolvement. This will be especially useful in terms of changing local legislation and updates to the HSE regulations. The HSE AI Assistant can also be supplied with a capability to assist HSE specialists in classification of hazardous materials and help to perform regular HSE audits in the areas where hazardous materials are used and disposed. Developed locally in Turkmenistan by a team of HSE and IT professionals, the HSE AI Assistant can become a very accessible and easy to maintain reference and solution tool for HSE specialists working on COSHH audits and environmental impact assessment. The HSE AI can also assist those who control the chemical stock in the warehouse, and who manage the hazardous waste at the disposal sites.
Application of Uncertainty Analysis in the Design of Subsea Natural Gas Dehydration Units
Authors: Kruger Francois J. , Kontogeorgis Georgios M. , von Solms Nicolas
Published: November 2018

Advances in subsea processing present the opportunity for high pressure natural gas dehydration and product export directly from the seabed. In this work we evaluate dehydration using monoethylene glycol (MEG) as an absorbent. A combination of parameter uncertainty and process input sensitivity analysis is used to evaluate the feasibility of 18 different scenarios. For a representative light and heavy natural gas, a 3×3 experimental matrix for processing pressure (60, 90 and 120 bar) and lean MEG quality (90, 95 and 98 wt%) was used. 5000 Monte Carlo simulations were performed for each case with the output mean and confidence intervals being calculated.

In terms of dehydration performance, the feed gas composition has only a minor effect in the order of 2.5%. The process is shown to be infeasible when using lean MEG with a quality of 90 wt%, while the lean MEG flow rate can be adjusted to meet product specification of 32 ppm H2O if higher quality lean MEG is used. The required flow rates ranged between 16 and 254 m3/h. The minimum required lean MEG quality is estimated as 95, 93 and 92 wt% at 60, 90 and 120 bar processing pressure respectively. From the upper bound of the 99% confidence interval, it is estimated that the minimum safety factor of 5-9 ppm is required (depending on the quality of lean MEG used).

Secondary performance measures were also evaluated. MEG content in the product gas varied most strongly with gas composition (especially at high pressure), where differences of up 150% are seen for the light and heavy gas. Product recovery was between 97.5 and 99% for the feasible cases with the best recover found at high pressure and lean MEG quality, while recovery of light gas was slightly improved compared to heavy gas.
Fibre Optic Surveillance for Conformance Monitoring in a Polymer Pilot by Petroleum Development Oman
Authors: Rawahi Zainab , Hemink Gijs , Freeman Floris , Groen Alex
Published: November 2018

Petroleum Development Oman (PDO) has been utilizing several Enhanced Oil Recovery (EOR) methods in the Sultanate of Oman to accelerate (polymer/steam floods) and increase (Alkaline Surfactant Polymer, or ASP, floods) recovery from fields with challenging rock and fluid properties. Polymer-flood is a mature EOR technique, and has been trialled and implemented successfully on full-field scale in a sandstone reservoir of excellent quality in the South of Oman.

As part of this continuing effort, a currently ongoing polymer pilot focuses on testing the ability to sustain polymer injectivity and to prove the polymer efficiency in a significantly lower permeability sandstone reservoir. This lower permeability reservoir introduces injectivity and conformance concerns. Continuous surveillance to monitor and assess changes in areal sweep, vertical conformance and fracture initiation play therefore a pivotal role in delivering on the success criteria of the pilot. The pilot was designed with this surveillance scope in mind. Producers are equipped with either a dual well-head or a permanent down-hole gauge, and well-testing is conducted with a dedicated [mobile] test-unit. In the injector wells verifying vertical conformance and matrix injection is critical but conventional surveillance (Production Logging) is unreliable as the spinner is affected by the non-Newtonian behaviour of the polymer solution. The two pilot injectors were therefore equipped with a fibre optic (FO) cable, clamped and cemented on the out-side of the 7″ casing, enabling continuous monitoring of the injection profile and thus injection conformance through temperature (Distributed Temperature Sensing, DTS) and acoustic (Distributed Acoustic Sensing, DAS) measurements.

The focus of this paper is to explain the decisions taken based on the information obtained from the FO data during the pilot period. The data was used for several key decisions; to select which pilot injector to use for polymer injection and which to keep as a back-up by assessing Out-of-Zone Injection, matrix versus fracture injection, and to prove conformance and injectivity improvement after acid stimulation jobs. The most valuable information inferred from the FO data allowed confirmation of the improvement in injection conformance by the polymer-flood over the water-flood. Fibre optic surveillance thereby has truly proven its surveillance value, for this polymer pilot, and any potential up-scaling of the project.
Efficiency, Economics and Compliance: A Practical Planning Tool for Optimizing Cuttings Treatment
Authors: Chauvin Earl
Published: November 2018

The expanding focus on total cost of ownership (TCO) in the oilfield is driving the application of global best practices in drilling and completion operations. Measurable benefits can result from a proactive approach to separating, treating, and handling disposal streams that accounts for both short- and long-term effects and is tailored to the specific needs of projects in the Middle East. This paper provides a versatile decision-making tool to help determine the optimal processes for a variety of conditions based on efficiency, economics, and sustainability.

The most effective treatment solutions and services seek to address multiple factors, including logistics and expenses, drilling efficiency and performance, remote locations with infrastructure limitations, and strict environmental regulations. Interdependencies between the fluids, equipment, and services will also influence the selection of appropriate separation and treatment processes.

A useful decision tree is based on the critical goals of waste volume reduction and maximum recovery of valuable components. Making the right choices in both of these areas will provide effective long-term results and economic benefits.

This paper summarizes multiple case histories that demonstrate successful cuttings and waste stream processing, including both land and offshore operations. In some cases, a mobile or well-specific treatment system works best; others rely on a central treatment facility to serve an entire field or multirig operation. The results achieved in each case contribute to a step-by-step planning tool in matrix format that can be used to design the best set of equipment and services for each location.

The matrix accounts for many factors, including rig equipment and capacities, proposed drilling and completion fluids, lithology, risk assessment, system maintenance, potential process rates and throughput, mobilization, environmental regulations, and infrastructure requirements.

The decision tree presented facilitates the treatment selection process by incorporating useful benchmarks for volumes, process rates, expected base oil/fluid recovery, installation costs/requirements, scalability, longevity, and decommissioning (and/or relocation of the treatment system). It provides a practical starting point for planning an efficient, fit-for-purpose treatment configuration, scaled to match operational needs, reduce total cost of ownership, and meet or exceed existing and future standards.
First Successful Chemical Application Water Shut Off Job in Dual Completed Well Short Tubing and Oriented Perforations to Enhance Well Productivity in Burgan South Kuwait
Authors: AL-Rashidi Alyah , Jain Manish , Tirkey Naween , AL-Ammar Heyam , Al-Ajmi Salem , Weiss Adrian
Published: November 2018

Greater Burgan Field has been producing from more than 70 years and brings many challenges with the maturing field. During the last decade almost all the new wells drilled were completed as dual completions to simultaneously produce from two different formations in Burgan. As the workover rig activity tremendously increased with the increased number of new wells per year, it has been a constant endeavor to carry out maximum well intervention jobs possibly by rig less operations to reduce rig related OPEX and well production down time during rig work over.

One of the biggest long term challenges was to carry out well interventions in dual completions short tubing, which was used to be considered inaccessible due to presence of tubing long in the well bore. In view of above, most of the intended well interventions in tubing short were normally used to be proclaimed as work over candidate thereby increasing load on limited work over rigs.

First time in Burgan a dual completion well was carefully identified to carry out water shut off job by chemical application and adding perforation by oriented perforation gun in short tubing. The tubing short was producing from BGSU reservoir and became ceased to flow due to lateral water encroachment which was evident from the recent PNC log. The formation layer below BGSM was still having oil potential and was intended to produce after shutting off the upper layer BGSU. The Tubing Long was producing from deeper reservoir BGSL around 1200 BLPD with 50% W/C.

This paper elaborates the procedures adopted during the execution of the job and selection process of the chemical squeeze technology. The best suitable chemical technology was selected after carrying out a careful & detailed approach towards different vendors. The step by step detailed program was prepared to squeeze the chemical in to existing perforations, cleaning to the desired depth, testing the squeezed perforations and adding new perforations below with oriented perforations gun.

The results were quite encouraging with sustainable oil gain of 1400 BOPD and the detailed cost/pay back analysis indicated the payback period of only 1.5 days of production.

This successful job has opened a new era in the history of Burgan field and many other water shut off jobs may be successfully carried out without the need of rig work over. This not only will reduce the work load on rig work overs and save rig cost significantly but will also allow to increase the well productivity with a very short period of well down time.
Efficient Pulse Neutron Logging for Uncertain Water Salinity in Carbonate Reservoirs: A Case Study from Offshore Abu Dhabi
Authors: Amer Mohamed Mostafa , Serry Amr Mohamed , Afzal Nusrat Afrin , Al Zaabi Fatema , Al Jaberi Salem , Zhou Jiheng , Ismail Mostafa , Nada Al Sayed
Published: November 2018

Pulsed neutron logging is currently the most commonly used technology for cased hole formation saturation analysis, providing data for reservoir monitoring and management. The common pulsed neutron log measurement is the formation capture cross section (Sigma). The data can be logged at a relatively fast logging speed. Water saturation analysis using the Sigma log requires high porosity and known formation water salinity. Errors in the Sigma log interpretation can result from the uncertainties of water salinity values, which usually change, for example, due to mixing of the hypersaline formation brine with the low-salinity injected seawater. Heterogeneity and changes in the carbonate petrophysical properties also play a role in magnifying the magnitude of water salinity changes. Carbon/ oxygen ratio logging (C/O) is salinity-independent and can be applied to overcome the problem, but the physics of the measurement usually require multiple passes with lower logging speeds than Sigma logging. This paper introduces a novel pulsed neutron logging methodology to help overcome the mixed-water salinity problem and produce a reliable water saturation interpretation for updating fluid front maps.

First, the pulsed neutron tool was operated in Sigma mode to cover the full target reservoir interval in a single pass. The tool was then switched to the C/O mode with multiple passes for 50ft only at the top of the target reservoir. Monte Carlo modelling was applied to the C/O data to calculate the water saturation. The C/O result was then used with the Sigma log data to inversely calculate the Sigma water using a Sigma-based material balance equation across the same interval. The final water saturation across the full interval was estimated by using the calculated water salinity and the Sigma data.

Through the application of the proposed methodology, we successfully measure the target formation saturation information in an acceptable operating time, when compared to conducting the conventional C/O logging across the full interval. The results show that the estimated formation water salinity is close to that value of drilling mud filtrate; the water saturation is slightly lower than that from the openhole resistivity interpretation.

This paper introduces how to optimize a pulsed neutron logging program that combines the C/O and Sigma measurements to enhance the offshore operations efficiency, minimize the water saturation interpretation uncertainties, and support future field development planning.
SCCO2 Flushing Technology: The Supercritical Revolution
Authors: Amundsen Espen , Juul Mikkel
Published: November 2018

Objectives

Research indicate that 80% of all failures in fluid transfer systems are caused by contamination.

Contamination causes huge gaps in both safety and reliability and shortening the lifespan of, systems. Subsea systems are often controlled by very long umbilical's/control-lines (>6 km) with no efficient cleaning option. It is necessary to clean these lines with turbulent flow, which can be difficult to obtain with conventional cleaning fluids

Method

With the Super Critical CO2 (SCCO2) technology, it is now possible to clean very long narrow pipes with turbulent flow, not possible with conventional flushing methods. Due to the very low viscosity, diffusivity, and no surface tension of the CO2, it possible to reach a level of cleanness never seen before. Using the pressure & temperature it is possible to manipulate the density needed to carry the particles. When the particles are carried out of the system, the liquid CO2 is converted into gas in the separator, and the contamination suspended in the CO2 drops out.

Results

This technology has been proven on a proof of concept test (onshore) with two 3rd party participance, flushing a 6,5km ¼" dual control-line. This line was cleaned with laminar flow (Reynolds No. under 3000) and had a certificate that said it was cleaned to NAS1638 grade 6. It was proved, using SCCO2 with a Reynolds No. of 42.000, that the line was not clean, [and was NAS1638 grade 12]. It was then cleaned to NAS1638 grade 3, best we have ever seen. Also, the SCCO2 technology was proved offshore, by cleaning a 38km ½"ID Umbilical for Wintershall Noordzee, from NAS1638 grade 12 to Grade 3 with a Reynolds No. of over 30.000. This umbilical had the same issue as in the proof of concept test. The line was claimed to be clean, but the operator experienced that the chemical injection line was blocked by contamination. This caused a lot of shutdowns and was very costly. After the umbilical was cleaned with the SCCO2 technology, the operator has not had any shutdowns due to contamination or blockages for over 9 months now.

Novelty

With the SCCO2 technology, it is possible to clean or unblock very long tubes/lines, to a cleanness never seen before. The cleanliness and unblocking possibilities are a result of the unique characteristics of the CO2, and the high Reynolds No. possible by using CO2. This opens more possibilities that previously was not possible and lacking in the industry. It will make the systems more safe, reliable and reduce cost and increase the production up-time.
First Successful Replacement of Fully Retrievable ESP by Slickline
Authors: Spagnolo Salvatore , Incollà Francesco , Guglielmo Carmelo
Published: November 2018

Eni installed the world's first offshore Rigless Fully Retrievable Electrical Submersible Pump (RFR-ESP) system in an Eni Congo field in April 2012. The ESP failed after four years, and the system was successfully replaced rigless, by means of a slickline unit and a pumping unit.

The job included the complete path from design and operations definition to the ESP commissioning and follow-up.

Replacement operations were split in three different phases: Pull Out Of Hole (POOH): retrieval of the system and verification of the failed item(s).Run In Hole preparation: order, shipment, test and preparation of the items to be run in hole.Run In Hole (RIH): system deployment, commissioning and follow-up.

The separation in time of the three phases was mainly due to the logistic arrangements required for the shipment of the various items to be replaced.

Major attention was given to HSEQ aspects in every phase.

The job resulted in the complete rigless replacement of the retrievable part of the ESP system, which allowed remarkable cost savings, compared to a rig intervention for the same scope of work, in terms of both direct costs and gains for avoiding well downtime and production delay.

Better results and further contractions of times and costs could have been achieved by improving the management of operations and logistics. However, being this the first job of this kind worldwide, it was challenging in that no model or benchmark was available at that time.

Some lessons learnt from the POOH phase were directly applied during the RIH phase, while others were reported in order to be implemented in future similar jobs. Since the economic impact of this type of job is remarkable, the sharing of knowledge is key to enhance performance of analogous applications, in a safe and efficient manner.

This paper describes the job performed, explaining the choices made, the criticalities encountered, as well as the lessons learnt and the benefits achieved.