bluuebunny/crossref_metadata_2025 huggingface dataset:
Innovation of Sand Management and Conformance Control Design in a Steam Flood in the South of the Sultanate of Oman
Authors: Shizawi Wafa , Zadjali Ruqaya , Riyami Mohammed , Bellmann Lars , Yahya'Ei Haitham
Published: November 2018

A thermal steam project has been successfully implemented in a Petroleum Development Oman (PDO) field in the South of Oman. The steam flood developed the crest of the field and incremental oil recovery from formation A has been obtained. Based on this success expansion of the steam flood in the field is planned. The southern extension will encounter the same formation A as developed at the crest. The northern extension, however, will contain two new formations (B and C).

For these two new formations limited field data on sand production is available, and a sand prediction evaluation for both cold & thermal production conditions is required. Additional to that, the field development strategy requires that the oil producers will be re-completed after steam breakthrough and a flexible placement of the pump above/below the perforations at different phases of the steam flood. Successful implementation of conformance control in wells with sand control has a significant impact on the oil recovery and thus economics of the project.

This paper focuses on formation B. The assessment of the likelihood of sand production and the requirement of sand control was based on a combination of a) actual field data such as sand production, well performance & completion data; and b) a sand production model for the different production conditions (hot and cold) utilizing rock-mechanical data. The sand evaluation study demonstrated that there is a risk of catastrophic sand failure under both cold and hot operation conditions and thus a completion with thermally compliant sand control and conformance control is required for this formation.

Core sieve analysis data were used to determine the Particle Size Distribution (PSD), which was used to select the sand control type and screen slot width. A standalone wire wrap screen has been selected for sand control in formation B.

A completion that combines a standalone wire wrap screen, with the provision of conformance control by isolating perforation intervals, with placement of a 4.5" tubing pump below the (isolated) sand screen is challenging to design. Multiple completion types have been evaluated and a new type of technology for PDO of sand control with an isolation sleeve is proposed to meet the requirements of the field development plan. It is expected that this new design with flexible recompletion of the sand control system will have a large impact on the oil recovery.
Rig Time Optimization During Workover by Predefined Well Integrity Criteria Using MAASP Sensitivity Analysis
Authors: Yugay Andrey , Yousfi Fawad Zain , Jaiyeola Abiodun Isiaka
Published: November 2018

During normal rig workover operations, once the old completion is retrieved, corrosion log is being executed to check the condition of the casing and/or liner as one of the means to establish a way forward. Decision can be made easily in case of pipe found completely corroded or absolutely intact. However, such clear scenarios are not always the case and the decision making takes significant time, specially if corrosion log results are received at night time or during the week end. It may become a subject of hot discussion between involved stakeholders, trying to find a right balance between safety and operations. Therefore Gas Development Operations Subsurface Team of ADNOC Onshore requested Technical Center Well Integrity Team to identify clear criteria in advance, to save rig time and improve business performance and decision making process. Based on this request Technical Center developed a strategy of predefined well integrity criteria's that are being successfully used now, saving rig time during workover and avoiding conflicts between teams in questionable situations.

The method is based on several factors: Maximum Allowable Annulus Surface Pressure (MAASP) calculation as per Norsok D10 standard, application of Double Barrier concept for Secondary Well Barrier Envelope, sensitivity analysis based on MAASP degradation and remained wall thickness of casing and/or liner. This method has already been successfully implemented in several wells during workover operations saving time for decision making. It is planned to be included in the next release of corporate procedures.

Method, explained in this paper can be used as a guideline by all petroleum engineers, drilling engineers, well integrity engineers and petrophysicists who are involved in workover operations, helping them to improve decision making process based on the results of the casing corrosion logs. In addition, the subject of well life prediction and well life extension in standard Company well design is covered, with focus on safety during workover operations.
Ice Plug as a Well Barrier: The Story of Success
Authors: Yugay Andrey , Albadi Mohamed Mubarak , Agarwal Anubhav , Nadder Mohsen Ali , Gadelhak Abdelrahman Mohamed , Masoner Mark
Published: November 2018

The actual case described here is about successful implementation of the freezing plug technology utilized as a well mechanical barrier for the first time in the company's history. The use of the ice plug resolved a complicated integrity issue and the high H2S gas producer well was brought back on to production.

Reduced space for the ice plug placement made this case unique. Despite the challenging conditions of limited accessibility, injectivity, and zero asset experience with this application, the job was performed successfully.

One of the challenges was a corroded surface casing, which is a common problem in Gulf onshore fields. The casing was previously repaired by welding a mechanical sleeve around the corroded area, which limited the plug length. Several additional problems occurred inside the Christmas tree. The wireline retrievable Surface Controlled Subsurface Safety Valve (SCSSSV) became dislocated out of the landing nipple profile and hit the Swab Valve. The Swab Valve was damaged and became stuck in the closed position, and was not holding pressure. The SCSSSV became stuck across the Lower Master Valve (LMV) and the Upper Master Valve (UMV), and left the well with no operable barriers. Well killing operations using high viscous pills ended up with lost injectivity. Different scenarios of curing this problem have been analyzed involving multi-disciplinary teams and contractors.

During further well service operations and the ice plug installation more challenges were encountered; however, all challenges were handled safely. The ice plug, once installed and tested, provided a mechanical barrier that allowed the team to perform the required services and to reactivate the well riglessly, and avoid drilling a relief well. The case was presented internally and the process was initiated to improve availability of this technology on a regular basis due to growing demand in the field.

The lessons learned during the execution of this job and the methods used will be interesting for all companies who operate naturally flowing wells, helping in curing well integrity issues in a safe and cost efficient way.
Sulphate Reducing Bacteria SRB Control and Risk Based SRB Severity Ranking
Authors: Emmanuel J. I. , Shaapere T. T.
Published: November 2018

The annual cost of steel corrosion is estimated to be $2,500 billon across the globe (Small).

Sulphate Reducing Bacteria (SRB) is one of the most implicated Bacteria in internal corrosion failures worldwide. Currently the method for controlling Sulphate Reducing Bacteria (SRB) by the International Oil and Gas Companies (IOCs) to mitigate the risk of Microbiological Induced Corrosion (MIC) on their wet treated or untreated crude oil transmission pipelines or tanks is by either batch treatment or slug treatment by injecting biocide between two pigs or direct injection through quill in the absence of online facilities for launching multiple pigs simultaneously.

The international best practise for the control of SRB is to kill the bacteria in-situ and prevent the contamination of downstream equipment and piping. To increase killing effectiveness and prevent resistant strains of SRB from been developed, biocides are alternated based on planned treatment frequency determine by the corrosion engineer or corrosion consultant that developed the programme. Time to kill test is conducted in the field to determine the concentration and time to kill the planktonic bacteria, however, determining the time to kill for sessile SRB is often difficult to achieve except slug between two pigs is utilised to create maximum contact with SRB in-situ.

Other parameters to be considered when developing a biocide treatment program are the historical data of the pipeline, the mixed flow velocity, Gas Oil Ratio (GOR), Water Cut (Base Sediment) and Water (BS&W), Pipeline topography, pipeline significance factor, maximum pitting rate, maximum uniform corrosion rate and historical leak history.

The method of assessing the risk due to SRB for static equipment (tanks or pipelines) varies from company to company and there is no universally acceptable standard on what to consider as bench mark for best and effective treatment. In addition, the kind of SRB (Sessile or Planktonic) to be monitored in-situ has also been debated by industry stake holders and corrosion practitioners. Whilst some operators monitor only planktonic in water phase, others monitor sessile growth via installed bio-probes and planktonic from oil field water sample microbiological analysis.

This paper present current practise, identify the gaps in the practise and propose risk based approach to SRB characterization to enhance biocide treatment effectiveness and monitoring. It is the intention of the authors to spur a debate that will lead to the development of best practise in biocide treatment strategy by the International Oil and Gas Companies (IOCs). The authors are of the opinion that improving treatment strategy with SRB characterization using risk based approach will result in efficiency of treatment in addition to substantial cost optimisation to the tune of 20% OPEX and 25% CAPEX.
Development and Field Trial of the World's 1st Cloud Connected Wireless Intelligent Completion System
Authors: Green Annabel , Lynch Paul , Bugten Bjarne
Published: November 2018

This paper describes the development and field trials of a wireless intelligent completion system that enables long term monitoring and interval control to enhance production management within new or existing wellbores by connecting the user wirelessly from the desktop to the downhole component of the system, inflow control valves (ICVs).

The effectiveness of intelligent completions for production optimisation and improving reservoir management is well established, yet the use of this technology remains limited to high value, single bore wells. The cost and complexity of these solutions coupled with limitations in well types, interval quantity and poor system interfaces are all factors which have prevented broader application.

An intelligent completion that communicates wirelessly within the wellbore provides dual benefits in completion operations and production management. Eliminating the requirement for control lines addresses many of the limitations of traditional systems, and the all-electric technology provides greater scope for digital well management and integration with surface systems.

A slimline inflow control valve (ICV) has been developed which provides infinitely variable choking capability and multiple integrated sensors. Qualification has been completed to Statoil's/Equinor's existing standard for the qualification of interval control valves adapted and augmented to reflect the differences between the wireless solution and conventional technology.

Several field installations have been performed with the system, two of which are detailed within this paper to demonstrate the performance of the technology. In the first, operations were performed with local only access to surface data which demonstrated the ability to communicate effectively but highlighted some mechanical limitations in the tool itself. Following implementation of design improvements, a second installation was performed which also included a surface management system with wireless interpretation software and cloud connectivity.

The system has been proven to provide robust communication using pressure pulses within the flowing well stream to provide operating instructions to the ICV, and for the ICV to operate as instructed and communicate effectively to the wellhead. Data from the system has been digitally managed and remotely accessed demonstrating the ability to change tool settings remotely.

Integrating a semi-duplex pressure pulse system which operates in compressive fluid environments to provide direct communication between a downhole device and wellhead provides a low energy communication method compatible with extended service life completion tools. The system has been demonstrated with ICV technology in both multiphase and gas environments. In field trial this has been integrated with an intelligent system effectively deploying the world's 1st cloud connected wireless intelligent completion.
An Innovative Workflow for the Petrophysical Characterization of Tight Gas Reservoirs in Argentina
Authors: Zambrano Rafael , Parra Daniel , Lamberghini Lucia , Saldungaray Pablo , Mosse Laurent
Published: November 2018

The formation evaluation of low-porosity tight gas reservoirs in Argentina presents several well-known challenges in the estimation of main petrophysical properties as porosity, clay fraction, permeability, and water saturation. The main goal is to accurately quantify these petrophysical properties with a consistent and reliable petrophysical model. The next task is to reveal the key petrophysical responses that represent the link between petrophysics and production.

The present work describes the main petrophysical challenges faced and an innovative workflow used in the Lindero Atravesado field with clear examples to illustrate the effectiveness of this approach. The workflow involves measurements such as advanced elemental gamma ray spectroscopy, multifrequency dielectric dispersion, and nuclear magnetic resonance (NMR). The advanced elemental gamma ray spectroscopy has been key for the creation of a robust mineralogical model, and to derive the matrix properties used to obtain an accurate porosity free of matrix and gas effects with the combination of NMR porosity. The dielectric dispersion provides a direct estimation of water volume, which, in turn, helps to adjust the conventional method of water saturation from resistivity. The good correlation between the petrophysical properties estimated from the proposed workflow and the core analysis, demonstrates the benefits of using the advanced log measurements. The final step of the workflow consists in the definition of poro-fluid facies determined with a new methodology, called NMR factor analysis, that is based on the extraction of multimodal information from the NMR T2 distribution to determine the optimal number of dominant modes (factors) that allow describing the reservoir. Production logging results showed a good relationship between the poro-fluid facies and reservoir productivity.
Influence of EOR Polymers on Fouling in Production Wells and Facilities
Authors: Mittal Saumya , Anand Saurabh , Venkat Panneer Selvam , Mathur Vinay , Zagitov Robert , Subramanian Jaisankar , Patel Nilay , Hammonds Paul
Published: November 2018

Cairn Oil & Gas, Vedanta Limited has implemented full field Polymer Flooding in Mangala Field and is currently injecting nearly 400,000 bpd of polymerized injection water with average polymer concentration of ~2500 ppm. Partially hydrolysed polyacrylamide (HPAM) Polymer is mixed with source water to create a mother solution of 15,000 ppm concentration at Central Polymer Facility (CPF) and is distributed through a pipeline network to 15 well pads where it is diluted to achieve a viscosity of ~30 cP for injection.

Artificial lift in Mangala is either by Jet Pump or Electrical Submersible Pump (ESP). In producers, a wide range of polymer concentrations are observed in the produced brine. Maximum polymer concentration measured is ~972 ppm and average polymer concentration is ~280 ppm.

Recently, during well intervention activities, it is frequently observed that polymer like waxy deposits are obstructing the free movement of wire-line tools. During jet-pump redressing, polymer deposition was observed in the Body X-over (Reservoir liquid path), check valve assembly, throat and spacer nozzle to throat inside jet-pump. In addition, an agglomerated polymer substance was also observed in the slick line tool string. A general observation is that after a jet pump change, production rate increases sharply followed by rapid decline. This requires Jet Pump Change Out (JPCO) job at regular intervals (every 20 days in few wells). Furthermore, semi soft to hard polymer deposits have been observed in surface facilities i.e. injection water booster pumps, injection water filters and heat exchangers.

Laboratory analysis of the samples collected indicated that the deposit consists of Hydrocarbon, Inorganic Scales and polymer agglomeration. Based on further studies it is observed that the degree of hydrolysis of the polymer deposit significantly increases between 50-80% in Jet pump deposits and up to 90% in heat exchanger samples. Increasing degree of hydrolysis reduces the polymer cloud point below reservoir temperature and heat exchange skin temperature.

Solution to the problem can be identified by controlling the degree of hydrolysis in fresh polymer below 25 mol% and cloud point greater than 120°C, addition of scale inhibitor to the system upstream of scale formation, removal of deposit with a combination of oxidizer and chelant; other options continue to be studied.
Machine Learning Provides Higher-Quality Insights into Facies Heterogeneities over Complex Carbonate Reservoirs in a Recently Developed Abu Dhabi Oilfield, Middle East
Authors: de Ribet Bruno , Jun Jaeho , Kim Yulee , Trowbridge Thomas , Shin Kook S.
Published: November 2018

Objectives/Scope

Because of the complexity of properties and heterogeneities, the challenge in a carbonate reservoir is to predict the spatial distribution of the best reservoir facies. Due to the sparse distribution of wells, uncertainties exist, especially where fewer cored wells are available. The aim of this study was to employ machine learning, using the full dimensionality of 3D seismic data and well data, to predict lithofacies heterogeneities distribution in major reservoirs of the Thamama Group, for a recently developed large UAE onshore field.

Methods, Procedures, Process

This technology generates a probabilistic seismic facies model derived from the 3D seismic data. An association of naive neural networks, each with a different learning strategy, is run simultaneously, to avoid biasing any of the neural network architectures. To train the neural networks, seismic data and the lithofacies at the well location extracted along the wellbore are used as labelled data. To avoid overfitting from a limited dataset, we introduce seismic data away from the borehole (soft data) so that the neural networks can "vote" on their integration to improve the final training dataset before reaching the ultimate learning stage.

Results, Observations, Conclusions

The application of this technique on Lower Cretaceous carbonate reservoirs shows promising results. The analysis of the probability distribution gives good insights into reservoir facies distribution uncertainty. Lithofacies are created from electrofacies by subdividing facies based on hydrocarbons. The resultant prediction was validated through comparison with observations from a new drilled well, adding confidence in the decision-making process when selecting future drilling locations. This method uncovers new potential for seismic data reliability when predicting the reservoir lithofacies away from wells, especially when referring to prestack data with any type of seismic attributes. Using this method, the major reservoir lithofacies can be precisely predicted within the field. As the probabilistic facies model is calibrated to wells, this lithofacies data can be used for both geologic modeling and volumetrics analysis.

Novel/Additive Information

Machine learning techniques were successfully applied to generate lithofacies from electrofacies from the 3D seismic data, leading to accelerated interpretation and reservoir characterization processes. In many cases, they provided faster images of the subsurface while still maintaining accuracy, thus helping to improve the decision-making process when determining new drilling locations.
Integrated Drilling Optimization Approach Delivers Excellent Results to Improve Drilling Efficiency in Remote Artificial Island
Authors: Paila Phalgun , Kirby Cliff , Diaz Nerwing , Aboulkheir Adham , Mahmoud Dalia , Al Kindi Rashid , Kasem Youssef , Benygzer Mhammed , Moreira Rodrigo , Cesetti Maurizio , Singh Rudra
Published: November 2018

Drilling & Completing of the wells faster, safer and at lower costs has always been the primary target for the operating companies worldwide. While it has been achieved by several means through Technology, Innovation, Operational Optimization, Cost Reduction Techniques, Application of Best Practices etc; the operating company still has to deal with multiple contractors, vendors, suppliers and service providers, with each of them having different drivers for success that may or may not align with the primary goal. The concept of Integrated Operations / Services brings in this required polarization of drivers for success to deliver the projects under budgeted AFE & planned times.

In one of such Integrated Drilling Operations Campaign, at an Artificial Island located in Offshore United Arab Emirates, with single focal point for various drilling well services, the learning curve of the project has been very steep with numerous optimization measures taken at the early phase of the project under the continuous improvement process to enhance the drilling efficiency in order to speed up the well delivery. The step change achieved in the drilling efficiency for delivering the 16″ section will be detailed in this paper. The same concept has been applied in other sections with similar success.

The drilling optimization has never been so thorough and need of the hour with the current prolonged challenging market conditions. This paper revisits the drilling optimization by integrating all the associated well drilling services to improve and pursue higher drilling efficiencies. It details in steps, starting with identifying the opportunities of improvement, how the traditional methods & practices were challenged and the revised practices were adopted in design & operational execution to better the performance and deliver the section faster consistently with every well.

The drilling performance of this section after integrated drilling optimization currently holds several records (best footage/day, best footage/24 hours, best onbottom ROP, best average ROP including connections, best connection times, days/1000 ft, faster casing running speeds) in the subject field and also stands out when compared to the other nearby offshore fields in the country. These drilling performance records are combined with good hole quality which have contributed to delivering the fastest 16″ section when one includes casing running and other flat time activities.

With the planned changes alongside the detailed engineering planning & constantly monitored execution, the section has been delivered well after well with improved times. Overall, the drilling phase of this section has been delivered 3 days earlier than the offset wells and contributing to potential savings of up to 18 million USD to the project drilling campaign cost.
Hydraulic Modeling Helps Designing Ultralow ECD Nonaqueous Fluids to Meet Narrow ECD Windows
Authors: Hui Zhou , Chesnee Davis , Jay Deville , Bill Shumway , Ryan Schiro , Tim Bailey , Rob Valenziano , David Carbajal
Published: November 2018

Hydraulic modeling was used to simulate the effect of fluid rheology (both high- and low-shear-rate rheology) on the equivalent circulating density (ECD) at critical points in the well. The modeling results provided a guide for the design of nonaqueous fluid properties necessary to achieve the required ultralow ECD values. Using a combination of a rheology modifier and a new low-end fluid rheology enhancer, ultralow ECD nonaqueous fluids were successfully developed to meet the fluid rheology and barire sag requirement. The low-end fluid rheology enhancer provided a desired gel structure that helps minimize barite sag, which is often the concern for low-rheology nonaqueous fluids.

The hydraulic modeling results showed that, although both high- and low-shear-rate fluid rheology must be very low to achieve ultralow ECD values, the reduction of high-shear-rate rheology has a larger effect on the reduction of ECD values. For a given ECD value, a fluid with a lower high-shear-rate rheology and higher low-shear-rate rheology is preferred because the higher low-shear-rate rheology is due to a much-desired gel structure that helps reduce barite sag during static aging. Hole cleaning is also expected to improve with higher low-shear-rate rheology.

Based on this information, a 14.0-lbm/gal clay-free nonaqueous drilling fluid was successfully formulated to achieve the required ECD without the use of micronized barite. As described, the fluid uses the combination of two rheology modifiers, one of which functions as a gel strength enhancer that provides the much-needed gel structure to minimize barite sag.
Lost-Circulation Control Material Yields Successful Cementing Operation and Achieves Good Zonal Isolation in Middle East Region
Authors: HamidZada AhmedAgha , De Barros Adelson Jose , El Sayed Ashraf , Matar Wael , Bereikaa Hesham , Vaidyanathan Vignesh , Ruben Medina
Published: November 2018

While drilling an 8.5 in. open hole in the Umm Shaif field, an unexpected fault was encountered across formation ARAB-D2, increasing losses from 15.0 to 40.0 bbl/hr. Initial losses were managed using mud lost-circulation material (LCM) pills; however, losses were observed again while running the liner. It was decided to cement the liner to secure the shoe, with the expectation of being required to perform a remedial operation. The liner was cemented with all precautions to help prevent further loss.

By systematically introducing enhancements to the cementing and liner running practices and optimizing the fluid (cement/spacer) design using the latest technology fiber system in the spacer, it was possible to achieve the objective to control losses during the cementing operation. Additionally, securing the shoe and isolating the reservoir zone while preparing for a top-of-liner squeeze and liner perforation, if necessary, to squeeze cement in poorly isolated zones was achieved. Three-dimensional (3D) placement simulator software was used to model the flow rates and the equivalent circulating density (ECD) during the operation, and sensitivity runs were performed to observe worst-case scenarios at different loss rates to optimize volumes, rates, etc.

Once the spacer crossed the loss zone, lost-circulation additives (composed of a blend of various additives) began bridging across the zone, enabling the cement slurry to reach the top of liner, where it circulated excess cement. The tagged hard cement above the top-of-liner log exhibited good isolation to the reservoir formation, no remedial operations were necessary for the shoe and top of liner, and no perforations were necessary.

Spacer fluids are an environmentally acceptable blend of carefully selected materials, including coarse and tough LCM, fibers, and medium-sized, resilient angular materials. These fluid systems help mitigate losses when cementing across weak, unconsolidated, or fractured formations and carry materials with both high-pressure integrity and compressibility to help ensure tolerance to modifications in fracture size, caused by differential pressure fluctuations, without the materials being dislodged or allowing collapse. These materials are stable and insoluble in water. The spacer fluid system breaks the emulsion of oil-based drilling fluid, water wetting the casing pipe and the formation in preparation for cement bonding. Additionally, such materials resist intermingling of fluids at the interface in the fluid train.
Study on Flow Diversion Caused by Deformable Preformed Particle Gel
Authors: Zhou Kang , Hou Jian , Wu Dejun , Du Qingjun
Published: November 2018

Water channeling becomes severer after long time of water flooding especially in heterogeneous oil reservoirs. Field applications of deformable preformed particle gel (PPG) in China has proved that injection of PPG can lead to flow diversion, increase sweeping efficiency and thus increase oil recovery. However, it is unclear how PPG promotes flow diversion and its controlling influence factors. To address this problem, the paper carries out the microscopic simulation study.

The flow of deformable PPG is complex, involving particle deformation, migration, fluid flow and particle-fluid interaction. In the study, the discrete boundary idea of immersed boundary method is used to deal with particle deformation. The lattice boltzmann method (LBM) and immersed moving boundary method (IMB) are combined to simulate the fluid flow considering the existence of particles. The discrete element method (DEM) is used to simulate particle-particle and particle-wall contact. Combining these techniques, the paper studies how deformable PPG migrates in a two-channel model and promotes flow diversion. The effect of particle diameter and elastic modulus on flow diversion is also discussed.

The two-channel model simulation results show that the fractional flow increases and decreases alternately between the two channels. This is mainly because the flow resistance increases and forces more subsequent water turns to another channel due to the particle deformation and wall friction when the PPG migrates in one channel. The influencing factor discussions indicate that in a certain extent the flow diversion capacity of deformable PPG increases as the PPG diameter and elastic modulus increase. However, overlarge PPG diameter and elastic modulus may block the small channel. In this situation, the fractional flow of small channel decreases to 0 and the water channeling becomes much more severer. Therefore, the PPG diameter and elastic modulus should be properly selected in order to obtain flow diversion and reduce water channeling in field applications.

The paper focuses on how deformable PPG promotes flow diversion, which provides a microscopic interpretation on enhanced oil recovery mechanism of PPG in heterogeneous reservoirs. The influencing factor analyses also provide valuable references for future applications of deformable PPG in more oilfields.
Right Data, Right Place, Right Time: The Evolution of a Data Acquisition Strategy for a Tight Gas Development in the Sultanate of Oman
Authors: Dawson William , Spain David , Rashdi Khalil Al , Saadi Sawsan Al , Gangopadhyay Abhijit , McTeague Mike , Busafi Badar Al
Published: November 2018

BP is developing the Khazzan and Ghazeer fields of Block 61 in the Sultanate of Oman. The development includes three Cambro-Ordovician tight gas sand reservoirs which require hydraulic fracturing for commercial production rates. There are challenges with depth and high temperature for the open hole logging environment, with a restrictive inner diameter and residual proppant creating challenges for the cased hole logging environment. Additionally, there are cost challenges on all data acquisition including coring, downhole gauges, sampling, proppant tracers and many other forms of surveillance.

This paper outlines the evolution of the data acquisition strategy for the Khazzan and Ghazeer assets. The development plan at project sanction was 20 vertical and 272 horizontal wells. The data acquisition strategy led to the development of a data acquisition plan, and all stakeholders were engaged to ensure the right data was acquired in the right place at the right time. Cross functional behaviours and fiscal discipline were essential in this process. Inclusion of the service companies into the wider BP team was crucial to ensure appropriate technology was applied, learning from previous operations implemented and new technology options made available.

Through careful management of the data acquisition plan, all data in development wells prior to first gas were acquired within the allocated data acquisition budget despite drilling 20% more wells than originally planned for this period. Early improvement in subsurface understanding enabled an overall reduction in well count for the life of the project, extension of the original development into unpenetrated areas, adding significant value to the project.
Energy Harvesting for Downhole Applications in Open-hole Multilaterals
Authors: Arsalan Muhammad , J. Ahmad Talha , S. Saeed Abubaker
Published: November 2018

This paper addresses the need and challenges associated with the energy harvesting methods in the downhole multilateral openhole horizontal well environment. The need for downhole energy harvesting is discussed and the functional requirements are established. Different means of energy harvesting that are available in either or both flowing and shut-in conditions are presented and the possibility of using them in the downhole horizontal wells for long-term monitoring and control systems is evaluated.
A Success Story of an Integrated Excel Based Process Simulation Model
Authors: Muthukrishnan Murali , Al Matroushi Mohamed Salem
Published: November 2018

Process Simulation model has the capability to provide optimum solutions for achieving higher productivity and efficiency of the existing processing facilities. To achieve this, process simulation model is required to be updated with actual operating conditions and composition. This activity requires substantial time to obtain the operating conditions and updating the simulation model for every changes of plant operating conditions and composition. In order to enhance the process of updating the simulation model for analyzing and troubleshooting the current performance in a proactive manner, an Excel based tool is developed to integrate the simulation model with Historian data. This Excel based tool will automatically update the operating data and composition in the process simulation model for the selected date (Historicisn data) and transfer the results from process simulation model back to the excel for further analysis.

The name specified by ADNOC Gas Processing for this excel tool is "Plant Simulation Interface (PSI)" Model. Following key advantages can be realized by using the PSI model. Validation of the process simulation model (Aspen HYSYS) using current plant data to establish a base case.Carrying out Preliminary Adequacy check of the plant within short schedule for different processing capacities and composition.Increasing the efficiency of the plant by fine-tuning the operating conditions within the operating envelope.Perform case studies to study the impact before implementing in the processing unit.Faulty instruments can be easily identified.Extraction of the results - required parameters and properties are easier and faster.No process simulation experience / expert is required as this works in Excel based environment except for the development of base model.

PSI model is developed in one of the processing facility of ADNOC Gas processing. Similar model is being developed for all the processing facilities in ADNOC Gas Processing. It is possible to extend similar ideas and develop Integrated Excel based simulation models for any oil and gas processing unit to increase agility in decision making, improve reliability and reduce the operating cost.

This paper outlines the procedure to develop an integrated Excel tool by linking the high fidelity simulation models with the data historian tags (PI data), Laboratory Information management system (LIMS) and to automate the complex workflow and the advantages of using this model.
OCTG Corrosion Status Monitoring in Wells Completed with Challenging High Ni CRA Non-Magnetic OCTG in Gas Well Environment with Higher Temperature, Extreme Hydrogen Sulphide and Reservoir Conditions – A Case Study
Authors: Sparke Simon , Abu-Ramoun Husam , Singh Basant Kumar , Dawson Graeme
Published: November 2018

This paper identifies a field with challenging well operating conditions for OCTG Corrosion logging in gas well that include pressure, temperature, carbon dioxide (CO2), hydrogen sulphide (H2S) and well completed with high Ni corrosion resistant alloys (CRA).

This case study, describes how periodic well interventions to measure the wall thickness of various strings, required specialised technologies in gas well to the high chromium and nickel content in the tubing which reduces the magnetic properties of the string(s).

All well interventions require careful tool selection, planning and implementation, however when the conditions are extreme and present HSE related issues, the planning must reflect a greater level of detail and understanding.

Additionally, the logging and interpretation process required for high end CRA tubulars is more detailed and sophisticated and little public domain data is available to assist in the well programme implementation. The Operator required logging tools to be fitted with highly sensitive and fast responding sensors, housed in titanium casings and run in memory mode with a slickline conveyance.

In this case study two wells were logged with multibarrier corrosion logging tools combined with multi-finger calipers, to determine tubing and casing thickness status of three tubular barriers. The flow wetted areas were completed with high end chrome/nickel tubulars with potential challenges for data acquisition and subsequent analysis. However, pre-logging planning was supported and bench marked by yard testing where identical composition materials had been used.

On retrieval, the data package showed provided a composite set of data, throughout the well and log interpretation clearly identified the well status to be positive. This provides excellent support for the applied logging technology.

Pre-logging data searches within SPE and other locations for academic papers describing similar scenario could not be found and this paper is understood to be the one of first kind. These specialized principles and procedures likely to provide with much needed BASE CASE guideline for such future corrosion monitoring logging in similar field conditions.
GIS: The Global Risk Mapping Towards Digital
Authors: Gouviez Benoit , George Bina , Nizar Mouna
Published: November 2018

Abu Al Bukhoosh (ABK) is an oil and gas field located 180 kilometers away from the Abu Dhabi's coast and has been in operation since 1974. The complex was gradually developed over the past forty years, and has some aging platforms and facilities.

As a consequence the problems related to Asset Integrity is one of the most important with regards to Operations Risk Management. Repairs or intervention activities must have very specific and rigorous plans for addressing barriers to prevent uncontrollable loss of containment from the wellbore to the external environment. Hence continuous monitoring and integrity management of the field is mandatory for long-term profitability and HSE performance in an aging asset like ABK.

Asset Integrity is usually well covered during technical discussions and meetings, and is usually considered as a subject matter expert topic. However Asset Integrity and its associated technological risks are usually less discussed during general events involving the whole organization. This is more limited to operational safety KPI's, the protection of the environment and the prevention of accidents to people. These are easier topics to discuss and are more suited to the corporate communication materials.
Northern Sea Route as the Main Driver for the Arctic Development: Challenges with Infrastructure and Opportunities for International Cooperation
Authors: Akimova Irina
Published: November 2018

Arctic's huge reserves potential development was blocked for many years by the lack of accessible and all-year open for navigation transport routes. In spite of the fact that the Northern Sea Route is the shortest way from Europe to Asia, currently about 75% of the total cargo turnover delivers through the south corridor via the Suez Canal and the Mediterrenian sea, but the turnover via the Northern Sea Route is growing rapidly over the past years. Due to the strategic allocation of the Northern Sea Route it attracts enormous attention of the international companies now. This paper highlights challenges with the development of the Northern Sea Route nowadays along with the opportunities for international cooperation.
Reducing the Risks of Emissions and Potential Loss of Production Due to Uncontrolled Off Spec Gas into Pipeline by Modification of the Logic of Shutdown Valve
Authors: Kurniawan Fanda , Nugroho Aditya Bagoes , Walahendra I Putu
Published: November 2018

Potential loss of production and gas emissions to flare constitute major problems in gas processing plant when off-spec gas cannot be controlled and may cause the entire gas to pipeline being off-spec and endanger liquefied natural gas (LNG) plant as the buyers have to burn the entire gas in gas pipeline to flare and, thus, there is an increase in emissions to environment. Normally, the gas impurity parameters to be maintained in a plant consist of Hydrogen Sulfide (H2S), Carbon Dioxide (CO2) and water content (H2O), which are monitored by the online analyzer transmitter installed after the purification units, such as acid gas removal unit and dehydration unit. The transmitter normally does not send the interlock signal to command the plant shutdown due to several factors which may affect the values of the analyzer. However, the off-spec gas shall not be allowed to enter the pipeline; otherwise, emissions and loss of production cannot be controlled. Among the methods to control off-spec gas is to shut the export gas to the pipeline remotely whenever there is confirmed off-spec sales gas. Modification of control of sales gas shutdown during an off-spec event can be done by adding a logic from the remote push button to the shutdown valve at the export gas line which can be operated by human intervention to prevent the off-spec gas from being delivered to the pipeline and buyers which may lead to an increase in emissions to environment and a loss of production.
Multimillion Cell Dynamic Model for High Resolution Studies of a Carbonate Reservoir, Part-1
Authors: Al Jenaibi Faisal , Giddins Marie Ann , Valero Adelis , Ali Samad , Saeed Yawar , Amtereg Ahmed , Bajwa Ali
Published: November 2018

Simulating a high-resolution multimillion cell model brings many benefits, by enabling reservoir engineers to use the best grid size for accurate representation of water and gas movement in the reservoir, essential for advanced field management, Enhanced Oil Recovery or complex well design studies.

To improve the characterization of a giant heterogeneous carbonate reservoir and enhance the quality of field development plans, new high-resolution static and dynamic models have been used to study one of the largest oil fields in Abu Dhabi. A detailed static model of over 50 million grid cells was constructed, using a unique water saturation modeling approach, without upscaling to a dynamic simulation, using hysteresis for both relative permeability and capillary pressure.

The reservoir has over 50 years of history, with hundreds of vertical and horizontal wells. Large volumes of data from well logs, cores and other measurements were used to populate the static model, define dynamic rock types and match well log water saturation and water capillary pressure profiles. The concept of wettability change with depth was introduced, with an oil-wet system at the crest, graduating to a water-wet system near the thin transition zone. A geological resolution grid was used for reservoir simulation studies, after testing input data consistency and stable behavior.

A stability test was performed by running the simulation with no wells for 50 years after equilibration and showed no movable fluids. This verified the consistency of the reservoir static properties, rock types, water saturation, relative permeability and fluid model. A history matched case was developed with over 850 wells using the same fine grid, to meet the objective of completing each simulation run within one day. After history matching, a compositional simulation model was built, to investigate the impact of grid resolution on future production forecasts.

This is the largest dynamic model built by the company and demonstrates the benefits of rigorous attention to the quality of the static data, while using modern simulation workflows to avoid compromising the detailed model by upscaling. The methodologies presented in this paper will be adopted as best practices for future similar projects.
Modified Thermal Maturity Models for Kuwait Basin Through Mud Gas Isotope Logging While Drilling; Benefits of Analyzing d13C2 and d13C3 at Wellsite
Authors: Dashti Jalal , Al-Awadi Mashari , Mushnuri Sudhakar , Al-Meshilah Thuwaini , Shoeibi Ahmad , Cecconi Bianca , Estarabadi Javad
Published: November 2018

Carbon isotopic characterization of mud gas can add great value to the information collected at wellsite and nowadays the interest in this topic is increasing as documented by the study from Poirier et al. (IMOG 2017).

The presented study has the objective of illustrating the data logged through a cavity ring-down spectroscopic (CRDS) technique that allowed collection of robust and reliable carbon isotopic data at wellsite. The logged carbon isotopic data were then used for studying the behavior of two formations (Makhul and Najmah) across different fields. Makhul Formation represents the lower most Formation of Cretaceous in Kuwait, representing predominantly as carbonate rock. In lower Makhul, the high gamma radioactivity is due to enrichment of the shales by uranium. While, Najmah formation is an excellent source rock located in upper Jurassic, it consists of black calcareous limestone source rock with high organic content. Both formations are considered as major source rocks for petroleum systems in state of Kuwait. Many standard interpretation models from the literature were screened and adopted in inter-field correlation, resulting in a good matching with the geographical distribution of the fields.

The second part of the study will focus on the added value of recording carbon isotopic ratios up to C3. The analysis of δ13C3 is demanding from the instrumental point of view, thus, the benefits in terms of formation evaluation that comes from the logging of isotopes up to C3 will be illustrated in the study. With reference to other literatures, δ13C1 readings might be affected by mixing phenomena with biogenic gases, and thus they are not the best candidates to run maturity assessment through isotopes. Instead, carbon isotopic ratios of ethane and propane are not affected by mixing with biogenic gas, resulting in more robust and accurate interpretations. Few models from literature were applied on collected data, allowing choosing the one that matches best the behavior of the studied basin.

Independent measurements on the maturity of the source rock in the area confirmed that the trend highlighted through carbon isotopes logging at wellsite is correct, validating the usefulness of this technique at wellsite.