bluuebunny/crossref_metadata_2025 huggingface dataset:
Comprehensive Methodology to Evaluate Blowout Probability Through the Combination of Geological Uncertainties, Human Errors and Equipment Reliability
Authors: Zausa Fabrizio , Spelta Andrea , Lorefice Roberto
Published: November 2018

The most significant threat to oil exploration and development is an uncontrolled release of reservoir fluids during drilling operations, commonly called a blowout. Besides its tragic environmental and human impacts, Macondo accident fostered the awareness in the industry that blowout risk goes further the idea of an implicit risk of drilling activities: blowout is an operative risk to be properly assessed, as reported in the European Directive 2013/30/EU on offshore operations. In order to tackle such request, Eni developed a standardized methodology called e-wise™ (eni Well Incident Systematic Evaluation) that provides an objective and reliable assessment of blowout risk.

As a prelude, the common criteria based on statistical occurrence of blowout was considered neither exhaustive, nor accurate. Actually these statistics are suffering from many limitations: limited time span, outdated technologies, inconsistent environment (now deeper wells), variety of technical approaches, and no consideration of risk exposure duration.

ENI decided to measure blowout probability with a comprehensive methodology accounting for the three key elements affecting blowout occurrence: geological uncertainties, equipment reliability and human errors. The methodology put together automatically in properly designed fault tree, the three root causes and it applies them on specific well designs.

The result of this approach is a standard way to calculate blowout risk that can be applied on rig/rigless operations, supporting well engineering and permitting process. This solution, named e-wise™ is able to generate two types of standard outputs: full breakdown of blowout frequency by section/flowpath and extensive bow-tie for communication and certification purposes.

The full breakdown of blowout frequency allows the engineering and the operations to focus their attention on the most critical phases of the well. The model can be used for further sensitivity analyses foreseeing alternative operating procedures or additional safety technologies in order to have an univocal assessment of their benefits in term of blowout probability reduction. As a matter of fact, specific R&D programs are assessed through e-wise™ to address their potential value in terms of safety improvement.

The bow-tie depiction of the results provides a synthetical representation of all detailed calculations, where some models encompass more than 20 scenarios, each one having dozens of sub components. A bow-tie supports the communication of the results toward management and authorities by giving a complete vision of the blowout with the relative reliability of safety barriers and the different impact scenarios including containment and relief strategies.
Optimization of Design Using Computational Fluid Dynamics Technique for New P&A Down Hole Milling Technology - Case Studies of Rig Run Comparisons Validating Design Changes
Authors: Haq Mohammed , Deshpande Kedar , Imtiaz Khalid , Smalley Michael
Published: November 2018

Hydrocarbon migration after plug and abandonment (P&A) operations negates well integrity and threatens the environment. A section milling procedure for P&A that achieves rock to rock bond eliminates the risk of releasing fluids and gases to surface. This section milling procedure usually involves milling a window in the inner casing and then creating another window in the adjacent outer casing. The tool developed for this process is commonly known as dual string section milling (DSSM) tool. Simulations using advanced finite element analysis (FEA) and computational fluid dynamics (CFD) prior to prototype manufacturing is an extremely useful guide for predicting performance, optimizing design and avoiding costly oversights. This results in higher quality of design of pioneering or innovative products while reducing development costs and time to deliver tools to field.

The scope of this paper is to discuss design optimization using CFD that resulted in efficient flow distribution leading to elimination of wash out issues during field runs, while highlighting case studies summary based on design changes made to the new dual string section milling tool. Initial testing of dual string section milling tool design was done on test drilling rig that revealed some erosion prone areas in the tool; this design was modified using CFD to eliminate these erosion prone areas. However, during field runs in salt dome reservoir applications, the erosion issues reappeared in critical flow areas. Further CFD analysis was conducted to eliminate erosion in critical areas to formulate the final product design. The goal was to develop an optimized design delivering extended milling times when the section window requirements were 100 feet or more without any washout or erosion issues while using high pump flow rates.

This paper discusses the optimized dual string section milling technology using advanced computational techniques. The development of this technology is an enormous time saving for operators versus using conventional methods- in one offshore field case it resulted in more than 20 days savings in milling time.
Source Rocks of the Thamama Hydrocarbon in Abu Dhabi
Authors: Taher Ahmed
Published: November 2018

More than 80% of Abu Dhabi oil reserves are accumulated in the Thamama reservoirs. However, its source rock locations, thickness and richness distributions are not fully understood.

Thamama hydrocarbons were generated and migrated from different source rocks including Diyab, Rayda, Thamama dense and Shuaiba basinal facies, in addition to a contribution from the deeper Paleozoic, Silurian Qusaiba and the Pre-Cambrian Huquf source rocks.

The Oxfordian, Diyab high-energy Oolitic belts are prograding in westward direction, and have resulted in the development of Diyab intrashelf basin in west Abu Dhabi. At the end of the Kimmeridgian time, Abu Dhabi basin was tilted towards the east due to the opening of Arabian-Indian Suture. This tilting had completely shifted the high-energy Oolitic belts to prograde in eastward direction, which resulted in the development of Rayda source rock in east Abu Dhabi.

The Thamama dense layers were deposited during the highstand system tract, which allowed some organic matter to be preserved; especially in intervals deposited below the wave base. The Shuaiba basinal facies were deposited in an intrashelf basin that was surrounded by the Shuaiba shelf facies. This resulted in restricted water circulation and anoxic conditions. Such depositional environment is reasonable for source rock preservation.

The hydrocarbon generations from these different sources were mainly accumulated in a super-giant Paleo-structure that was located in the northeast onshore Abu Dhabi. This Paleo-structure was segmented by the Late Tertiary tilting, which resulted in remigrating its trapped hydrocarbon into the prominent Abu Dhabi fields.

The development of Rayda source rock will increase the potentiality of finding additional unconventional hydrocarbon resources in east onshore Abu Dhabi. The high unconventional potential in this area can be attributed to the advanced level of source rock maturity and to the highly faulting and fracturing found in east onshore Abu Dhabi. The Rayda source rock maturity map confined the unconventional gas potential to the foreland basin while the unconventional oil potential is located to the south of this area (figure-10).

Understanding the locations of Thamama source rock kitchens will facilitate the delineation of its migration pathways. This will reduce the exploration risk and help in detecting prospective areas for stratigraphic traps potential along the Thamama migration pathways over all Abu Dhabi.
Significant Increases in Turnaround Maintenance Performance and Safety through Powerful Digital Integration
Authors: Tol Michel M.
Published: November 2018

More and more leading companies are moving to digital systems to support their operations, maintenance and turnarounds. This marks huge progress and sees impressive results: incidents and injuries decrease, risk becomes more understandable, and processes streamline and simplify. But if the information used within these digital systems is not connected or up to date, the concept simply does not work effectively.

Collaborating closely with major industry players such as Shell, BP, RasGas, Borouge, and others, eVision Software developed bespoke daily maintenance and turnaround management solutions, which address and mitigate many common turnaround and maintenance challenges. The enterprise-ready tool combines powerful Permit to Work, Risk Assessment, Isolation management and advanced (Mobile) visualisations, and integrates these into the client ecosystem. This study pertains to a major derivatives manufacturer in the UAE, in which a platform was implemented to help achieve ambitious hands on tool time increases during their planned shutdown.

Integration gets the most out of existing client data and solutions. From preparing digital permits and risk assessments in eVision's software using up-to-date equipment and location information from Maintenance Management Systems (MMS); to creating context-sensitive work execution packs linked to Oracle Primavera, which can be mass signed, enabling continuous scheduling optimisation; to effective and efficient maintenance execution empowered by mobile tools for front-line crew; to monitoring real-time data through connected dashboards. Data and systems are connected, information is shared in real time, reducing Turnaround time and improving capacity planning and Hands on Tool Time, thereby decreasing the number of contractors required for the next shutdown. This continuous feedback loop further enables the client to take lessons learned and improve their next turnaround, getting maximum return out of their digital solutions.

By taking a platform approach to shutdown preparation and execution, and utilising the vast amount of data available across systems throughout the asset, challenges could be met head-on and mitigated, without large-scale changes to infrastructure or methodology. Creating a synergy between existing systems, new solutions and effective and improved procedures allowed staff to focus on what really matters: quick and safe turnarounds. During the 2016 planned shutdown, a core goal was to increase the HoTT of staff and contractors by a minimum of 7%. eVision was able to improve HoTT by more than 17% overall, by tackling key challenges, such as permit cycle duration, work instruction time, and vast reduction of indirect productive hours. By implementing the integrated software platform, the workforce was able to more effectively utilise their time on plant.
Maintaining Flare Tip Health
Authors: Bakthavachsalam Venugopal , Buendia Gerald , Hashimi Haitham Al
Published: November 2018

Maintaining flare tip health is essential to ensure safe disposal of flammable hydrocarbons in any oil and gas industries. This paper presents best practices (from operation, to maintenance and inspection) to ensure the health of large flare tips. The flare tip mixes flammable fluids and air into the required concentration and velocity to maintain stable ignition and combustion. These flare tips are vulnerable to damages caused by burn backs that may result in serious threats to plant safety & integrity, as well as exorbitant replacement costs.

We will outline how we comprehensively mitigated thermal buckling failures in HP flare tips to improve the asset life and availability of these safety critical flare systems. In the past, we recorded frequent flare tip failures in the four stage HP flare system of trains 3 & 4. Replacement of these expensive tips was planned during major turnarounds. Meanwhile, the root cause analysis revealed that the thermal bucking tip failures can be attributed to "burn back". Inadequate purge gas flow, poor reliability of burn back detectors, inadequate design, control measures and project specifications were identified as causes for the burn back.

It was recommended to replace the fuel gas as a purge gas medium with nitrogen. This permanently preserved the integrity of the flare tips, while avoiding fuel gas wastage. In addition, the following best practices were recommended to maintain a healthy flare system. Improve the design and reliability of burn back detectorsChange the inspection approach to thermographic surveysImprove the pilot flame, burn back detectors and alarm system to provide low flow alarms for purge gas

The implementation of these recommendations enhanced the asset life and availability of the safety critical flare system, as proven by the thermographic survey, which shows colder operating conditions of the flare tips.
Influence of Pressure and Temperature on CO2-Nanofluid Interfacial Tension: Implication for Enhanced Oil Recovery and Carbon Geosequestration
Authors: Al-Anssari Sarmad , Arain Zain-UL-Abedin , Barifcani Ahmed , Keshavarz Alireza , Ali Muhammad , Iglauer Stefan
Published: November 2018

Nanoparticles (NPs) based techniques have shown great promises in all fields of science and industry. Nanofluid-flooding, as a replacement for water-flooding, has been suggested as an applicable application for enhanced oil recovery (EOR). The subsequent presence of these NPs and its potential aggregations in the porous media; however, can dramatically intensify the complexity of subsequent CO2 storage projects in the depleted hydrocarbon reservoir. Typically, CO2 from major emitters is injected into the low-productivity oil reservoir for storage and incremental oil recovery, as the last EOR stage. In this work, An extensive serious of experiments have been conducted using a high-pressure temperature vessel to apply a wide range of CO2-pressure (0.1 to 20 MPa), temperature (23 to 70 °C), and salinity (0 to 20wt% NaCl) during CO2/water interfacial tension (IFT) measurements. Moreover, to mimic all potential scenarios several nanofluids at different and NPs load were used. IFT of CO2/nanofluid system was measured using the pendant drop method as it is convenient and flexible technique, particularly at the high-pressure and high-temperature condition. Experimentally, a nanofluid droplet is allowed to hang from one end of a dispensing needle with the presence of CO2 at the desired pressure and temperature. Regardless of the effects of CO2-pressure, temperature, and salt concentration on the IFT of the CO2/nanofluid system, NPs have shown a limited effect on IFT reduction. Remarkably, increased NPs concentration (from 0.01 to 0.05 wt%) can noticeably reduce IFT of the CO2-nanofluid system. However, no further reduction in IFT values was noticed when the NPs load was ≥ 0.05 wt%. Salinity, on the other hand, showed a dramatic impact on IFT and also on the ability of NPs to reduce IFT. Results showed that IFT increases with salinity particularly at relatively low pressures (≤ 5 MPa). Moreover, increased salinity can eliminate the effect of NPs on IFT. Interestingly, the initial NP size has no influence on the ability of NPs to reduce IFT. Consequently, the potential nanofluid-flooding processes during EOR have no negative effect on the later CO2-geosequestration projects.
A New Method for Diagnosing Caves in Fault-Karst Carbonate Reservoirs
Authors: Xu Yandong , Hu Wenge , Pang Wei
Published: November 2018

Shunbei block is nearly the deepest oilfield in China with formation buried about 8000 meters. Good production performance is gained with rate as high as 100t/d per well. The formation belongs to fault-karst carbonates and is composed by caves, natural fractures and matrix. The current well testing models that assume dual or triple mediums cannot give reasonable interpretation such as the volume of caves and the connectivity between caves.

We proposed a new model for the well connected to one cave in the carbonate formation based on the three laws of mass conservation, momentum conservation and energy conservation mechanics. The concept of wave propagation is introduced and the model incorporating fluid flow and pressure wave propagation is built in the caves. For the cave connected to the wellbore, its volume can be obtained by history match of the log-log plot of the pressure and pressure derivative. The matrix is viewed as storage medium and it provides fluid to the caves by crossflow. Field cases are conducted to validate the proposed method.

Results show that the sequent flow regimes including wellbore storage, transition from wellbore storage to cave storage, wave propagation and fluid flow in cave, formation flow can be diagnosed in the log-log plot of the pressure and pressure derivative, therefore, the new method can characterize the features of fault-karst carbonate reservoirs such as the volume of caves. For the field case, from pressure buildup test, the volume of the caves connected to the wellbore is estimated as 37281.41 m3. Log-log plots of the pressure and pressure derivative show good agreement with the pressure buildup data, therefore, the models are validated and the results interpreted are accurate and confident.
A New Approach to Well Construction Cost Saving, The Success of Drilling Long Departure Dual Lateral Wells in United Arab Emirates Onshore Field
Authors: Morales Annie , Al Yamani Sultan , Salem Gamal , Nava Jose , El Barbary Abdalla , Pham Dang Le Khoa , Diaz Nerwing , Adams Adeniyi
Published: November 2018

Drilling wells with long departure for extended reach applications is indeed a difficult task. Adding dual lateral sections involves increased risks, thus feasibility studies for wells design and execution purposes are critical. However, the success of this challenging campaign has enabled a new way of cost saving for wells construction.

This case study demonstrates the solutions during drilling and completion by using a single surface slot with two strings for deep water and gas injection wells in shallow coastal water field in UAE.

Dual laterals with long departure involve risks associated with drilling and completion, especially for long sections at high inclinations.

The process involves optimization of the well trajectory to minimize the inclination at whipstock setting depth in order to reduce the drilling footage in the dense formations. Optimizing the Bottom Hole Assembly and drilling parameters to improve the rate of penetration (ROP), always targeting shoe to shoe runs; optimizing the retrievable whipstock type selection together with retrieving procedure; improving the completion design in high inclination at nipple depth to be able to set the packer and test the tubing successfully.

Drilling one for two is the most beneficial point that this well construction practice has offered. Exiting from a congested surface location expose to the highest risk of Anti Collision, now reducing to 50% the exposure minimizing HSE risks. Saving surface facility while delivering two reservoir drains for better productivity is the key element for cost reduction. Most importantly, the concept is feasible and proven.

Surface location has become increasingly more congested in this field thus much higher collision risk, drilling and completion technical constraints are being pushed beyond their limit to target deeper and further reach reservoirs. Lessons learnt and recommendations have been captured to establish the basis for continuous performance improvement. This paper presents a novel approach to well construction with increasing efficiency, integrity from all involved parties, reducing operational risks while significantly reducing cost, and ultimately increasing productivity and profitability.
Novel Assessment of Hydraulic Fracturing with Geomechanical Characteristics in Tight Carbonate Formations
Authors: Jang Youngho , Yoo Hyunsang , Sung Wonmo , Lee Jeonghwan , Lee Won Suk
Published: November 2018

Hydraulic fracturing in naturally fractured tight formations causes complex fracture geometry corresponding to the existence of natural fracture as well as geomechanical characteristics. It is extremely important when stimulating fluids such as water, brine, and CO2 are injected into tight carbonate reservoirs for increasing recovery. For fracture propagation modeling, several models have implemented multiple planar fracture with only opening mode, which have a problem in representing realistic fracture behavior.

In this regard, we proposed a hydraulic fracture propagation model implementing multiple planar approach with mixed mode including opening and sliding modes for being able to describe fracture propagation more realistically. When hydraulic fracture encounters natural fracture non-orthogonally, fracture tip slides first along the natural fracture face, and then propagates into rock mass. That is why sliding mode also needs to be considered. With the use of the model, this study analyzed the effects of the brittleness on fracture propagating behavior and gas recovery for tight formations with respect to Poisson's ratio and Young's modulus.

We investigated the modeling results for examining the importance of the sliding mode newly employed in the hydraulic fracture model. In the case of a formation having a high brittleness index, which presents greater deformation longitudinally rather than transversely, called the formation A, the effect of sliding mode was not critical on the fracture propagation. Meanwhile, in a formation having an intermediate brittleness index, named the formation B, the hydraulic fracture less easily crosses natural fracture because Young's modulus of this formation is lower comparing to the formation A, and consequently, implementation of the sliding mode is more dominant. In a formation representing higher Poisson's ratio and Young's modulus compared to formation A, which denotes a low brittleness index, since it shows larger deformation in transverse direction, hydraulic fracture hardly crosses the natural fracture, and thereafter, the propagating direction of the crossed fracture is highly deviated. The larger brittleness index, the greater in stimulated reservoir volumes by up to 17% because fracture crossing occurred easily.

Therefore, the model with the mixed mode proposed in this study was found to be extremely important in the analysis of fracture propagation behavior resulting the stimulated reservoir volumes and gas recovery differently in tight carbonate reservoirs.
Development of In-House Novel Process Scheme to Mitigate BenSat Unit Oxygen Stripper Overhead System Corrosion with Reduced CAPEX
Authors: Chaudhuri Rajib Kumar , Rauof Raji A.
Published: November 2018

As part of the worldwide drive to produce cleaner fuels via Benzene reduction in the Gasoline Pool, ADNOC Refining utilizes the Innovative Benzene Saturation Technology which selectively targets saturation of only the benzene fraction to minimize the loss of octane number. The Benzene Reduction Unit (BenSat Process)is designed to process combined full reformate stream from two existing reforming units and comprises of the Oxygen Stripper, Reformate Splitter columns and BenSat Process unit. Severe corrosion and leaks were observed in the Overhead Circuit of the BenSat Unit after 2 Years of operation. Detailed Root cause analysis indicated to variations and contaminants in the feed stream as the main cause for the corrosion. Based on lab result of corrosion deposit analysis, which showed a presence of 78% of Iron & 9.8% of Oxygen, and morphology of failure i.e. presence of pits and tubercles it was concluded that the most probable reason for the failure is Oxygen corrosion aggravated by the presence of chloride.

As the contributing causes were identified to be continuous in nature, a comprehensive solution was required at ADNOC Refining to ensure that similar failures do not re-occur. An upgraded and expensive metallurgy for the entire overhead circuit was the obvious solution for such a problem. However even this solution only prolongs the effects of corrosion and does not mitigate the corrosion at the source. The Technical Team at ADNOC Refining (RRW) developed an economical and continuous chemical injection system to resolve the issue at the source itself. Given the sensitive nature of the platinum Catalyst in the downstream of the Oxygen Stripper System, the selection of appropriate chemicals was a challenge. A unique combination of Corrosion Inhibiting filmer and a Neutralizing Amine was selected while ensuring overall compatibility with the system. A Chemical Injection Skid Framework was designed, engineered and built in-house in record duration for immediate commissioning. Upon implementation of the chemical injection system, it was observed that corrosion halted completely within one month. The paper explains in detail the troubleshooting and implementation methodology. These methodologies further highlight how efficient team work is able to deliver in-house solutions in the shortest possible durations.
Analysis of Diffusion Coefficient and Fracture Aperture in Coal using Micro-Computed Tomography Imaging
Authors: Lu Xiao , Armstrong Ryan , Yuan Meng , Zhang Yulai , Mostaghimi Peyman
Published: November 2018

Coalbed methane (CBM), also known as coal seam gas, is becoming an increasingly important energy resource in the global natural gas market. Gas transport in CBM reservoirs remains a crucial research topic that has not been fully understood. Two scales of gas flow are identified in coal cores: flow in fractures and diffusion within matrix. The diffusion process is quantified by the gas diffusion coefficient while flow in fractures is governed by fracture apertures. This paper aims to explore the diffusion process in coal using X-ray microcomputed tomography (micro-CT) imaging. The experiments are conducted at 100 psi effective stress to eliminate the impact of pressure. The images obtained are registered for visualisation and analysis of the diffusion process and comparisons of fracture. In the paper, the impact of increasing effective stress on fracture aperture is demonstrated. Also, the diffusion coefficient of Krypton in coal matrix is estimated and discussed.
Prediction of Hydraulic Properties in Carbonate Reservoirs Using Artificial Neural Network
Authors: Khalaf G. Salem Khalaf Gad , Abdulaziz M. Abdulaziz Abdel Aziz , Abdel Sattar A. Dahab Abdel Sattar
Published: November 2018

An accurate estimation of porosity and permeability are extremely essential for designing an ideal and efficient program of an oil and gas field development. Numerous methods have been developed to determine the porosity and permeability including laboratory measurements and log derived models. Artificial neural network (ANN) provides an efficient technique that successfully addressed several engineering and geological challenges. In the present study ANN is applied to help in predicting porosity and permeability in carbonate reservoirs using back propagation neural network (BPNN) with high accuracy on well log data from numerous fields worldwide.

ANN has the ability to understand a highly non – linear relationship and to perform simulation studies in a rapid manner. The BPNN model of porosity and permeability is developed using a set of well logging data as input layers and core porosity and core permeability as output layers. Two scenarios are considered to develop by ANN.

The first scenario considers using all available logging data directly as input for ANN. In the second scenario an additional input, diagenesis parameter, is added as input to ANN which is essentially calculated from logging data. In each scenario two models are developed; the first for porosity prediction and the second predicts permeability in carbonate reservoirs. The optimal learning rate and momentum constant used in the BPNN model are achieved after serial combinative trials. The available data was assigned 80% for training and 20% for verification.

The results of the developed porosity and permeability models are well compared to core data in verification. In the first scenario, cross-plot of the actual porosity versus ANN predicted Porosity exhibited a good match with a correlation coefficient equal to 0.97. Cross-plot of the actual permeability versus ANN predicted permeability exhibited a good match with a correlation coefficient equal to 0.80. In the second scenario, cross-plot of the actual porosity versus ANN predicted porosity exhibited a good match with a correlation coefficient equal to 0.97. Cross-plot of the actual permeability versus ANN predicted permeability exhibited a good match with a correlation coefficient equal to 0.98. Such data indicate that the developed models are successful in predicting the porosity and permeability for carbonate reservoirs.
Modeling the Effects of Salinity, Polymer Rheology, Temperature, and Reservoir Wettability on the Performance of In-Depth Gel Treatment Coupled with Surfactant and Polymer Flooding
Authors: Khamees Tariq K. , Flori Ralph E. , Alsubaih Ahmed A. , Alhuraishawy Ali K.
Published: November 2018

In-depth gel treatment is a chemical EOR process used to improve the sweep efficiency from heterogeneous reservoirs with crossflow. However, if these reservoirs are saturated with viscous oil, polymer and surfactant flooding should be combined with in-depth gel treatment. Thus, in this study, a 3D model using the UTGEL simulator was built to model in-depth gel treatment combined with surfactant slug and polymer solution. The model was represented by one quarter of the five-spot pattern with eight layers where two thief zones are located in the middle of the model. The thief zones had a permeability of 1500 md with a total thickness of 20 ft, while the rest of the layers had a permeability of 100 md with a total thickness of 200 ft.

The gel system consisted of a polyacrylamide/Cr(VI)/thiourea solution, which is considered an in-situ gelation system. Gelant solution was injected for 60 days when the water cut in the model reached 65%, followed by surfactant slug for 2 years, polymer solution for 3 years, and then post-water injection for the rest of the simulation time. The concentrations of the surfactant ranged from 0.01 to 0.2 wt.%, while the polymer concentration was 1,000 ppm. The injection rate was 1,070 bbl/day during all flooding and treatment processes.

The results showed that it is imperative to implement surfactant with gel treatment to reduce the interfacial tension between water and oil phases and to alter the wettability of the reservoir rocks. Thus, gel treatment alone or gel followed by polymer was not as efficient as the injection of a surfactant slug. The results also showed that as the reservoir temperature increased, the overall performance of gel, polymer, and surfactant decreased. Therefore, the higher the temperature, the lower the recovery factor. The results also revealed the importance of viscoelastic behavior of the HPAM polymer solution where higher results for both water-wet and oil-wet conditions were obtained compared to shear-thinning behavior only. Moreover, the results revealed interesting behavior regarding the concentration of the surfactant, where the recovery factor increased as the concentration of the surfactant increased in oil-wet conditions. However, in water-wet conditions, the results were unpromising and unfavorable. Furthermore, the injection of surfactant directly after the gel treatment was more effective in improving the sweep efficiency than the injection of polymer directly after the gel treatment. Finally, as the salinity of makeup water and/or reservoir brine increased, the recovery factor decreased for both water and oil-wet systems. This is because, as salinity increased, the adsorption of both polymer and surfactant increased and the polymer viscosity decreased. Furthermore, the presence of divalent cations such as Ca+2 and Mg+2, would have a negative impact on overall treatment.
Automated Multidisciplinary Collaboration in Integrated Reservoir Management IRM through Business Process Management BPM
Authors: Marzouqi Mohamed Al , Saputelli Luigi , Abdou Medhat , Mohan Richard , Pandian Senthil Murugan , Hammadi Maryam Al , Khan Muhammad Navaid , Cumming John , Pires Joshua , Escorcia Alvaro
Published: November 2018

The objective of this work is to enable the collaboration of multiple disciplines in the performance reviews of reservoirs while establishing a culture of variance reduction and sustainable consistency in results delivery. This effort focuses on the performance management reviews of very large carbonate reservoirs where the number of wells and producing zones overwhelm engineers and organizations with data volume and complexity due to areal and vertical heterogeneity.

A novel Reservoir Performance Review (RPR) solution has been implemented across various offshore reservoirs units. RPR initiates all asset activities during reservoir performance reviews and allows the tracking of actions over the life of the reservoir.

RPR leverages data analytics to automatically compute reservoir health key performance indicators that allow prioritization of the technical work, extract and transform data from multiple data sources, deliver performance dashboards with diagnostic plot standardized across all assets and users providing an archive of information and knowledge from past reservoir performance reviews.

RPR leverages business process management and integrated visualization to assist in the identification and recording of opportunities, risks and actions, while providing control and management of the business processes.

The solution offers an innovative way to collaboratively gather, validate, analyze reservoir performance across the asset on a sustainable and cost-efficient manner while addressing more formal approval processes in order to garner approval or authorization for action. Some of the realized benefits include ensuring effectiveness in the execution of reservoir management, monitor variance between actual performance and expectation during the execution of projects; and ensure production sustainability and mitigate shortfalls proactively. RPR enabled the achievement of a consistent approach across all assets for all reservoir performance review processes, while improving efficiency through automation of data gathering and presentation and the identification of all underperforming reservoir, sectors and fields.

Reservoir management excellence is achieved by delivering immediate value on the opportunities identified during performance reviews which ensure short term profitability while preserving long term goals. Typically, operators are satisfied by meeting targets within certain tolerance. RPR ensures that performance excellence is achieved by considering all technical and business aspects.
Integration of P-P,P-S, and Diffraction Imaging Brings Geophysics, Geology and Engineering Together-A Case Study of the KOC Sabriyah Field
Authors: Al-Saeed Hanan , Duncan S. Bruce , Al-Kanderi Jassim , Negut Dan , Martin Cathy , Nowry Wayne
Published: November 2018

The Kuwait Oil Company's (KOC) Sabriyah field, located in North Kuwait, produces oil and condensate from the Jurassic Najmah formation in a structurally complex setting. In 2017, Kuwait Oil Company reprocessed their 50 square km, three-component 3D seismic survey originally shot in 2010, to include shear wave splitting analysis and diffraction imaging. This project was undertaken not only to seismically image the structures better but to also better define faults and fractures and their positioning in the Najmah.Also in order to determine maxium and minimum stress directions and correlate with the known geological areas of maximum stress from previous core work. This work will help the Engineers to determine best orientation directions for drilling programs to add value.

One of the purposes of this project was to help answer the disconnect between the actual well logs,geology and the conventional seismic interpretation when tied to the well on crestal part of the anticline. The other main purpose was to see if we could help engineers place vertical and horizontal wells in optimal positions through the use of P-P,P-S, and diffraction imaging geophysical methods we were able to come up with a comprehensive look at the fractures and faulting of the Najmah as well as match with current drilling results.
First-Ever Large Diameter Fully Captured & Retained Pressurized Core and In-situ Analysis with Slow Depressurization - Pilot Case on Giant Burgan Reservoir, Kuwait
Authors: Mukherjee Pritish , Peres Jose , Hayat Laila , Anders Dr Erik , Al-Rashaid Mona , Wunsch David , Rothenwaender Tobias , Al-Kandari Jassim
Published: November 2018

Typically, conventional cores provide indeterminate reservoir condition; suffer loss of unknown volume of hydrocarbon fluid and mechanical integrity while being retrieved. Most laboratory analysis thereafter are simulated however it's not truly turning back the lost conditions into in-situ condition. A fully captured, and pressure retained core is thought to be a solution to provide a true micro-reservoir at surface which explains the reservoir behaviour as it behaves in subsurface. This led to successfully deploying the technology to fully capture a large diameter pressured core for the first time in conventional hydrocarbon industry in Giant Burgan Field in southeast of Kuwait in a Middle Cretaceous Clastic reservoir and also to derive a number of critical parameters from the retrieved micro-reservoir. The technology involves lowering of a large diameter pressure corer (LPC) with an outer pressure vessel and inner core barrel. After the core is cut, a drop ball mechanism sets the inward movement of the inner barrel past a spring activated pressure seal thereby keeping the core in reservoir condition. While continuous pressure recording on the retrieved core, a core analyser (PCAL) system captures multiple sets of reservoir data through a predetermined slow depressurization without hampering any operations on the rig floor. Other than measuring accurate reservoir pressure, the analytical process provided for sampling of released gases, fluids and PVT samples in addition to in-situ bubble point estimation, all at the rig site. The onsite gas analysis with compositional changes during depressurization and bubble point estimation well matched with the subsequent analysis performed on the samples in laboratory. Thus, a real representative Upper Burgan reservoir sand was retrieved containing present reservoir pressure with all fluids retained. Additionally, it provided a nearly undisturbed core with high degree of original mechanical integrity. The final depressurized core is then sent for further laboratory investigations and geological studies including slabbing and plugging. This encapsulated "micro-reservoir" is less sensitive to unexpected events like delays during retrieval and analysis, avoiding damages of the core or loss of fluids. The technology stands out against systems delivering cores at partial or no pressure retention, as it retrieves cores at formation pressure with all fluids retained and core integrity unaltered.
Offshore Electrification from Onshore through Submarine High Voltage AC Cables
Authors: Renaudin Fabien , Toulotte Maxime , Cebeci Ipek , Manna Malay , Shabaka Ashraf , Kotrappa Murugendrappa N. , Sundaresan Hemachandran
Published: November 2018

The objective of the proposed paper is to present the successful electrification of a newly built offshore super complex from shore as well as the shift of power production from offshore to onshore generation of an existing offshore super complex using high voltage alternative current (HVAC) submarine power cables. Both offshore super complexes are electrified from an island and are connected together to create a redundancy in the power supply between them.

The design, qualification, manufacturing, testing, and installation of the HVAC submarine cable system including fiber optical elements and accessories are described in this publication.

The HVAC submarine power cable system for the oil field development is composed of three 132 kV insulated cables which connect the offshore super complexes and the island with length ranging between 30 to 80 km. It also includes HVAC underground power cable to connect the HVAC submarine power cable to the power generation installation as well as approximately 60 km of medium voltage alternative current submarine power cable which are used to power other offshore equipment from the new offshore super complex.

The HVAC cables were designed to fulfill the load demand of both offshore super complexes considering redundancy in the HVAC power system as well as challenging installation conditions at the landing at the island. The technology used for the cable is the well-proven cross-linked polyethylene (XLPE) insulation technology.

The HVAC cables were successfully qualified and type-tested according to the requirements of IEC international standards and CIGRE recommendations.

Each three-phase cable was manufactured and tested within the manufacturing facility in Norway in one complete length insuring that a high-quality product was supplied. It also permitted to install each cable in one laying operation without having to introduce offshore field joints in the cable system.

This publication shows that electrifying offshore assets from an onshore power source using submarine power cables is a viable solution.
Forecasting Unconventional Volatile Oil Reservoirs Using Compositional Reservoir Simulation and Hybrid Decline Curve Models
Authors: Xavier John , Khanal Aadi , Lee John
Published: November 2018

Despite emerging technology in the areas of unconventional forecasting, recovery factors are merely a fraction of its conventional counterparts. Unconventional reservoirs are characterized by their ultra-low permeability. It is to be noted that traditional decline curve analysis (DCA) is not best suited to forecast unconventional reservoirs. This is due, in part to a variety of reasons the most important being lengthy transition zones from transient flow to boundary-dominated flow which is highlighted in this paper via the usage of diagnostic plots.

The objective of this paper is to compare the production performance of volatile oil reservoirs, generated from a commercial compositional simulator, by using simple decline models used in the industry. Fluids with different initial gas to oil ratio (GOR), due to different fluid composition, was simulated for a period of 30 years. Oil rate was forecasted by assuming different lengths of available production history. We present the application of diagnostic plots to identify different flow regime. The results from our study showed that the duration of linear flow period and the transition from linear to boundary dominated flow varies drastically based on the initial fluid composition. With respect to the decline curve analysis performed, a hybrid decline curve model was used to model different sections of the production profile. Since we are analyzing volatile oil reservoirs, the biggest challenge in performing traditional DCA is the effect of multi-phase flow behavior. So, use of hybrid decline model results in a better production forecasting compared to a single decline curve.

With the advent of the shale boom, many oil and gas producers struggle to forecast unconventional reservoirs effectively. We believe that this paper serves to further elucidate the theory and application behind the concept of unconventional forecasting.
De-Risking Multi-Well ASP EOR Pilot in a Challenging Clastic Reservoir in Kuwait Following Successful Implementation of a One-Spot EOR Pilot
Authors: Al-Murayri Mohammed T. , Kamal Dawoud S. , Al-Mayyan Haya , Shahin Gordon T. , Shukla Shunahshep R. , Ten Berge Anke B.G.M.
Published: November 2018

Following encouraging results from laboratory experiments, simulation studies and a one-spot EOR pilot for the Raudhatain Zubair (RAZU) reservoir in Kuwait, a multi-well pilot is planned in the near future. A combination of high temperature (90°C), in-situ brine salinity (>250,000 ppm) and divalent ion concentration (>20,000 ppm) make implementation of Alkaline Surfactant Polymer (ASP) flooding in RAZU quite challenging. The presence of a ‘Tar Mat’ interval in the pilot area further complicates pilot design. This paper outlines some of the risk mitigation measures for a successful ASP pilot.

Laboratory experiments were performed to evaluate different polymers for improved thermal stability and to obviate the risk of polymer precipitation at the producers. Based on long-term thermal stability studies and producer scaling considerations, HPAM/ATBS based polymer was chosen over HPAM -based polymer. The original formulation which was used in the one-spot EOR pilot required 3.5% co-solvent to overcome surfactant separation at optimal salinity. Several alternative alcohols were tested and finally an appropriate co-solvent that gave adequate performance at 1.5 wt% was selected to reduce cost and logistical requirements. Additionally, optimization experiments were conducted to de-risk emulsification potential of produced oil by reducing the concentration of the injected surfactants. Finally, experiments were carried out to characterize the nature of the hydrocarbon and rock in the ‘Tar Mat’ interval to evaluate the risk versus reward of perforating it in the pilot area.

This is the first time, to our knowledge, that ASP injection is being considered in a reservoir in such a harsh environment due to combination of high temperature, salinity and divalent ion concentration in formation brine. The presence of a ‘Tar Mat’ interval further complicates pilot design. The successful execution of this pilot will push the envelope of ASP deployment in other challenging reservoirs worldwide.