bluuebunny/crossref_metadata_2025 huggingface dataset:
Successful Implementation of EPC for New WAG Wells Project at SE-Field at ADCO
Authors: Ghazo Samer
Published: November 2016

The Water Alternative Gas Injection Wells (WAG) are newly type of wells that ADCO start using in theory Fields, therefore, I decided to share the experience, lessons learned, challenges, mitigation criteria and some of the formats, that we used during the implementation of the EPC New WAG Wells & Conversion of Existing Gas Injectors Wells to WAG Wells at SAHIL, which awarded on March. 2014 for 18 months with budget of 109 Million DH, and completed without LTI after 1.2 Million man-hour.

The EPC new WAG wells project was completed and the target achieved, therefore in this work we highlighted the following:

Theory about the WAG wells, the importance of this type of wells in the oil and gas fields, and explains its components. EPC, Engineering Procurement and Construction, definition, phases, and risks associated with those types of projects. EPC for New WAG Wells & Conversion of Existing Gas Injectors Wells to WAG Wells at SAHIL. State a facts about the projects, scope of work, Duration, resources required, and then highlight ADCO specific requirements for such projects. Successful criteria that led to the success of the project; anticipation, preparation and execution at the right time were the main factors in the success of the project. Challenges that faces the project; share some of the challenges and how to mitigate them.

This work will help all the project management team to manage such projects, and provide a guideline for how to manage similar projects, where this project was an example of a successful projects that ADCO accomplished recently.
Estimation of Petrophysical Parameters of Heterogeneous Carbonate Rock Sample with Multi-Scale CT Images
Authors: Sun Huafeng , Vega Sandra , Tao Guo , Yong Hong , Li Bing
Published: November 2016

The understanding of petrophysical properties is essential for the assessment and exploitation of hydrocarbon reserves. Reservoir rock is one of the main sources used to derive petrophysical properties by laboratory measurements. However, probing complex pore structure and heterogeneity of carbonate rocks are difficult with conventional experimental methods. Digital rock physics (DRP) is able to compute the petrophyscial parameters (e.g. porosity, permeability, elastic modulus) from three dimensional (3D) computed tomography (CT) images, which can make up for some disadvantages of traditional experiments. It also provides an understanding on how the large variations in petrophysical properties are caused by wide variations in pore type, pore shape, and pore interconnectivity.

This paper is a case study on analysis of heterogeneity and estimation of petrophysical parameters in a heterogeneous rudstone sample using multi-scale CT images with three resolutions of 39.48 μm/voxel, 1.0357 μm/voxel and 65 nm/voxel. The Back-scattered Electron Image (BSEI) analysis that is used to locate subsamples in low-resolution image for high-resolution CT scan shows the range of pore-throat radius size of this sample is from 0.1μm to 10μm and most pores are under 1μm. The low-resolution images (here resolution of 39.48 μm/voxel and 1.0357 μm/voxel) show a poor pore connectivity. The high-resolution image (65 nm/voxel) provide a more detailed pore structure that contributes to estimation of petrophysical properties. The estimated porosity (21.92%) and absolute permeability (6.54mD) from the high-resolution images are close to the lab measurements (22.7% and 4.9mD), which shows the accuracy of DRP in this particular sample. The relative errors of elastic modulus between the simulation and the measurements are 77.23% and 87.68% for bulk moduli and shear moduli, respectively. The image registration locates the Nano-CT images in the low-resolution image (1.0357 μm/voxel), which better characterize the pore geometry in different 3D image and provide a new way to do the upscaling work. The multi-scale images, the visualization of fluid velocity distribution, the lab measurements, and the simulated values show the heterogeneity of this carbonate sample.
Seismically Derived Porosity Prediction for Field Development- An Onshore Abu Dhabi Jurassic Carbonate Reservoir Case Study
Authors: Chatterjee Shraddha , Burreson Matthew , Six Bertrand , Michel Jean-Marc
Published: November 2016

A high quality broadband impedance solution by inverting seismic amplitudes is one of the most common industrial standards to integrate geophysical inputs into geological models during field development studies and planning. The use of accurately quantified petrophysical volumes derived from seismic data during geological model building can help improve the understanding of the reservoir and in maximizing the value of seismic data.

During this case study for two sour gas carbonate reservoirs- reservoir units C & D, in an onshore Abu Dhabi field, the acoustic impedance volume from seismic inversion and the seismic data itself were further converted into a porosity volume by a probabilistic neural network (PNN) approach. This non-linear transform approach establishes the link between seismically-derived impedance and porosity through an optimized training correlation and error method approach at each well location. A combination of the following factors pertaining to training dataset, established a successful neural network based porosity prediction workflow for the reservoirs: Amplitude preservation of seismic data (target-reservoir specific re-processing)Many calibration wells with good quality calculated log porosityHigh quality inverted seismic impedance.

A high correlation of predicted porosity to measured well porosity was achieved at all the well locations. In addition, reservoir unit C porosity grades from a very high but thinner porosity at the top to medium-high thicker porosity at the base, which was well resolved within the available seismic bandwidth and the PNN method of porosity prediction matched this variation of the log porosity. High cross-validation scores achieved during PNN training for porosity prediction, in effect provided the confidence in prediction away from the wells. Furthermore, a close match of predicted and measured porosity at blind test wells drilled in the field extended the confidence in the porosity prediction results. The porosity prediction successfully delineated regionally known non-porous lineaments and faults (encountered while drilling wells) on mean porosity maps of the two reservoirs.

The main objective of reservoir-focused reprocessing was to minimize the amplitude damaging effects of the near-surface, mainly due to presence of large sand dunes, and adequately prepare the data for seismic inversion. Successfully estimating seismically derived porosity was an important tool for well planning, geosteering long reach horizontals and also a key input for reservoir characterization to improve our understanding and distribution of reservoir properties in our geologic model.
Styles of Salt Tectonics in the Sab'atayn Basin, Onshore Yemen
Authors: Tari Gabor , Zabalza Isabelle , Neff Pascale , Dellmour Rudolf , Rodgers Emma , Asmar Chloe , Hagedorn Peter , Salman Adel
Published: November 2016

In the Sab'atayn Basin of Yemen hydrocarbons were generated from pre-salt Upper Jurassic source rocks during the Cenozoic and the salt provides the ultimate seal for the pre-salt and intra-salt traps. Therefore the proper understanding of salt tectonics is critical for ongoing hydrocarbon exploration efforts in the Sab'atayn Basin.

A variety of distinct salt tectonic features are present in the Sab'atayn Basin. Based on the regional interpretation of 2D seismic and locally available 3D seismic reflection data calibrated by exploration wells in the central part of the basin, an Upper Jurassic evaporite formation ("salt" from this point on) produced numerous salt rollers, pillows, reactive, flip-flop, active and falling diapirs.

Due to regional extension, halokinetics began by formation of salt rollers, as soon as the early Cretaceous, within just a few million years after the deposition of the Tithonian Sab'atayn Formation. The salt locally formed salt pillows which evolved to salt diapirs and diapiric salt walls as the result of renewed extension in the basin. As the result of a prominent extensional episode at the end of the Cretaceous most of the diapiric walls in the basin are controlled by large normal faults on their updip flanks. Some of the diapiric walls even evolved into falling diapirs due to ongoing extension. As the post-Cretaceous sedimentary cover is largely missing in the study area, the assumed reactivation of salt structures during the Cenozoic remains poorly constrained.

As the Sab'atayn Formation has typically several massive salt intervals in it, it defines post-, intra- and pre-salt play types in the basin. However, other than just providing traps and seals in the basin, salt tectonics is also very important for source rock maturation in the basin. As there are many salt diapirs in the study area, their cooling effect on the the pre-salt hydrocarbon kitchens appears to be quite significant, based on our preliminary basin modelling efforts.
Linking The Subsurface To The Surface Integrated Asset Modelling For A Super-Giant Oil Field To Optimize And Manage Production
Authors: Al-Jumah Ali , Doush Mohamad , Alharthy Said , Lalji Farhad
Published: November 2016

With limited and scarce subsurface and surface data, it becomes quite challenging to monitor a rather large field, having more than 50 wells actively producing, and actively optimize the production, achieving the desired production rates and maximizing the benefit for the operator and partners. The field in question was inherited from the previous operator, with 27 legacy wells, and a surface facility capable of processing ca. 100kbb/d of crude. Additional processing facility was installed to double the legacy capacity and 30 wells drilled by the time of preparing this paper for supplying the crude. The field had a shut-in period of 14 months in 2011-12 for various upgrades and surface works. It was then necessary to introduce an integrated modelling tool, to allow for a more efficient control and monitoring of the producing asset, combining all the components together and testing the interactions between the different system parts.

The Integrated Production System Model (IPSM) was built based on the principle of following the oil molecule from the pore throat to the export. As such, it comprises of three main components, linking the subsurface to the surface, those are: –Reservoir Models (built with Petex® MBAL©)–Well Models (built with Petex® PROSPER©)–Trunklines/Flowlines and Separators (built with Petex® GAP©)

Petroleum Experts® (Petex) develop the Integrated Production modelling software suite that comprises the tools mentioned above and are the company's proprietary. The current version of the IPSM is used in variety of situations; these include mainly but not limited to: ▪Medium Term Production Forecasting (MTPF)▪Production System Optimization (PSO)▪Opportunities assessment▪Identification of bottlenecks▪Further well scoping

The IPSM has facilitated the application of many processes, allowing for a faster and more informed decision making, these include: ▪Optimization: as required and identified in PSO Meetings, optimization activities are carried out as part of increasing the total system production output, which adds more value to this process▪MTPF: generated on a monthly basis, the MTPF clearly highlights the production pitfalls, and the expected targets with a given set of assumption, and honouring the constraints that exist in the system, allowing for proper future planning, and the need for well scoping studies and highlight of the requirements to meet the desirable targets▪Maturing opportunities and assessing their system gains and impact on system

This paper presents the process of building and maintaining an IPSM model throughout the different phases of a super giant field's life, from early production days with limited wells and data to the point of having real time data transferred to the office, fully utilizing the available data help make decisions that maximizes and eliminates waste.
High Temperature Cementing: Fluid Loss Control Polymers Performance and Limitations
Authors: Cadix A. , Wilson J. , Bzducha W. , Gomez J.-R. , Feuillette A. , Guichon H. , Thant K. , Nelson T.
Published: November 2016

Oil well cementing is a technically critical job and requires a well controlled placement along the wellbore and an even fill of the annular volume. As a consequence fluid loss control additives, preventing water from filtering into the formation are key ingredients of cement designs. These additives are often based on synthetic high molecular weight sulfonated copolymers.

The mechanism of action of these polymers has been studied recently and it was demonstrated that adsorption onto the cement surface is key to the achieve product performance. Unfortunately this adsorption yield is generally limited and typically performance decreases significantly as temperature increases. In order to overcome that loss, formulators typically increase loading to regain acceptable performance. Due to the high molecular weight nature of these AMPS copolymers, the subsequent drawback of increased loading is also an increase in cement slurry viscosity. In addition, as higher density slurries are typically used when downhole temperature increases, the problem is exacerbated and these limitations highlight the need for alternative technologies.

In this study we investigated the use of block copolymers comprising first a strong adsorbing block, then a long second hydrophilic block providing filtration control. This technology has already demonstrated to be very effective in preventing performance losses in presence of competitive formulation additives such as dispersant or retarders (see SPE173758). In this work, the behavior of such fluid loss additive is investigated in several cement grades and at elevated temperature.

Thanks to systematic methodology combining adsorption quantification with a standard HP/HT filtration, it is possible to quantify fluid loss polymer adsorption. This methodology using steric exclusion chromatography applies even in the case of complex formulations comprising retarders.

This work focuses on the analysis of the adsorption of fluid loss polymers on several cement grades and at elevated temperature.

Comparison of conventional copolymers and diblock copolymers show that conventional systems are very sensitive to cement grades even at moderate temperatures and gets very difficult to use above 100°C. On the other hand diblock copolymers are consistently performing at moderate temperature. Some potential performance limitation of this additive may occur at very high temperature if sulfate/aluminate balance of cement is such that ettringite thermal degradation can take place.
Fiber Optic Leak Detection FOLD Project
Authors: Baqué Marc
Published: November 2016

Fibre Optic Leak Detection (FOLD) Project

Recent news headline came to remind the dangers associated with gas transportation. Due to its asset size, pipelines are often the facilities the more difficult to protect in cases of an explosive gas leakage.

The objectives of the Fibre Optic Leak Detection (FOLD) project were to assess the capability of fibre optic sensing to detect a small gaseous leakage on a buried pipe, to give guidelines regarding the best deployment positions of the fibre along the pipe, to compare the performance of several methodologies and to assess the impact of the fibre optic length on the detection performance.

The strength of this project is to propose a representative test bench to help the industry to mature the detection methodologies: Gaseous leakages were performed from the external surface of a steel pipe with an internal diameter of 390 mm and a length of 30 m. These leakages were of methane, hydrogen or nitrogen and took place through different orifices (from 1 to 7 mm) and at varying released pressure (between 20 and 100 bar). This pipe and the optical cable were buried in a granular type soil compacted to a known level. Several types of interrogator (DTS - Distributed Temperature Sensor) from different suppliers were tested during the FOLD project.

The paper will present the experimental bench and the main results. Based on these results, it will be possible to conclude on the overall performance of the DTS technologies to detect a small gaseous leakage on a buried pipe, to give guidelines to optimise several parameters for improved detection performances: fibre optic position or deployment architecture along the pipe (directly buried or into a polyethylene tube), detection range assessment, equipment choice... Five different instrument suppliers took part in the initiative and delivered comprehensive data.

To make sure that detection will occur whatever the gaseous leakage flow rate on a buried pipe, it could be interesting to use both internal detection means (pressure or flowrate transducers placed at both ends) and external ones. Among the technologies available for external sensing, the optical fibre seems to be a promising candidate. This paper will present brand new data, collected in very controlled conditions, to assess the performance of such technology.

We will present the proportion of instruments capable of detecting leaks and the possible configurations presently recommended to pipeline designs in project phase.
Estimation of Relative Permeability from Laboratory Displacement Experiments Application of the Analytic Solution with Capillary Corrections
Authors: Deng Lichi , King Michael J.
Published: November 2016

Waterflood, or other forms of immiscible displacement, have been the most widely used mechanism for secondary recovery and the determination of individual phase's relative permeability has been crucial for many reservoir engineering applications. Traditionally there are two ways of determining the relative permeability from laboratory experiments: the steady state experiment and the unsteady state experiment. The steady state experiment has the disadvantages of being time-consuming, obtaining few points on the relative permeability curves, as well as not being identical to the true reservoir displcacement process. On the other hand, the Johnson-Bossler-Naumann (JBN) method, based on Buckley-Leverett (B-L) immiscible displacement theory, is the standard procedure used to determine relative permeability from unsteady state experiments. However, the neglect of capillary pressure effect in the Buckley-Leverett theory has placed limitations on the method, such as requiring high flow rates. In order to remove the limitations of the displacement experiments and give more flexibility to the experiment configuration, an analytic model with capillary corrections is presented in the context of viscous dominated flow to study the impact caused by capillarity. The solution shows a fixed water-oil saturation bank at the outlet whose magnitude depends upon the wettability of the system. The analytic model is able to predict the saturation profile, considering capillarity, under various rock and fluid properties and experimental configurations. Therefore, the model could be used to calculate accurate relative permeability by matching experimental pressure drop and production reponses, correcting for capillarity. Also, through this method, a dimensionless parameter could be provided to quantify the effect caused by capillary end effect based on the length scale affected. It reflects the influence from a variety of aspects, not only from the experimental settings.
Optimizing Seismic Survey Geometry with Blending Methods in a Transition Area
Authors: Ishiyama Tomohide , Ali Mohammed , Blacquiere Gerrit
Published: November 2016

Survey design should provide an efficient and practical survey geometry that meets the required survey parameters. Therefore, we have to seek an optimal geometry, taking survey productivity and constraints into consideration. In a transition area, the types of sources and receivers are various and mixed depending on the environment. They are independently deployed, allowing high flexibility in geometries with various roll and shooting patterns such as blending methods. In this paper, we tried to optimize the geometry with several shooting methods, maintaining the required parameters whilst enhancing the survey productivity. We will review and discuss the results of this case study.
An Evaluation Method of Snubbing Units in China
Authors: Liu He , Ming Eryang , Han Weiye , Li Tao , Li Yiliang , Pei Xiaohan , Sun Qiang , Huang Shouzhi
Published: November 2016

Since the popularizing of snubbing technique in China, a number of new types of snubbing units appeared in oil fields. Without new industrial standards, it was difficult for users to choose the exactly suitable units to fit into their conditions. Consequently, most units were inefficient and accompanied high maintenance cost. It is urgent to draft a rational selection reference for solving above problems.

This paper introduces an evaluation method on varied versatile snubbing units except those special units, including classification, rationales, characteristics, advantages & disadvantages, and costs. Based on investigation, by comparing rationales and analyzing structure characteristics, the snubbing units can be classified into several types. Advantages & disadvantages provide the comparisons of mobility, integration, theoretical efficiency and well site requirements. The cost evaluation which is composed of acquisition cost, operation cost and maintenance cost provides an economic effectiveness ranking among different types. According to these five aspects' comparisons, the rated ranges of use are provided.

According to this evaluation method, snubbing units in China are divided into 2 types, separated type and independent type, and subdivided into 5 subtypes. Normal rig-assistant type and single hydraulic power rig-assistant type belong to separated type. Rig-less type, vehicle-mounted integration type and hydraulic energy-storing service rig type belong to independent type. Each subtype associates with specific rationale and structure characteristics, and it is easy to identify by users. Furthermore, each subtype has unique level of mobility, integration, theoretical efficiency and well site requirements, which means that users have more accurate specifications to choose ideal snubbing units for their certain conditions. What is more, there is a cost evaluation to balance their budgets or anticipations before purchasing. For example, in the northeast of China, the well depth is average and it is a plain area. According to this method, mobility should be the main consideration in all matters. Therefore, vehicle-mounted integration type is highly recommended to the users from that area. However, in the southwest of China, because of the mountains, separated type is better. This selection reference is very convenient and effective for Chinese users.

The research result in this paper helps users, mainly, producers and managers to acquaint snubbing units' situations in China and to take advantage of that for better work performance. It promotes standardization of snubbing industry and has formed a new industrial standard. In addition, this result potentially improves the rate of capacity utilization which is particularly beneficial to petroleum industry.
Gerotor Pump Performance in Artificial Lift for Single-Phase and Multiphase Conditions
Authors: Ejim C. E. , Oshinowo L. , Xiao J.
Published: November 2016

Gerotors are positive displacement pumps and candidates for artificial lift in the oil and gas industry. This study evaluates the performance of a unique gerotor pump design under single and multiphase conditions in a downhole configuration. The gerotor pump performance is modeled with computational fluid dynamics (CFD) to develop a virtual prototype of the multiphase performance behavior prior to physical testing.

A prototype 3D model of a 400 series gerotor pump suitable for application in a 5½-in. casing was developed. The pump volume displacement is consistent between the initial laboratory experimental tests and future field testing. A transient 3D CFD was used to simulate the gerotor pump performance under single-phase and multiphase flow conditions. The complex gerotor motion was modeled in CFD using a dynamic meshing technique. Pump rotor speeds applicable to the range of testing conditions were applied. The gas and liquid phase properties correspond to mineral oil and air at the prototype test conditions.

The results of the gerotor pump performance are presented for single-phase and multiphase conditions over a range of gas volume fractions (GVFs) from zero to 0.75. The CFD results show that the flow rate decreases approximately linearly with discharge pressure, which is typical of positive displacement pumps. Pump performance and efficiency curves are developed relating the delivery pressure and flow rate. The CFD model methodology is presented with consideration to appropriate selection of the numerical methods, multiphase model, mesh design, dynamic mesh motion, and other aspects to improve the reliability of the numerical simulations. For the same delivery pressure, increasing the GVF decreases the gerotor pumping rates. Recommendations are proposed for improving the multiphase pumping capacity through pump geometry modifications. The modifications effectively tailor the gerotor to improving gas-liquid pumping in specific oil field operating conditions.

This study highlights the potential for gerotors as an alternative artificial lift technology for multiphase pumping. This technology with the inherent mechanical simplicity and compactness provides cost-effective surface and downhole multiphase pressure boosting for production in the oil and gas industry.
Introduction of 25mm-PDC Cutters in the Latest Drill Bit Technology Leads to Multiple Drilling Performance Records and Reduces Days to Production in Oman
Authors: Al-Hinaai Ahmed , Al Esry Saleh , Scott Dan E. , Fuselier Danielle , Lee Roger , Boisvenue Graham
Published: November 2016

Suppressed oil prices amid a call for increased returns from shareholders has created opportunities for operators and service companies to work closely in developing and deploying new technology in well construction efforts. Under extreme pressure, operators are seeking innovations to reduce drilling time and shorten the time to production. An operator in Oman has tripled output over the last ten years using enhanced oil recovery (EOR) methods, making it the largest independent oil producer in the Sultanate.

The development of polycrystalline diamond compacts (PDC) is one of the fastest-evolving technologies for fixed cutter drill bits. The application of PDC bits continues to expand performance by increasing rates of penetration (ROP) to lower drilling costs. The most recent developments in synthetic diamond cutters have been in 25mm-diameter cutters. Although 25mm-PDCs were developed in the mid-1990s, they lacked the necessary durability for demanding drilling applications. Only recently has the technology become available to meet these needs in this size.

Several recent tests in Oman have shown the new 25mm-cutter technology drastically improved performance with shoe-to-shoe runs at increased ROP. With the new cutters came the need for paired frame improvements with special considerations for aggressiveness and mechanical limitations for torque, both for the drilling rigs and use with positive displacement motors. During vertical drilling through carbonates and shales in the Diba field, the technology established a new field record ROP of 217 feet per hour—an 80% improvement over the field average ROP. In the Jalal field, 275 feet per hour was achieved—29% higher than the previous best record. The technology was also introduced on a steerable motor in a directional well, delivering improved penetration rates and excellent stability in slide mode. An additional lesson learned was the smooth torque generated by the large cutters. The smooth drilling torque enabled improved directional tool face control.

This operator has implemented an aggressive drilling and development program to drill faster and reduce cost per foot in heavy oil sands and fractured carbonates. The authors will present case studies to demonstrate how the latest technology 25mm-cutters and new frame technology helped lowered drilling costs for this operator's drilling program in Oman.
Nanotechnology Improves Wellbore Strengthening and Minimizes Differential Sticking Problems in Highly Depleted Formations
Authors: Al-Ajmi Abdullah M. , Al-Rushoud Abdulaziz S. , Gohain Ashis K. , Al-Haj Hussien A. , Khatib Faiz I. , Al-Mutawa Faisal M. , Al-Gharib Majed A. , Soliman Ahmed H. , Ibrahim Ahmed S. , Al-Mujalhem Manayer Q.
Published: November 2016

It is a challenge to drill in highly deviated or horizontal holes with high differential pressures. Wellbore instability, differential sticking and mud loss are frequently encountered problems while drilling slanted wells in Kuwait across shale and sand series. Drilling became more challenging with considerable non-productive time. Therefore, it is necessary to identify a fluids solution when other options with casing zone isolation are not viable. Traditionally, oil-based mud (OBM) was used while drilling these formations with limited success.

A customized fluid system was designed to overcome the issue of high overburden pressure in shale and sand series formations targeting effective bridging, minimizing pore pressure transmission, and strengthening the wellbore. A nano-size deformable synthetic polymer, along with sized calcium carbonate and graphite, was identified to effectively plug the pore throats and minimize fluid invasion, which was confirmed by particle plugging tests.

A well section was identified to comingle the highly depleted and pressurized formations. This was the first attempt on a high-angle well with development drilling operations in Kuwait and was performed to facilitate the successful drilling of the reservoir. Traditional OBM was converted to a customized fluid system using a nano-size polymer and sized bridging additives based on proprietary software selection and a series of laboratory tests. Drilling and logging were successfully performed for the first time in the commingled section without incident. There was no wellbore instability or differential sticking tendencies, less torque and drag, as well as enhanced wellbore cleaning in the high-angle sections.

This paper also presents some successful applications of the nano-size deformable polymer in OBM to drill highly depleted formations in HTHP wells managing up to 3500 psi overbalance across highly permeable formations.
Technological Improvements in OCTG Premium Casing Connections and Advancements in Design Paradigms to Address the Challenges Present During the Exploitation of Unconventional Hydrocarbon Resources: A Critical Review
Authors: Meza O. Grijalva , Berdasco J. Holzmann , Baptista N. Perozo , Carvajal C. Paz , Oppelt J.
Published: November 2016

Well Integrity is one of the most critical topics concerning the E&P sector nowadays, especially during the development of unconventional hydrocarbon resources. Among them, the exploitation of natural gas from shale and hydrocarbons from deepwater reservoirs pose considerable challenges to the entire well system, specifically in one of its more critical elements: the threaded connection. In the current state of the art, Premium Connections are the best option for ensuring wellbore integrity and mechanical reliability. Despite of its proven improved capabilities compared with standard API Casing connectors, Premium Connections are still relegated to "special applications".

In the case of offshore drilling, and in the light of new drilling techniques to develop deepwater resources, the use of Premium Connections to drill with casing tubulars offshore Australia has demonstrated the great opportunity this type of connection has for deepwater developments. In this work, a brief historical overview will be given addressing the technological highlights that contributed to the current market offer of OCTG specialty connectors for unconventional oil and gas applications. By means of a comparative, however, detailed analysis of available geometric profiles on the market in the last 15 years (ie. improved dovetail thread, coupling bevel, toroidal sealing surfaces, etc.) and the current state of the art of applicable norms, standards and their validation levels (Connection Application Level (CAL)) it was concluded that an additional improvement on the mechanical reliability of the connection still can be achieved. This would be noticeable in form of gas-tighter connections as per ISO 13679 and bigger torque capabilities (e.g. for casing drilling) during make and break operations.

Parallel to this, a new definition for "well integrity" is provided considering the role threaded connections play as critical innate safety barriers within the wellbore system; an extensive discussion on historical development of Premium Connections is provided, focusing in the innovations that took place in the last 15 years in OCTG for Shale Gas applications and Deepwater Drilling, at the same time the current state of the art of norms and standards for OCTG is critically cited.
Maximizing Completion Efficiency Using Remotely Operated Barrier Valves
Authors: Thomson Barry , Arackakudiyil Zac Suresh , Todd James
Published: November 2016

The paper introduces an application of intelligent completions that uses remotely operated barrier valves to improve completion efficiency. The case study outlines the completion of a well in the UK North Sea. The valves were used to set the packer and to test tubing; later, they functioned as shallow and deep-set barriers for the removal of the blowout preventer (BOP) and the installation of the christmas tree.

The well was completed with two barrier valves deployed in the open position; one was installed for use as a shallow-set barrier above the safety valve and the other as a deep-set barrier below the production packer. The valves used onboard decision-making electronics that monitor well conditions and that are programmed to open or close in response to the detection of a specified condition (known as a trigger). This configuration enabled the operator to communicate with the tool remotely from the surface by using applied-pressure commands. The use of remotely operated barrier valves made it possible to open and close the barriers multiple times.

The deep-set valve was initially closed to set the packer and test the tubing string. It was later opened to test the packer on the annular side, and it was closed to act as a deep-set barrier. The shallow-set valve was later closed to act as a second barrier to enable the removal of the BOP and the installation of the christmas tree. Both valves were then remotely opened to begin production.

The use of remotely operated barrier valves helped the operator to successfully eliminate eight wireline runs, which resulted in the elimination of approximately 59 hours of rig time. The health, safety, and environment (HSE) risks associated with rigging up and running wireline were also eliminated in this case.

The industry is striving to perform completions and intervention activities in a safer and more economic manner. This case study demonstrates the new use of remotely operated barrier valves will provide a timely addition to existing completion solutions.
Utilizing Pulsed Eddy Current to Inspect Insulated Piping
Authors: Sayed Talal Al , Hammadi Hassan Al , Yaarubi Ameer Al , Harmi Faisal Al
Published: November 2016

A wide range of Oil & Gas plants is subjected to periodic inservice inspection in order to ensure continued safe and economic operation. The catastrophic failure of a component in a process plant may result in costly business interruption and also it endangers plant personnel. If an explosion or fire occurs, or a hazardous chemical is released widespread fatalities or undesirable environmental consequencies may result. Premature failure of plants can hapeen as a result of variety of different causes, and these include design deficiencies, manufacturing defects, fabrication or erection defects, service related deterioration and operating deficiencies. In order to prevent the sudden upset and resultant catastrophic failures, regular inspections most suitable for the anticipatory failures has to be identified and executed. The inspections are often performed by traditional NDT methods such as Radiographic testing and ultrasonic testing. These can be highly sensitive, but the rate of coverage is relatively very low and extensive preparation for inspection often required, eg. Like insulation removal or composite wraping removal often required for the inspection of substrate. There are also many situations where access or geometry prevents the use of conventional inspection methods.

Over recent years a wide range of advanced NDT technques has evolved. These techniques provide large area screening of a component for significant degradation. Some of the techniques can be rapidly applied and they also provide means of inspecting areas which would be uninspectable. PEC or pulsed eddy current is one among this and this inspection technique is most suitable and best approach for insulated and composite wrapping applied section of piping.

ZK site have many critical piping components applied with pressure / non pressure containment composite wrapping and the recent survey on these piping concluded many affected by corrosion under wrapping. PEC inspection is a solution for the inspection and condition monitoring of substrate under the wrapping, and which has proven and established.
Mitigating Water Injectivity Decline in Tight Carbonates due to Suspended Particles
Authors: Alyan Mohand , Al Tamimi Mohamed , Al Zinati Osama , Calarasu Dan , Martin John , Irwin Drew
Published: November 2016

This paper is a comprehensive analytic driven study on the use and sizing of membrane filters to improve the injected water quality for maintaining injectivity in tight carbonate reservoirs. Out of the different mechanisms of formation damage, the pore plugging with the migration of particles within the injectant fluids by bridging at the pore throat junctions and/or by pore filling can lead to the buildup of an internal filter cake away from the wellbore that limits the well’s injectivity and can affect the vertical and lateral sweep.

This type of formation damage is very difficult to treat with any kind of stimulation and the impact will be manifested especially in tight formations with interbedded stylolites layers with a total range of permeabilities from 2 to less than 1 milli-Darcy and a median pore throat size ranging from 2.5 to 0.3 micron meters. The study comprises several parts starting with a geological analysis that was conducted to identify areas and layers most prone to formation pore plugging by analyzing thin-sections and MICP data. Second, in the lack of core flood tests, a reservoir and well study analyzed existing water injectors situated in similar or slightly higher quality rock areas through the analysis of injectivity index behavior to estimate the impact of damage and the expected injector’s half-life.

As a result, through the application of an analytical mathematical model for defining deep bed filtration parameter, a correlation was established based on average injected particle size and reservoir rock quality to aid in selecting the proper water injection filter size. In order to confirm that, a dedicated injectivity test in a horizontal well utilizing membrane filters was carried out to assess eventual formation damage and the filters efficiency by conducting a series of multiple pressure fall-off tests coupled with injection profile logging to monitor any induced damage within the wellbore region.

Finally, the operational aspects and the integration within field development plans were addressed, especially with the recommended well placement and completion. This culminated in a field development strategy for formation damage mitigation in tight carbonate reservoirs during production and injection phase that can be used in other similar fields.
Achieving Predictable Outcomes for Modular Construction in Megaprojects
Authors: Jeffers John
Published: November 2016

Megaproject definition: A capital investment project with a total installed cost in excess of $1 billion USD with complex stakeholder arrangements.

Rystad Energy estimates that global capital expenditure in oil and gasfields dropped $215bn between 2014 and 2015, shaving almost 0.3% off the size of the global economy. That trend continues in this low oil price environment. The effects of volatile and low oil prices vary along the value chain and are most acutely felt upstream with all national oil companies (NOCs) and international oil companies (IOCs) revising their capital investment schemes downwards.

As the number and size of megaprojects continues to increase across all sectors of the capital projects industry, one fact stands out: megaprojects tend to underperform more often than not. More specifically, megaprojects fail to keep within their approved budgets, fail to meet their approved schedules, or fail to achieve their promised business objectives. To provide substance to this assertion, independent and empirical studies (by Ernst & Young and the I.P.A.) point out that the sector record in executing major oil and gas projects is far from palatable. Approximately 64% exceed their control budget and over 70% experience schedule delays. It is therefore necessary for the oil and gas industry to examine the underlying reasons for this disappointing failure in order to achieve predictable outcomes on investments.
Acoustic Downhole Three-Phase Separation Method in Oil Field Applications
Authors: Abdel-Fattah Amr I.
Published: November 2016

The need for downhole oil-water separation systems increases with the rising water cuts in producing wells worldwide. This need is driven by the urge to reduce costs and environmental risks associated with managing and treating the expected large volumes of produced water. Available technologies utilize hydrodynamic, gravitational, or membrane separation techniques to separate oil from water downhole. They suffer from a number of systemic problems, including flow intervention and possible subsequent pressure drop in the well and failure of mechanical parts. They require a specific range of flow rates and water cut percentages in order to function properly. If well conditions deviate from these operational ranges, partial or complete failure of function is the result, unless some system parts are replaced, which in turn may require costly workover and temporary shutdown. Existing technologies are also incapable of separating fine solids from the fluid stream downhole, and thus run the risk of clogging the formation zones in which the water is reinjected. Acoustic separation techniques provide a viable solution to these limitations and add a number of advantageous functions. In this article, a concept for an Acoustic Downhole Oil Water Separation (ADOWS) tool and its field implementation is introduced. ADOWS is a three-phase separation concept in which both oil droplets and solid fine particles are separated downhole simultaneously from water. Oil is directed to the surface and water is allowed to enter a cavity equipped with a membrane to remove the already-separated particles before reinjecting the water back into the formation. ADOWS thus has the potential of not only increasing oil-to-water ratio and reducing produced water pumped to the surface, but also removing fine particles from the water so it can be reinjected into the formation without the risk of pore clogging. ADOWS is versatile, does not intervene the flow, and does not require narrow ranges of flow rates or water cuts to function properly. The underlying acoustic separation forces can be tuned instantaneously via surface controls to accommodate changes in flow rates and water cuts. Direct microscopic visualization experiments in a microfluidic channel demonstrate the key phenomena underlying ADOWS. The experiments show simultaneous separation of micron-sized oil droplets and solid particles from water by exciting the proper acoustic standing wave patterns in the flow channel.
A Multiscale Pore Network Modelling of Gas Flow in the Nano-Porous Structure of Shale
Authors: Yuan Yudong , Wang Yuzhu , Rahman Sheik S.
Published: November 2016

Flow simulation in shale is challenging due to its multiscale porous structure and multi-physics gas flow in these pores. Because network of pores is capable of characterizing the three dimensional (3D) distribution of pores and throats, it is widely used to estimate the apparent gas permeability of porous media, such as shale. Pores residing in shale have a broad spectrum of size ranging from a few nanometers to micrometers, therefore, multiple flow regimes, including the continuum flow, slip flow, transition flow and sometimes Knudsen diffusion are controlling the flow in the porous structure of shale. In addition, surface diffusion occurs on the adsorption layer of organic matters also contributes to the total flow rate. For the network modelling in the literature, the employed equaitons fail to account for these flow mechanisms. In view of this, Beskok and Karniadakis (1999)’s equation and Fick’s equation are employed to describe the non-continuum flow and surface diffusion, respectively, in a reconstructed network of shale. The simulation results provide an improved understanding of gas flow behaviour in shale matrix. It has been observed that the apparent gas permeability increases by a factor of 2.4, with 21% contribution arising from surface diffusion when the downstream pressure depletes from 9 MPa to 2 MPa. Sensitivity analyses imply that the apparent gas permeability is dependent on the size and shape of throats, compressibility factor and type of gas, Langmuir adsorption parameters and reservoir conditions.
New Steel Plate for LNG Storage Tank
Authors: Kagaya T. , Furuya H. , Kamo T. , Takahashi Y. , Wakamatsu H. , Nagao T. , Nishigami H. , Tomita S. , Hirai S. , Mitsumoto M.
Published: November 2016

Due to the demands for expanding liquefied natural gas (LNG), an increase in LNG storage tank constructions is now expected. For over 50 years, 9%Ni steel with excellent mechanical properties at a cryogenic temperature under -162°C has been used as inner-tank material for LNG storage tanks. As nickel is an expensive and a rare metal, a reduction of the nickel content in steel can save construction costs of LNG storage tanks.

A new steel plate for LNG storage tanks has been developed by optimizing the chemical composition and applying the latest thermomechanical control process (TMCP) technology. TMCP is a production process wherein the rolling temperature and cooling rate after rolling are controlled, thereby enabling the refining of the microstructure. For the application of the new steel to LNG storage tanks, the brittle crack initiation properties and propagation properties of the base plate and welded joint were analyzed.

The new steel has a finer microstructure and larger amount of retained austenite than conventional 9%Ni steel. It was demonstrated through various large-scale fracture tests that the new steel has excellent performance equivalent to conventional 9%Ni steel. The new steel plate (7.0%–7.5%Ni) has already been adopted in an aboveground LNG storage tank in Senboku Terminal 1 of Osaka Gas Corporation. This tank, which has a capacity of 230,000 m3 and is the largest of its kind in the world, was constructed in November 2015. It was confirmed that weldability and formability of new steel in the construction of LNG storage tanks are also equivalent to 9%Ni steel. The LNG storage tank has been safely operating till this day.

The newly developed steel (6.0%-7.5%Ni) was standardized in JIS, ASTM, ASME, and API. Furthermore, in addition to Class 9 of ASTM, Class 10 having higher strength was specified. The new steel can be used in LNG storage tanks all over the world.