bluuebunny/crossref_metadata_2025 huggingface dataset:
Project Knowledge Harvesting: The Case of Improving Project Performance through Project Knowledge Sharing Framework
Authors: Al-Awadhi Rima , Tharayil Abdul Jaleel
Published: November 2018

Driven by KOC 2040 strategy, the process integrated approach to project knowledge sharing is evolving to be the knowledge-sharing model in KOC. It integrates with various organizational process and policies such as Project Gate System and Performance Excellence and Change Management. KOC is one of the largest crude oil exporter in the world, and managing highly complex multi-million dollar projects over the last 80 years. Therefore, managing critical project knowledge is vital to the success of the project and the organization. However, due to the very nature and complexity involved, each project engagement generates a lot of ‘learnings’ that need to be factored into while new projects are initiated and thus avoid repeating the same mistake. Nevertheless, many a time these learnings are localized and remains as ‘tacit knowledge’ leading to scope re-work, schedule overrun, adjustment orders and claims. While KOC follows an asset based organization structure, with a multi-cultural and multi-ethnic workforce and larger chunk of the work is carried out through complex, long term project engagement, diffusion of ‘learnings’ across assets while dealing with the natural entropy of the organization is of great significance. The project knowledge harvesting through process-integrated approach encompasses knowledge assessment and prioritization, knowledge mapping and classification, user engagement, branding and communication, knowledge exchange with service providers, quality control through collaborative review and publishing process including a quick demonstration of the lessons learnt sharing & reuse platform.
A Biomarker and Isotopic Study of the Source Rock Organofacies, Oil Families, Source-oil Correlation and Thermal Maturity of Cenomanian Petroleum Systems in the Offshore Abu Dhabi
Authors: Amo Miki , Taniwaki Takash , Yamanaka Motoyoshi , Kato Ayato , Shinbo Emiko , Shibuya Setsuko
Published: November 2018

Crude oils and rock samples from Cenomanian carbonate oil field (Field A) in the offshore Abu Dhabi were investigated in order to define oil families, paleoenvironment, origin of organic materials and thermal maturity because the origin of crude oils and their thermal history in this field has not been understood well. Especially, maturity profile in this area has not been determined yet because the source rocks don't contain enough amount of vitrinite due to the dominance of marine organic matters. Field A has two culminations above OWC: North structure and South structure. Therefore, we investigated oils from both structures to figure out the geochemical features of each culmination. The Cenomanian carbonate rocks of Field A are composed of shallow marine porous limestone (reservoir rocks) and deep marine lime mudstone (seal rocks and source rocks). Saturated biomarkers (n-alkanes, isoprenoids, steranes and triterpanes) of crude oils from shallow marine porous limestone and core samples from deep marine lime mudstone were determined using gas chromatography-mass spectrometry (GC/MS), gas chromatography-mass spectrometry-mass spectrometry (GC/MS/MS) and gas chromatography-combustion-isotope ratio mass spectrometry (GC/C/IRMS). Ternary diagrams of C27-C29 steranes of all oil samples and core samples show significant similarity among crude oils and source rocks in Cenomanian age. High amount of C30 sterane and the ratio of C27-C29 steranes suggest that the crude oils were generated from Cenomanian marine source rocks. Biomarker maturity parameters such as Ts to Tm ratio and diasterane (Dia) to regular sterane ratio (Reg) were slightly different among the crude oils. The crude oils from South structure were slightly more maturated than those from North structure. The stable carbon isotopic values of individual n-alkanes in the crude oil would be classified into two crude oil families: dominance of lighter carbon in North structure and relatively heavier carbon in South structure. These results were consistent with the results of biomarker maturity parameters such as Ts/(Ts + Tm) and Dia/(Dia + Reg). Thus it was confirmed that the crude oils of North structure and South structure were from same Cenomanian source rock, however, thermal maturity of the crude oils were slightly different between North structure and South structure.
Wireline Tractor Conveyance - A Technology Game Changer for the Gulf of Thailand
Authors: Jongnarungsin Sarunya , Puttisounthorn Toon
Published: November 2018

Easy oil is no longer low hanging fruit for oil and gas operators, and drilling targets are becoming increasingly ambitious, which results in escalation of the well trajectory complexity. This accordingly spirals the well and completion costs. To overcome this situation, technology must play a role to reduce cost, increase efficiency and ensure safety at all times. Conveyance is the key for any data acquisition and well completion activities. Historically, conveyance methods for data acquisition and perforation in highly deviated or horizontal wells required drill pipe or coiled-tubing methods. These methods are time consuming, labor intensive, require a larger equipment footprint, with possible HSE risks involved. Mubadala Petroleum in Thailand has seen a significant increase in horizontal and high deviated wells over the past few years. The wireline tractor technology has been used for the first time in Mubadala Petroleum's Thailand operations during the drilling, initial completion and workover intervention operations, and it has been a game changer for Mubadala Petroleum in Thailand in terms of reducing rig time, well cost, and most importantly minimizing the HSE risks.

Over the past few decades, the oil and gas industry has developed the technique of drilling horizontally through the reservoir to maximize the surface contact area of the reservoir, to gain higher recovery and production. However, one downside from this technique is that it has become challenging and costly to perforate or to obtain measurements in this horizontal environment, as gravity will no longer support the wireline tools to reach to the bottom of the well. Wireline Tractor technology has played an important role to overcome this challenge. It reduces time, cost and will improve data quality as well as increase wellbore coverage. The wireline tractor functions with an electric over hydraulic power relationship, using its drive/wheel sections to push the passenger tool downhole as the cable is spooled off the unit allowing the tool to reach the end of horizontal or deviated wells without deploying drill pipe or coiled tubing conveyance methods. With this principle, any job that is typically run on electric wireline in a vertical well can be efficiently done in a horizontal or deviated well using wireline tractor.

Material presented in the paper will be from actual operations, examples being tractor conveyed wireline logging tool and 4.5in Outer Diameter (OD) 90 ft heavy long perforation gun in single tractor operations. It will also display the operational efficiencies increases and risk reduction being obtained.
A Breakthrough in Extended Reach Drilling by Introduction of a Redesigned Drill Pipe Connection
Authors: Kvalvaag Edvin , Frigui Mejdi , Al Hajeri Mohamed , Awad Ahmed , De Roffignac Geoffry , Lafuente Marta , Carrois Fabien , Sissenov Olzhas
Published: November 2018

A world leading ERD project was required to make a step change in drilling performance to reduce the well construction duration. An opportunity was identified to minimize invisible lost time due to handling a tapered string combing two sizes of drill pipe.

The objective was to design and successfully run a new uniformed string, based on a fit-for-purpose slim drill pipe concept which is intended to offer an unprecedented robust and ultrahigh torque connection.

Following an initial analysis of the drilling requirements in terms of torque, dimensions, tensile capacity and hydraulics, it was rapidly identified that the process limiter was the drill pipe connection as no option available in the market could meet the redesigned project requirements. A thorough assessment of the tool joint characteristics was performed to identify the upgrade(s) that will maximize the connection capacity and performance. As a result, the R&D team of a manufacturer was brought onboard to design the new thread that will enable the operation as planned. The new design would then be validated through shop stress tests and field trials with actual pipe.

A new thread model was developed and allowed the design of drill pipe that had a reduced tool joint OD that would allow for a lower annular pressure drop and fishability in the 8 ½" hole. The tool joint provided an increased torque capacity up to 70,000 ft-lbs while still meeting the operating mandates of minimized handling and maintenance requirements. The newly designed drill pipe successfully passed the shop stress tests and was mobilized for operations. The drill pipe completed an entire well consisting of three sections (16", 12 ¼" and 8 ½") within the tight hydraulic window of such ERD wells further validating the original drilling simulation parameters. The post job drill pipe inspection confirmed that wear and tear were within current benchmarks. Furthermore, subsequent analysis showed that the connections make and break duration was better than the average experienced rates on the same rig.

In addition to the technical capability of the new drill pipe, the introduction of a single size string reduced the drill pipe inventory by approximately 20% and saved close to 7 days of rig operating time on the well.

This paper will present the framework used to foster innovation and the cooperation between the E&P company drilling team and the drill pipe manufacturer's R&D group. It will detail the fast-tracked introduction of a new design of drill pipe with an innovative thread type which seeks to combine efficiency, reliability and unparalleled torque capacity, in order to extend the drill string torque technical limit with the potential to revolutionize the ERD industry.
Kinetics Study of Iron Sulfide Scale Dissolution
Authors: Aljeban Norah , Chen Tao , Balharth Salem
Published: November 2018

Iron Sulfide deposition in production facilities is one of the flow assurance issues in oil and gas industry. It can cause tubing blockage, interfere well intervention, and reduce production in both sour oil and gas wells. Mechanical descaling is currently applied, but it is time consuming and costly. Dissolvers based on concentrated hydrochloric (HCl) acid have high dissolving power, but with a limited applicability due to overwhelming drawbacks such as corrosion and H2S generation. Low corrosive, non-acid chemical dissolvers were developed. However, the dissolution rate is low and is not comparable to concentrated hydrochloric (HCl) acid performance.

Following the development of the iron sulfide dissolver presented in ADIPEC 2017, this work focuses on the improvement of the kinetics of iron sulfide dissolution, the kinetic factors of the dissolution rate. The non-acidic iron sulfide dissolver was used in lab dissolution tests. The effect of dissolution temperature, particle size, agitation, and ratio of volume of dissolver and mass of scale, were studied. Scale dissolution tests at temperature between 40°C and 125°C were carried out to evaluate the dissolution rate of pyrrhotite scale particles of sizes between 10 and 80 mesh. The ratios of volume (ml) of dissolver and scale particles (gram) were tested from 10:2 to 20:1. The agitation was from static to 160 rpm. The tests lasted for 6 hours. The dissolving amount was calculated by weight difference between the initial and final solids.

The results show that the kinetics of pyrrhotite dissolution can improve significantly at high temperature due to the increase in the thermodynamic of dissolution, and by reducing the particle size to increase the contact surface area of scale particles. The increase of volume ratio of dissolver with the mass of scale particles and increasing agitation have limited effect on the kinetics of scale dissolution under the test conditions.

This study provides and ranks the kinetic factors for iron sulfide dissolution. It gives a guideline to improve iron sulfide dissolution during field application using non-acid based iron sulfide scale dissolver.
Piping Motion Solutions-Ball Joint Technology
Authors: Chase Arlene
Published: November 2018

Objective

Inform and educate oil and gas pipe engineers of the safe and reliable solutions to pipe motion at high pressures. Expansion joints for Axial and Offset technology pipe systems. Ball joint designs in the offset and scissor installations for Offshore, Onshore, Production, Development and Distribution pipe systems.

Axial and Offset Pipe system technology and what are the advantages? How are expansion joints installed? What is a ball joint and how do they work? How to model expansion joints in a pipe stress program?

Ball joints are not new. Barco Ball joints have been around since 1908. The designs were developed to ensure steam could reach the front of a train from the boiler in the back across each car connection. The Steam piping made the passenger cars warm and comfortable. Today, Ball Joints provide a method of absorbing pipe movement for applications ranging to high pressures, steam and hot water pipe expansion, tank and building settlement, seismic isolation, wave motion compensation on oil platforms, barges, FPSO and drilling ships, solar panel movement, oil well riser expansion and safety relief valve escape piping.
Continuous Improvement of Hybrid-Solvent Solutions through a Smarter Formulation
Authors: Langé Stefano , Zhao Jing , Cadours Renaud , Weiss Claire , Bernadet Mikael , Caetano Michel , Layellon Lise
Published: November 2018

This paper presents how the optimization of the solvent composition provides significant OPEX reduction and simplifies process management.

Removing mercaptans from natural gas is becoming a tough work for operating companies due to the tightening of commercial specifications for sulfur-containing molecules in the final products. Beside this, about 40% of the known gas reserves are sour; some of them contain H2S and mercaptans. To commercialize these gas fields in a profitable way, smart process solutions focused on energy efficiency are needed. Classical gas sweetening units are based on chemical absorption by means of aqueous alkanolamines to remove CO2 and H2S from natural gas. These solvents have limited mercaptans removal capacity, requiring supplementary removal processes. This has a negative impact on the overall gas processing costs.

To face this challenge, TOTAL has developed a new series of hybrid solvents able to remove, in a one- step operation, CO2, H2S and mercaptans. Process performances can be improved without plant modification. The first solvent formulation was based on DiEthanolAmine (DEA) and was implemented in the sweetening units of the Lacq plant (France), demonstrating the benefits of the new hybrid solvents at industrial scale.

DEA solvent is a widely used and easy-to operate/monitor solvent. However, DEA has the drawback to be sensitive to chemical and thermal degradation. Moreover, DEA regeneration is quite energy demanding.

To overcome these problems, the amine components have been changed. The choice of new components is driven by following characteristics: good solvent stability, low regeneration energy demand, high CO2 and H2S removal efficiency.

A mixture of MethylDiEthanolamine and Piperazine (MDEA+PZ) has been adopted as the solution to replace the DEA based solvent. The choice has been made thanks to the good chemical stability of MDEA and the high performance of PZ as an activator to boost the rate of the absorption process.

This paper presents the operational feedback with this new formulation. The first benefit of the hybrid solvent formulated with MDEA+PZ is that it was implemented in the existing unit without plant modification. Other advantage is the improved chemical and thermal stability. This solvent swap allows to decrease the reboiler duty of the solvent regeneration, to reduce the chemicals consumption, while keeping the final product quality unchanged.

The benefits of the solvent swap will be supported by operating data collected before and after the solvent swap.
Attaining Technical Excellence in Project-Based Organisations through Multidisciplinary Knowledge Management Strategies and Tools to Improve the Transfer, Application and Reuse of Critical Knowledge
Authors: Weightman Janine , Curson Nigel
Published: November 2018

In these lean times, many organisations are considering investing in custom knowledge management (KM) strategies and enabling technologies to drive sustainable and enhanced business performance to reclaim or redefine their competitive advantage. The financial squeeze, movement of employees, and pressure to meet challenging customer requirements in the aftermath of Oil and Gas industry consolidation has effectively curtailed an organisation's ability to compete with financial advantages, retain critical knowledge and demanded increased agility in terms of delivering competence and services to tighter budgets. The changing face of competitive advantage in an increasingly technological and economically challenging world has directed organisations to look within to exploit their knowledge as a resource for innovation and sustainability. Success depends on how organisations have nurtured their differentiating knowledge.

It is imperative to rewire industry thinking around a subject that has been misrepresented as a voluntary business strategy. Such thinking has been detrimental to the intellectual health of organisations and the individuals that sustain it. This paper presents a resourceful approach to rescue or advance a KM strategy so that knowledge is created and transferred within the flow of work by ‘hiding KM in plain sight'.

Penspen's 8-point KM strategy and model for knowledge creation is a pragmatic approach to improve the transfer, application and reuse of critical knowledge in an organisation where the pressure of meeting project deadlines is always at odds with the imperative to manage knowledge. The discussion around personal knowledge capital and social capital seeks to sober up the reader's mind to the human and technological element of knowledge creation inside managed organisational environments. Insight into the tangible connection between knowledge creation and competitive advantage is offered, and how this is realised through a custom multidisciplinary approach that can elevate the maturity of a KM strategy. Recommendations and insights are provided as intervention strategies, which should appeal to organisations that have either limited KM resources, limited time to leverage critical knowledge or present lower levels of KM readiness.
Key Successful Factors in Deep Water Development - Eni Experience in West Africa
Authors: Lamberti Andrea , Colombi Nazzarena , Calderoni Mirko , Bombaci Fabio , Castelnuovo Luca , Crema Giordano
Published: November 2018

2018 will be the brightest year for upstream investment since 2014. Costs reduction and the oil price stabilization gives operators confidence in launching new challenging projects.

However, launching new projects is still particularly challenging for deep-water assets. Even if project costs are 20% lower than mid-2014, deep-water projects are not yet competitive with tight oil, considering also the higher associated uncertainty.

The direction to improve is clear: further cost cuts, through leaner development principles and improved well designs. Moreover, operators have to take advantage from lesson learned of projects already in production.

Eni has consolidated on its West Africa deep-water assets a workflow that can support challenging projects FID through: Reduction of time to market parallelizing project phasesManagement of project uncertainty through flexibilityWork in integrated teams taking advantage from digital transformation

More in details, the first target is to reduce time to market anticipating free cash flow generation. This is achieved through an appraisal while developing phase: drilling appraisal as first wells of development campaign, derisking the following well locations. Time-to-market reduction is achieved by parallelizing development phases, starting development plan definition during exploration phases and anticipating procurement of long lead items.

This is possible if subsurface uncertainty has been properly defined through robust 3D models and if projects can guarantee the flexibility to capture new opportunities: fine tune well locations during drilling campaign, keep spare slots availability and sidetrack opportunities, substitute water and gas injectors with water alternate gas wells (WAG).

In addition, Digital Transformation offers more and more the possibility to continuously update 3D models thanks to the availability of real time data, run thousands of simulations on super computers and monitor in real time field performance, taking advantage from simple daily operations.

This work is aimed to describe the steps that were the key successful factors of Eni operated deep water projects in West Africa. The presented workflow can now be considered a standard approach for the most challenging Eni's projects and supported the company to reach record time-to-market for the execution of challenging deep-water projects in the range of 2,5 to 4 years from authorization to first oil.
Impact of Stray Capacitance on Long Control Cable
Authors: El Sadani Mohamed , Sorin Pavel lonut , Somasundaram Sivanantham , Krishnasamy Suresh , Al Menhali Fahed
Published: November 2018

The objective of this paper is to share the RCA (Root Cause Analysis) of the power failure incident of 11kV substation fed from upstream 33kV SWGR through 2 nos. 33/11kV transformers at Company operating Plant.

Both interconnecting 33/11kV transformers tripped simultaneously causing black out of certain process train at the plant. However, all other downstream substations fed from the same 33kV SWGR did not trip

Maintenance team performed preliminary investigation and found that event records of protection relays of both 33kV outgoing feeders indicated that downstream 11kV incomers were racked-out.

Since, no physical rack out of both 11kV incomers, and after quick review of the relevant schematics, it was thought that simultaneous tripping could be attributed to mal-operation of Arc flash flap Switch at incomer/coupler circuit breakers of 11 KV Switchboard.

As such, in order to restore the power supply and resume production, the following has been made: Switchgear cubicles along with VT and circuit breakers compartments were inspected and cleared from major findings.TC (Temporary Concession form) had been filled and Risk Assessed to temporary disable Arc flash flap Switch at incomer/coupler circuit breakers of downstream 11 KV SWGR – till further investigation.

Finally, 11KV Power supply was restored after approximately 2 hours.

Company formed investigation team lead by the author of this paper to find out the root cause, which is concluded as follows: This particular 11kV substation among all other substations is 1500 meter far from main upstream 33kV substation. As such, the interconnecting control cable is long enough to carry undesired stray voltage due to well-known phenomena of capacitive effect.11kV CB rake-out trip signal was directly wired to upstream outgoing CB protection relay and powered from 110VDC control voltage of upstream substation. Due to long distance, stray voltage of 15VDC was measured in the cable but it was not enough to trigger the trip signal until 110V DC system disturbance took place causing enough stray voltage above 25VDC (experimentally verified) to initiate the trip.Nevertheless, why other substation did not trip even though all of their 33kV outgoing feeders are tapped from the same affected110VDC source? This is what we will explain in the next pages.
CO2 Sequestration Optimization in Aquifers While Considering Thermal and Geochemical Effects
Authors: Temizel Cenk , Abdullayev Azer , Kedia Rachit , Chhabra Sameer
Published: November 2018

One method of reducing the recognized threat of global warming is using continued sequestration of anthropogenic "greenhouse gases," such as carbon dioxide (CO2). Sedimentary basins are present globally and, because of the omnipresent nature of deep, regional-scale aquifers within them, they can be considered as potential sites for disposal and sequestration of CO2. Successful implementation requires identifying and considering fundamental concepts to help ensure that CO2 is stored in the aquifers effectively. The ideal scenario involves migrating CO2 from injection wells to remote storage sites using the aquifer, helping ensure its isolation from the atmosphere for a considerable length of time. In addition to the scientific and technical aspects of sequestration research, the practicality of the concept should be considered, including evaluating the maximum possible volume of CO2 that can be stored at global and regional levels as well as the safety and economic feasibility of the process. This study discusses examples to help provide an in-depth, practical understanding of this concept.

The study combines a full-physics commercial simulator with an effective uncertainty and optimization tool. The sequestration phenomenon is then modeled to investigate the significance and effect of the essential parameters on well performance while also considering thermal and geochemical effects. The process assesses the injection of CO2 containing tracers for 25 years, followed by shutting in the injectors and modeling the status of CO2 for the next 225 years. While CO2 is injected into an aquifer, the molecular diffusion of CO2 in water is modeled. The modeling of the thermal effects attributable to the injection of CO2 is important because the chemical equilibrium constants have a functional thermal dependency.

For reservoir management, the evaluation and effective management of uncertainties are as important as managing the well-level parameters. For this study, essential reservoir and well parameters are identified, and sensitivity and optimization processes are performed on them; the tornado charts in this paper illustrate the significance and effect of each parameter. Thermal and geochemical effects are shown to play vital roles in the sequestration process.

This study outlines the significance of essential parameters associated with the overall success of the CO2 sequestration in aquifers using in-depth uncertainty and optimization analysis, and it considers the influence of thermal and geochemical effects.
Assessment of Condensate Recovery Improvement Through Gas and Water Injection: A Case Study for a Large Heavily Depleted Very Rich Gas Condensate Field in the Sultanate of Oman
Authors: Cobanoglu M. , Shukri I. , Omairi R.
Published: November 2018

The Barik Deep clastic gas reservoir was discovered in 1991 and has been on production since 1994. It is a very rich gas condensate reservoir with initial Condensate to Gas Ratio (CGR) of 1100 m3/MMm3. With reservoir pressure dropping below dew point (428 bar vs. initial pressure of 478 bar), a huge volume of condensate has dropped-out inside the reservoir as confirmed by production data and the deterioration of well performance. As of 1/1/2018, the Barik Deep reservoir is developed with 29 gas producers out of which 7 wells are closed-in mainly due to liquid loading. The reservoir is currently producing above 2 MMm3/d of gas and ~400 m3/d of condensate and reservoir pressure is around 230 bars.

An integrated subsurface-surface study was started in 2017 with the objectives ∘To propose an integrated plan for re-developing the Barik Deep∘To identify solutions to maximize recovery of the dropped-out condensate∘To resolve condensate banking issues and its impact on productivity∘To identify new technologies allowing to increase production, to increase the field recovery (gas and condensate) and to propose a maturation plan for these technologies.

In a first phase of the project, a detailed analysis of all data collected over years of field development have been used to achieve a step enhancement in the understanding and characterization of the condensation process in Barik deep. In a second phase, the study involved the construction of compositional model capturing the physics of the condensation phenomena (i.e. very refined single well models) in order to assess various condensate recovery options. This effort supported the later building of full field simulation models to evaluate the impact of the most promising recovery techniques on recovery at field scale.

This paper covers: The interdisciplinary novel data analysis workflow approach followed to determine the critical elements of the condensation process (PVT, SCAL, pressure depletion, reservoir properties,...etc)The quantification and characterization of condensation by using analytical methods (Pressure Transient Analysis, PVT and production data analysis)The evaluation of various condensate recovery options (CO2, N2, separator gas, water injection and cyclic gas injection) using very refined single well physics based modelsThe evaluation of condensate recovery options using full field models adapted from these physics based modelsThe economical evaluation of condensate recovery optionsThe proposed road map for maturation of the most promising options

It is concluded from the conducted study work that out of the various injection fluid options considered, CO2 injection is likely to be the most favorable. Moreover, initial economical screening appear to be promising for CO2 injection.
Production Enhancement for Tight-Gas Condensate Reservoirs: A Compositional Dual-Porosity Model for Sabriyah Field, Kuwait
Authors: Al-Qahtani Misfera Misfer , Uzun Ilkay , Kazemi Hossein
Published: November 2018

A significant fraction of the world gas needs is supplied from gas-condensate reservoirs. The well productivity of these reservoirs is compromised because of liquid condensation in the matrix and fracture. The Sabriyah field is the first successful exploration in the North of Kuwait which led to the discovery of six extensive, deep, tight gas-condensate reservoirs. A purely fracture-dominated unconventional resource play, Najmah-Sarelu formation, is considered the source for most of the reservoirs in the Sabriyah field. In this paper, a compositional, multi-phase, dual-porosity model was used to analyze an existing horizontal well performance, and to evaluate potential enhancements to the future production.

The Sabriyah gas-condensate field in North of Kuwait is an abnormally high-pressure tight reservoir, which has very low matrix permeability and porosity. In this study, the geological system of Sabriyah field was studied using a static model to decipher the complexity of the reservoir—especially, the Najmah-Sarelu formation. A well's performance was analyzed using history-matching of the production data using a multi-component compositional dual-porosity model. To assess potential enhancement of the future production, eight different scenarios were studied. Specifically, we extended the current horizontal well length and added several multi-stage hydraulic fractures to increase production.

To assess the flow behavior of gas-condensate in Sabriyah field, we began with a study that tied the reservoir geology to the performance of a typical well using both static and dynamic simulation models. Both pressure build up and production data were analyzed using pressure and rate transient techniques which yielded an effective formation permeability of 0.5 to 0.6 mD. The numerical modeling parameters achieved a successful history match for one year of production, and the sensitivity analysis demonstrated that producing at a pressure of slightly below the dew point yielded the largest amount of condensate production. In particular, the additional condensate production was twenty-two percent for this case. Also, we observed that the existing horizontal well performed as effectively as having three-stage hydraulically fractured well in a matrix-dominated situation because of the presence of existing natural fractures replace the effect of the multi-stage fracturing.
Wellbore Assessment Using Time-Lapse LWD Calipers
Authors: Hamid Osman , Al-Qahtani Adel , Suaid Mohammed , Mohiuddin Mohammed A
Published: November 2018

Logging While Drilling (LWD) calipers (ultrasonic, density, and resistivity) have been available for several years, but their use is still limited due to the belief that they are not as reliable as the mechanical calipers obtained from wireline (WL) logs. One possible reason for this belief is the different time at which the LWD and WL measurements are made. In fact, LWD density derived calipers have their advantages over the WL calipers. One example is that they cover relatively larger portion of wellbore circumference, thereby providing a better characterization of borehole shape. A 3D caliper image can be obtained using 16 radii density measurements around the wellbore. Another advantage is that these measurements are available in real-time and borehole deterioration with time can be measured with time lapse acquisition. Accurate logging-while-drilling (LWD) borehole caliper data is important for drilling, logging and well completion. An accurate LWD caliper can greatly minimize risk and improve quality by bringing critical new information to these applications. During drilling, caliper data can be used to monitor the wellbore condition, providing early warning of borehole washout and impending wellbore instability, thus allowing the driller to take remedial action. During well completion, the caliper data can be used to accurately evaluate the volume of cement required to fill the casing annulus as well as aiding in the section of casing points or packer intervals by identifying in-gauge hole intervals. During logging, a reliable caliper is essential to correct some formation evaluation measurements for borehole size and to evaluate the quality of almost all LWD logs. A caliper can be used to plan services (such as formation testers) that may be affected by unfavorable borehole conditions.

In this paper, the main objective is to characterize the change in wellbore shape with time and relate it to formation characteristics and drilling and completion operations. Any relationship observed and correlated will be utilized to optimize these processes. The results presented in this paper show that the borehole degradation increases with time and that the accuracy of LWD derived caliper is 0.1in when both the LWD caliper and WL caliper runs are done at similar time periods. The depth of investigation in this case study is 2.25in.
Telemetry Managed Well Head Compressor: A Real Case Application
Authors: Cappuccio Pasquale , Imbò Pasquale , Gorini Simone
Published: November 2018

The GasJack® type compression units installed on wellheads are a widely applied solution to mature gas wells with unloading problems. These are very reliable machines for manned well sites, requiring little maintenance, equipped with appropriate safety systems. However, for unmanned platforms and remote areas, it is mandatory to improve the GasJack® units with a telemetry control system.

A dedicated R&D project has achieved such objective, through the following activities: "Feasibility Study", to evaluate the technical parameters and manned operations to include in the new system."Telemetry Technology Evaluation", to choose the most functional telemetry technology, by assessing the proper data communication system."GasJack® Unit Improvement", to identify the required modifications on the compressor unit, such as the replacement of existing components and the installation of a new control panel."Workshop Test and Certification", to certify the modified unit and verify its efficiency for the field test."Field Test", including an application in a remote and unmanned site, to restore production from a gas well.

The results obtained during the project are quite remarkable. The installation in the remote well area was successfully performed. At stable conditions, the technology demonstrated to be fully remotely manageable; telemetry confirmed to be an excellent tool for communication. The gas well restored its production and, thanks to the continuous monitoring and management of settings, the machine allowed the optimization and stabilization of the gas rate and liquid flow (doubling the well production capacity).

Therefore, the technology demonstrated that it can bring benefits in terms of wider application, well production increase, reduction of non-production time, simpler setting of parameters and unit operator costs minimization.

This paper explains how to update/modify a standard wellhead compressor unit, in order to install a telemetric remote control system and replace existing components, thus allowing use in unmanned sites.
A New Method to Model Fractured Rocks with Effective Capillary Pressure Curves and Saturation-Height Functions
Authors: Alobeidli A. , Li D. , Omura T. , Selvam B. , Al-Harbi M. , Ottinger G. , Obeta C. , Al-Shehhi B. H.
Published: November 2018

When a rock is fractured, its capillary pressure may radically change. In other words, the effective capillary pressure of the fractured rock is no longer the same as that of its original matrix. This is an important phenomenon to consider when building static and dynamic models of fractured reservoirs. Fracture capillary pressure can have a significant impact on modeling of initial water saturation. In a reservoir model, initial water saturation is typically calculated as a function of capillary pressure. While matrix capillary pressure can be obtained by measurements of core plugs, fracture capillary pressure is hardly known from actual data due to limited or no measurements from fractured cores. In this case, a practical solution to assign capillary pressure in a model is to modify the matrix capillary pressure in a reasonable manner. Generally, matrix of a tight (low porosity) rock can have very high capillary pressure, but once it is fractured, the water saturation in the fractured rock should be dramatically decreased. If we ignore this phenomenon, water saturation will be significantly over-estimated and consequently oil-in-place is under-estimated. Another impact of the incorrect capillary pressure can be on dynamic models, in which the model will show significantly early water breakthrough and dramatically higher water cut than field data. Therefore, correctly modeling fracture capillary pressure is critical for both static model building and dynamic model simulation. The proposed solution is to assign the effective capillary pressure for fractured rocks independently from non-fractured ones. The solution has been applied in a couple of giant carbonate offshore reservoirs in the United Arab Emirates and has demonstrated significant benefits in reservoir models with improved fluid stability and better water cut matches.
Unique Dual Core Acid Gas Removal Membrane Technology Reduces Total Cost of Ownership for South East Asia Gas Plant
Authors: Jariwala Ankur , Knight David , Mat Isa En M
Published: November 2018

Schlumberger has developed a unique PN-1 membrane technology in collaboration with Petronas. The technology is unique in combining two distinct types of membrane fibers in one single membrane module to reduce the overall membrane requirement by 10% and offers overall CAPEX and OPEX savings. The PN-1 technology was developed in 2009 and was successfully tested onshore and offshore facilities for total 5 years.

The PN-1 technology was first deployed in an onshore gas processing facility which was awarded to Schlumberger in 2013. The facility comprised of membrane pretreatment which is mainly gas dehydration, dew pointing followed by several PN-1 membranes in first stage. The membrane design was unique to handle variable inlet feed conditions from 25 to 12% CO2 inlet gas and outlet gas at 8% CO2. The feed gas design flowrate is 700 MMSCFD and at 750 psig operating pressure. Since this is an onshore gas receiving station, the processing trains should be able to handle variable inlet CO2 concentration in the inlet feed gas and particularly membranes.

Schlumberger engineered the entire pretreatment system, membrane and mercaptan removal system. The entire system was delivered and commissioned by Schlumberger on time and was brought online in 2017. The PN-1 membrane system was successful in meeting the required outlet gas CO2 specification while retaining maximum hydrocarbons in the product gas.
First Global Successful Large Diameter Pressurized Coring Application Using HPWBM: Kuwait Case History
Authors: Stewart Robin , Osman Tarek , Reda Tamer , Al-Ajmi Abdullah , Al-Rushoud Abdulaziz , Gohain Ashis , Khatib Faiz , Al-Haj Hussain , Al-Naqa Faisal , Al-Mutawa Faisal , Al-Gharib Majed , Shinde Hrishikesh , Al-Mekhalef Alanoud
Published: November 2018

Conventional coring does not provide core samples that are characteristic of the original formation condition. Thus, pressurized coring is required to capture samples that represent the in-situ composition of gases and liquids; pressure, volume, and temperature (PVT) data of the fluids, and porosity, permeability, and wettability, which are critical to reservoir interpretation and development. A customized high-performance water-based mud (HPWBM) was used successfully where prior attempts with conventional water-based mud (WBM) had failed.

The key well challenges included wellbore instability with caving shale and depleted reservoir sands. Previous attempts to retrieve pressurized core using conventional WBM proved unsuccessful because of the early activation of the pressurized capture mechanism caused by an accumulation of wellbore and mud solids linked to insufficient hole stability. A HPWBM containing liquid additives was customized to minimize solids content while stabilizing the shales and to minimize the differential sticking potential in the depleted reservoir. The formulation was finalized, based on laboratory testing, to optimize the bridging and inhibition package for the formations drilled.

Drilling and logging were successfully completed with no incidents; the fluids parameters were maintained to effectively clean the hole while controlling equivalent circulating density (ECD) through minimizing solids in the mud. The combination of salinity and liquid additives used minimized the total solids of the mud while effectively stabilizing the wellbore, which helped to reduce the premature activation tendency of the catcher system of the pressurized coring tool.

Pressurized cores were successfully retrieved with in-situ conditions and analyzed on-site, maintaining a pressure equivalent to the pore pressure. The core samples were retained in their native state for future studies. There was no nonproductive time (NPT) related to wellbore instability, and differential sticking was avoided by the customized bridging across the depleted reservoir. The successful collection of data enabled improved reservoir modeling.

This paper discusses the design of the HPWBM system, along with its technical features and benefits, which helped to successfully complete the first global 12 ¼-in. pressurized coring application. The customized HPWBM provided good shale inhibition, low solids and excellent lubricity, and eliminated the need for conventional shale stabilizing materials, which could have interfered with the capture of the pressurized core.
Improved Decision Making for Coiled Tubing Well Intervention With Downhole Video Camera DVC
Authors: Hamid Saad , AlMulhim Abdulrahman , AlGhamdi Abdullah , Unnikrishnan Vikram , Ahmed Usman
Published: November 2018

Conventional Coiled tubing well intervention has been carried out in oil and gas wells for more than 30 years with not real-time data acquisition. With the advent of Coiled Tubing Telemetry (CTT) e-line/fiber optics/mono conductors in coiled tubing industry, a wide variety of opportunities has become available - downhole video camera (DVC) being one of them, to go beyond the conventional parameters and optimize the well intervention operation.

DVC is used in the oil and gas industry with high success rate reported by several operating companies and service companies around the world. Video cameras have mostly been deployed using e-line; however, Coiled tubing camera runs provide the ability to clean the wellbore (by pumping fresh water or solvent) for capturing clearer, crisper videos and images.

As the oil and gas industry is moving towards improving operating efficiency, minimizing the coiled tubing runs based on actual downhole data is of utmost importance. Therefore, having the ability to inspect downhole obstructions using the video camera, and to observe the downhole conditions is phenomenal.

In this paper, the well intervention performed on multiple oil and gas wells in Middle East shall be discussed. Whenever an obstruction is encountered in the well bore, the primary form of detecting it is to run a lead impression block (LIB) on slickline or e-line. In most cases the LIB results do not provide a clear indication of the anomaly or obstruction. Not only that it sometimes adds to further confusion leading to inappropriate job design and planning, which results in potential misruns, inaccurate tool selection resulting in extensive and costly operations.

This paper aims to highlight the unique integration of DVC and telecoil application to enhance the reliability of data acquisition and job success. The custom designed downhole camera shroud, along with the robust CTT system is deployed in each of the candidate wells. The camera chosen is designed to withstand the maximum anticipated downhole temperature.

All the camera runs were analyzed and the obstruction in the wells was determined, which enabled the team of engineers to decide on the appropriate real-time course of action to gain access into the well bore or detect functionality of downhole jewelry.