bluuebunny/crossref_metadata_2025 huggingface dataset:
A Fast Parallel Coupled Hydraulic Fracture Simulator
Authors: Shetty Dinesh , Lin Avi
Published: December 2014

The multiphysics of hydraulic fracturing unconventional reservoirs is complicated, involving large, dynamic, and complex-shaped fracture networks composed of natural, hydraulic, and induced fractures, multiphase flow, solid-fluid interaction, and fracture-reservoir coupling, all of which make numerical simulation computationally prohibitive. Thus, innovative and efficient algorithms that are accurate, stable, and scalable to exploit modern hardware have become imperative. In this paper, a novel multigrid-based computational approach for hydraulic fracturing simulation is proposed and analyzed. It is composed of four grids; namely, the junction grid, the fracture grid, the rock block grid, and the reservoir grid, which are listed in hierarchical order. The reservoir is represented in the most inner level through a set of one-dimensional (1D) domains. In the next level, the fractures are represented through a collection of connected 1D grids. The fracture and the reservoir coupling lead to a pseudo-two-dimensional (2D) (fish-bone like) structure. The rock block dynamics are simulated on a 2D grid. On the top of the hierarchy, a 2D junction grid interacts directly with the fracture and rock grids. In this multigrid approach, the reservoir lines are first eliminated using fast parallel Cholesky decomposition. This is followed by an elimination of fractures using parallel Gauss elimination. Simultaneously, the rock blocks are also solved in parallel. This computational approach reduces the original large problem into a condensed small problem formulated only in terms of the junction variables. The resulting small sparse junction system is efficiently solved to obtain the solution on the junction grid. Then, this solution is propagated to the fractures through a primary prolongation operation. Finally, the solution for the reservoir grid is reconstructed from the fracture grid through a secondary prolongation operation. The capability of the algorithms is illustrated through actual simulations.
Maintaining Well Integrity in Underground Gas Storage Wells in China Using a Novel Cementing Technology
Authors: Wu L. , Yi L. , Taoutaou S. , Yao K. , Fan Y. , Liu W. , Fan X. , Liu H. , Liu L.
Published: December 2014

Underground gas storage (UGS) wells have become the natonal strategy for natural gas storage and supply throughout China. PetroChina is building UGS facilities throughout the country, with planned construction extending from 2011 to 2015. The Chongqing gas storage well project in Central China is one of the constructed facilities. Because the life expectancy of gas storage wells is at least 50 years, long-term maintenance of well integrity is one of the major challenges faced during the construction and operations phases of UGS wells. The wells must bear the injection pressures, temperature changes, and frequent cycling of injection during production. With conventional cement, the pressure and temperature change during the injection and production phases can result in cement traction, compression, or microannulus failure. This leads to gas migration through the damaged cement sheath, which means the well will fail its mission as a UGS well.

To maintain well integrity, a novel engineered flexible and expanding cement system has been introduced for UGS cementing in the Chongqing project, whereas past service companies have failed to deliver the fit-for-purpose solution. The optimized mechanical properties of this novel cement allow the cement to remain intact under extreme pressure and temperature changes.

To prove the ability of the selected flexible and expanding cement to withstand the pressure change, logging was conducted at various times during the construction and after the casing pressure test cycle. The logs show excellent results.

Since its implementation, the flexible and expanding cementing system has become the standard solution for China's UGS wells, in which long-term well integrity and sustained casing pressure are required. This paper discusses the challenges for cementing UGS wells, which case histories describe the successful implementation of the FEC solutions.
Application of Micro-fine Cement for the Sequential Zonal Abandonment of a Multi-Zone Sand Propped Fractured Horizontal Well With Coiled Tubing - Lab Studies, Field Trial & Computational Fluid Dynamics
Authors: Boekholtz E. A. , Bansal B. D. , Pasturel C. , Madsen M. M. , Tonell D.
Published: December 2014

For the first time in a Danish field, micro-fine cement was used to abandon a multi-zone horizontal well by plugging each sand fractured zone sequentially. Lab testing was performed to investigate the depth of penetration of different conformance systems in a 20/40 sand pack. The micro-fine cement showed the highest penetration and was considered the best option for abandoning sand propped fracs in horizontal wells. The first field application was unsuccessful due to pre-setting of the micro-fine cement in the Coiled Tubing. Extensive lab tests were performed to understand the causes of the pre-mature setting of the cement. A new cement recipe was selected and subjected to modified lab test procedures to successfully abandon the horizontal well.

To economically develop chalk reservoirs in the North Sea, long horizontal wells are drilled, hydraulically fractured and waterflooding is applied to the field. To ensure conformance, flow from each fracture is controlled by a Sliding Side Door (SSD).

Well A suffered injection water breakthrough which could not be controlled by closing the SSDs. To enable the full abandonment of each zone the decision was made to isolate each zone sequentially from the toe of the well up with cement retainers and to use Coiled Tubing to squeeze a pre-determined volume of special micro fine cement into the zone in order to plug the tubing, the tubing-liner annulus, any cement channels and a limited section of the sand propped fracture. In this manner any potential water channeling between zones and with other wells in the pattern would be prevented.

This paper discusses the results of initial lab tests, causes of failure of the first job, testing of new micro-fine cement and the successful application. This paper also discusses the results of computational fluid dynamics simulations which were performed to understand the behavior of cement in a fracture and enable further improvements to similar abandonments in the future.
Chemical Solutions for Improved Waterflooding in Carbonate Reservoirs
Authors: Acevedo-Vélez Claribel , Mukherjee Joydeep , Yu Wanglin , Mounzer Hamza , Buckner Wanda , Falcone-Potts Susan , Hernandez Martha
Published: December 2014

Improving oil recovery in mature carbonate reservoirs is a significant challenge in the petroleum industry. Carbonate reservoirs present several characteristics which lead to low oil production during waterflooding, including reservoir rock heterogeneity and heterogeneous wettability. Several laboratory investigations have shown that changing the rock surface wettability to a more water-wet state can lead to significantly higher oil recovery during the waterflooding process. In particular, the addition of wettability altering surfactants enhance water imbibition into the low permeability matrix and enhance water spreading on the carbonate rock to release trapped oil and hence increase cumulative oil recovery. This paper reports the development of wettability altering surfactant formulations to improve waterflood performance in carbonates under a wide range of reservoir conditions (e.g., temperature, salinity). First, an efficient wettability altering surfactant was developed for application at low salinity (up to 4%) and moderately high temperature (up to 80°C) conditions. Second, a design of experiments was developed and executed to explore formulations consisting of surfactants and additives for application at high salinity (greater than 10%) and high temperature conditions (greater than 100°C). In addition, the effect of divalent cations on the stability of the surfactant formulations was investigated. Finally, laboratory studies were conducted to evaluate the performance of the developed surfactant formulation at relevant reservoir conditions, including core flood experiments. This paper also describes laboratory studies aimed at providing further insights into the wettability alteration mechanism by these surfactant formulations. Overall, the results presented in this paper support the hypothesis that altering the rock surface wettability using the developed surfactant formulation can improve waterflood performance in carbonates under a wide range of reservoir conditions, which may present a significant opportunity for application in the oil field.
Geosciences Understanding as a Breakthrough to Enhancing Borehole Stability Management - Lower Tawilah Sandstone, Central Yemen
Authors: Yasir M. , Neff P. , Zabalza I. A. , Klaa K. , Krusche K. , Kuzmanovic U.
Published: December 2014

Well bore stability management is key to HSSE and cost effectiveness while drilling. This work focuses on the role of Geosciences to understand, explain and better predict the occurrence of well bore stability issues during onshore drilling operations in Block S2, central Yemen.

To reach the primary reservoir target, the fractured Basement, development wells must penetrate a complex stratigraphic column, characterized by ten key formations and approximately 2000 meters thick. Lithologies vary from sandstones to carbonates, including salt layers with clay intercalations. Severe mud losses are often encountered in poorly consolidated sands of the Lower Tawilah formation where well inclinations are vertical or sub-vertical. At their most severe, they can translate to a complete loss of drilling mud returns on surface. Severe mud losses are not only a threat to borehole stability but they can have a serious impact on the drilling budget and timing.

In order to improve drilling efficiency and speed-up the decision-making process associated with mud losses management and well stability, a detailed Geoscience study has been carried out. This work focuses on identifying three critical factors to explain the occurrence of severe losses: –the lithological variability of the Lower Tawilah,–the formation pore pressure–the local stress regime.

Despite the challenging working environment and the interaction of geological heterogeneity, pore pressure and stress across the development area, the prediction and prevention of mud losses has been greatly improved while drilling new wells.

The main objective of this paper is to highlight the role these three major elements play during drilling by illustrating with case study examples. Finally, mitigating actions and strategies implemented to prevent and/or deal with severe drilling mud losses are presented.
G&G Data Integration to Model a Carbonate Giant Field: Predicting & Managing Reservoir Properties in an Underexplored Basin till Production Phase
Authors: Marini A. I. , Spadafora E.
Published: December 2014

The early integration of geological concepts and seismic (qualitative and quantitative) interpretation is a powerful tool to enhance the probability of success of an appraisal campaign. The presented example of an integrated workflow was applied to Perla Field (offshore Gulf of Venezuela), an Early Miocene carbonate reservoir containing gas and condensates. The work was therefore tailored on the integration of geological data and advanced seismic interpretation since exploration project start-up is a key to improve success of appraisal campaign and early production phases.

The presented case refers to an Early Miocene gas-bearing carbonate asset, Giant world-class reservoir. 3D Seismic data shows an isolated bank developed on basement high, thickness decreasing from crest-to-flanks. Wildcat well found 200m high-porous bio-GRST/PKST having moderate diagenetic imprint.

The red algae-dominated system formed low-angle ramps more than classical flat-top platforms. AVO attributes (Gradient) fully supported detailed seismic interpretation, since Carbonate reflections responded to elastic changes rather than subtle acoustic contrasts, negligible on conventional seismic.

A petroelastic model and strict quantitative amplitude reliability were validated.

Acoustic Seismic inversion was performed right after the wildcat well.

Efforts devoted to realistic a-priori model building accounted for overburden trend and carbonate sequences velocity fields. The inversion results permitted seismic to effective porosity calibration (Seismic Pseudo-Porosity Volume), a significant tool for the delineation campaign.

Inversion properties vs depositional facies geometries relationships also allowed facies belts areal definition; jointly with structural attributes they were used to optimize the number, locations and trajectories of delineation wells. Appraisal wells confirmed the porosity predictions at seismic scale, and approach stability. No needs for acoustic inversion or calibration revision were considered, due to the high-quality blind tests results on appraisals. The availability of hard-data from extensive core campaign, re-enforced the geophysical calibration to reservoir facies, via petrophysics and rock-physics lab measures.

Seismic Porosity, Non-Supervised, and Supervised Facies cubes got into reservoir model, driving the areal distribution of Sw and K.

Elastic-Porosity large variability was tentatively correlated with the factor Gamma-K, representing the frame flexibility, hence pore structure of different sed-petro-facies.

Manipulation of Elastic Inversion data and more stable Rock Physics Model would be the next development to capture internal reservoir model microstructure variances.
Complex Phased Development for CO2 EOR in Oil Carbonate Reservoir, Abu Dhabi Onshore
Authors: Figuera Luis , Al-Basry Ali , Al-Hammadi Khaled , Al-Yafei Arafat , Sakaria Dipak , Tanakov Mikhail
Published: December 2014

CO2 injection into oil reservoirs for EOR is well known as one of the most proven and efficient Enhanced Oil Recovery (EOR) processes. The subject study was conducted with the objective of enhancing oil recovery by injecting CO2 into a heterogeneous, low dipping and low permeability carbonate oil reservoir. The required CO2 is captured from a steel plant (Emirates Steel Industry (ESI)) which is part of a large scale carbon capture and injection project. The project entails capturing, dehydrating, compressing, and transporting the CO2 to the oilfields for sequestration and/or EOR processes. The carbon capture from ESI is part of a collaboration (Joint Venture) between ADNOC and MASDAR which will help make CO2 available for potential future EOR operations along with the added benefit of reducing Abu Dhabi's carbon footprint.

As part of this initiative, planning of the CO2 EOR process as part of ADNOC's EOR strategy is essential and includes building a phased development CO2 EOR model. The strategy is to breakdown the overall objective into phased developments/projects in order to gain experience in surface and subsurface aspects of CO2 EOR, operations and mitigate risk. The end goal of the phased development is to enhance oil recovery, improve CO2 utilization, and maximize project profitability by implementing more complex operations such as Continuous/WAG CO2 injection, CO2 recycling, and the development of "difficult oil" from flank areas with higher water saturation (transition zone). This paper discusses the benefits and rationale behind building such a phased development model.
Deployment of New Sonic-While-Drilling Technology in a Large Development Project in the Middle East: A Case Study
Authors: Murray Doug , Belaud Didier , Ogawa Ryoko , Shaban Mohamed , Edwards Ewart , Abbas Nashat , Al Ayadi Kholoud Ghareeb , Boyd Douglas
Published: December 2014

A new logging-while-drilling (LWD) sonic tool was successfully deployed in a large development project in the Middle East. The new LWD sonic tool offers robust compressional and shear measurements, irrespective of mud speed, and Stoneley information for a wide range of applications. The acquisition of LWD sonic measurements can be challenging. The introduction of the new tool with a novel hardware design, extensive tool modeling, and an alternative approach to data handling has significantly improved both overall data quality and the viability of advanced answer products while drilling.

The fundamentals of both wireline and LWD sonic measurements are similar; however, differences in the measurements dictated by the deployment environment need to be considered. LWD tools are deployed on a drillstring and have a large diameter. Wireline tools are much smaller and are deployed on wireline after drilling is completed. Operational frequencies, acquired waveform modes, and transmitter-receiver source spacings are also different. The most fundamental difference is that the new LWD tool uses quadrupole technology to acquire shear slownesses in slow formations (shear formation slowness slower than mud speed), whereas, in the same environment, the wireline tool relies on dipole technology.

Although there is considerable literature that discusses waveform quality, processing, and interpretation of wireline sonic measurements, very few such studies exist for LWD sonic measurements. In addition, no studies compare the measurements. To investigate the interpretation and use of the new LWD tool and to compare it with wireline sonic tool technology, both methods were deployed in the same wellbores in a large development project in the Middle East. Most observed disparities were across washed out boreholes where data quality from both wireline and LWD tools was negatively affected by the borehole environment.
Integrated Simulation Study of a Gas Condensate Field with Nitrogen and Hydrocarbon Recycling
Authors: El Gohary Mohamed , Al Bairaq Ahmed , Al Hashemi Hussain H. , Abed Abdulla , Saeed Yawar , Torrens Richard , Kumar Arun
Published: December 2014

This paper presents a feasibility study for the development of the unexploited outlying area of a gas condensate field operating under gas recycling mode to optimize condensate recovery. Heavier components have migrated to the flanks which is the motivation to exploit this area. To maintain reservoir pressure the voidage replacement ratio must be maintained at 100%. However, due to high demand for natural gas, a certain percentage is replaced with non-hydrocarbon makeup gas. This strategy has the potential to reduce the condensate recovery as well as affect the quality of the produced gas.

A reservoir simulation study was conducted to maximize the condensate and clean gas recovery through development of the flanks. Two major scenarios were created consisting of more than twenty different development strategies based on well location, number of wells and well production rates. Additional sensitivities on blow down time, under-injection, injection stream composition and compression were considered for both scenarios. The influence of the surface infrastructure on production performance has been quantified by the application of Integrated Asset Modeling, which improves the accuracy of the standalone reservoir simulation scenarios.

The study highlighted a significant upside in terms of oil recovery by exploiting the outlying area of the field. Multiple optimization scenarios were performed and a maximum gain of approximately 10% in recovery was observed above the base case. Integrated Asset Modeling led to more optimistic estimates of future recovery and reduced makeup gas production, through the removal of simplifying assumptions related to back pressure and injection composition.
Major Step Change in Sampling While Drilling Technology Combined with Best Practices Delivers Fluid Samples and Pressures in S-Shaped Well Over Challenging Thin Bed Successions
Authors: Tran Huy N. , Tang Binh V. , Nguyen Tuan M. , Tran Dinh V. , Tran Ninh D. , Hardikar Nikhil P. , Pragt Jos S.
Published: December 2014

This case study highlights a major step change in fluid sampling technology while drilling. The decision to deploy a Logging While Drilling (LWD) fluid sampler was made because of the S-profile well, which would have required pipe-conveyed wireline fluid sampling. This would have added rig days to the project and increased the risk of stuck pipe. One run of the LWD fluid sampler, during a wiper trip, was sufficient to acquire the necessary 60 pressure tests, fluid gradients, down hole fluid identification and analysis and PVT samples. Six single phase oil samples (four liters total volume) were acquired. Lessons learnt offer additional best practices and risk mitigation techniques for future LWD sampling projects.

The thin bed succession comprises centimeter to meter scale sandstones, inter-bedded with shales. The sandstones have a variable measured mobility between 1.2- and 296-mD/cP. This type of succession poses significant challenges to obtain a gradient for each sand layer, particularly since each layer may have different fluids. Moreover, inherent depth uncertainties in these measurements, affects the fluid gradient. The excellent repeatability of the pressures allowed adjusting formation tops by reconciliation to pressure profiles. This reconciliation process could only be achieved by taking many pressure tests (upto 60). A consequence of this process was the high-grading and selection of representative locations for sampling. There were zero lost seals during the pressure testing and sampling operation. Laboratory analysis results showed about 15% WBM filtrate contamination, which was comparable to wireline runs in the same formation.

In conclusion, this case study shows that LWD pressure and sampling technology provides high quality results over complex thin bed reservoirs with different fluid types; Operators no longer need to consider a well's deviation or complex geometry to collect fluid samples while drilling; the demonstrated operational efficiency and good sample quality resulted in significant savings in rig costs (USD 2 million) and the LWD sampling application reached the same sample integrity and safety standards as compared to existing wireline methods.
Experimental Study of Plastering Effect During Casing While Drilling
Authors: Naveen Velmurugan , Babu Vinay
Published: December 2014

The objective of this work is to experimentally understand the plastering effect during Casing while Drilling (CwD). CwD can be considered as the process of drilling the well wherein the drill pipes are replaced by the casing and the well is cased as it is being drilled. Literatures have exclusively shown that CwD is practiced with a notion to reduce the Non - Productive Time (NPT) and to tackle problematic zones of fluid loss or unstable formation. One plausible reason that has been claimed is the plastering effect during CwD, in which the drill cuttings are crushed to finer particles between the casing and the wellbore during contact due to limited annular clearance. These finer particles are smeared into the formation by the mechanical contact of casing to the wellbore. Plastering effect leads to formation of a thin layer of mud cake that is strong enough to prevent fluid loss and had been proven in the field trials.

Actual forces acting on the drill cutting in the limited annular space can be majorly divided as centrifugal force and the drag force due to circulation of drilling fluid. Apart from the smearing effect, the acceleration due to the centrifugal force may also be responsible for the cuttings to be adhered to the wellbore. Here, in this study, authors consider the CwD process to be analogous to a large vertical centrifuge and experimentally understand the process.
A New Approach for Optimization and Uncertainty Assessment of Surfactant-Polymer Flooding
Authors: Nguyen Ngoc T. , Chen Zhangxin , Nghiem Long X. , Dang Cuong T. , Yang Chaodong
Published: December 2014

Surfactant-Polymer (SP) flooding has become an attractive Enhanced Oil Recovery (EOR) method. Defining chemical concentrations, chemical types and an injection schedule, according to geological features of a reservoir and well pattern, is key to making decisions for reservoir management.

In this paper, we introduce an innovative approach for EOR optimization under geological uncertainty by integrating a reservoir geological property modelling and a robust optimizer. Multiple reservoir realizations are generated automatically by geology-driven modeling software and sent directly to an optimizer to analyze the effect of single or multi-parameters on objective functions such as cumulative oil production and net present value (NPV). Clay minerals play an important role in chemical flooding, but it is rarely included in the reservoir simulation. In this study, the distribution and proportion of clay are investigated in terms of facies and its relationship with porosity and permeability for a sandstone reservoir. Different facies and petrophysical properties are geostatiscally generated in a geologic manner that significantly improves the quality of history matching and optimization processes.

It is found that SP flooding has the highest oil recovery factor in comparison with waterflooding, polymer flooding and surfactant flooding, and it demonstrates good performances even in high clay content reservoirs. The optimal formulation of SP and polymer slugs and injection schedule were proposed. The effect of clay content in cumulative oil and NPV were addressed, in which the more clay content is the lower NPVs obtain. A comprehensive geological uncertainty analysis has been performed for: (1) facies distribution only; (2) facies distribution and proportion. The results indicated that NPV uncertainty is less than 2.25% for (1) and about 4.18% to 5.68% for (2).

The proposed optimization approach could be effectively applied to tertiary EOR techniques in various reservoir conditions under geological uncertainty. By integrating geological software, reservoir simulator and robust optimizer, it serves as a powerful tool for design and optimization of these processes.

SP flooding is definitely a complicated process, therefore, an innovative modeling and optimization approach for SP flooding described in this paper is needed to improve the prediction of process performance.
Demonstrating the Potential of Low-Salinity Waterflood to Improve Oil Recovery in Carbonate Reservoirs by Qualitative Coreflood
Authors: Nasralla Ramez A. , Sergienko Ekaterina , van der Linde Hilbert A. , Brussee Niels J. , Mahani Hassan , Suijkerbuijk Bart M. , Al-Qarshubi Ibrahim S. , Masalmeh Shehadeh K.
Published: December 2014

Low salinity waterflood (LSF) is a promising improved oil recovery (IOR) technology. Although, it has been demonstrated that LSF is an efficient IOR method for many sandstone reservoirs, the potential of LSF in carbonate reservoirs is still not well-established as only a limited number of successful coreflood experiments are available in the literature. Therefore, the aim of this study was to examine the oil recovery improvement by LSF in carbonate reservoirs by performing coreflood experiments.

This paper proposes an experimental approach to qualitatively evaluate the potential of LSF to improve oil recovery and alter the rock wettability during coreflood experiments. The corefloods were conducted on core plugs from two Middle Eastern carbonate reservoirs with a wide variation of rock properties and reservoir conditions. Seawater and several dilutions of formation brine and seawater were flooded in the tertiary mode to evaluate their impacts on oil recovery compared to formation brine injection. In addition, a geochemical study was performed using PHREEQC software to assess the potential of calcite dissolution by LSF.

The experimental results confirmed that lowering the water salinity can alter the rock wettability towards more water-wet, causing improvement of oil recovery in tertiary waterflood in plugs from the two reservoirs. Furthermore, seawater is more favorable for improved oil recovery than formation brine as injection of seawater after formation brine resulted in extra oil production. This demonstrates that the brine composition plays an important role during waterflooding in carbonate reservoirs, and not only the brine salinity. It was also observed that oil recovery can be improved by injection of brines that cannot dissolve calcite based on the geochemical modeling study. This implies that calcite dissolution is not the dominant mechanism of IOR by LSF.

To conclude, this paper demonstrates that low-salinity waterflood has a good potential as an IOR technology in carbonate reservoirs. In addition, the proposed experimental approach ensures the verification of LSF effect, either it is positive or negative. However, more work is required to further explore the most influential parameters affecting LSF response and explain the dominant mechanisms.
Challenges and Learning from Developing Deep High Pressure Sour Reservoirs in Southern Oman by EOR MGI
Authors: al-Hadhrami Abdullah , Jabri Abdullah , Alawi Hamoud , Proot Michael , Schulz Ralf , Barwani Shihab , D'Amours Kevin
Published: December 2014

The Sour Cluster is located in the south of the Sultanate of Oman. Since the first oil discovery in 1997, a successful exploration drilling campaign was carried out in the Cluster, resulting in the discovery of several carbonate stringer oil and gas reservoirs. Approximately half the gas volumes are contained in a gas condensate field. This field will be developed along with the other oil reservoirs in the cluster and will export gas to market as well as provide a source of make-up gas for the miscible gas injection operations.

In phase 1 of the development (normal depletion), the wells were routed to the existing station-B via the Early Development Facility (EDF). These facilities consisted of a number of remote manifolds, a 70 km multiphase pipeline to station-B and a new oil and gas compression train at station-B. Whilst the field was depleted via station-B, design and construction of the new plant (phase 2) progressed.

First production from phase 2 commenced 10 April, 2012, some 3.5 years after the target first oil date. Despite the delayed start, this first oil milestone is considered a commendable achievement given the significant challenges faced by the project team during the execution phase. Building a facility to handle the extreme mixture of high pressure, sour corrosive fluids and gas contained within the sour reservoirs is a technical step-out for PDO, let alone the oil industry in general.

The establishment of the new Production Station (Station-H) now provides the infrastructure for long term development of the area and a number of follow-on projects which will make use of these facilities are either already in operation (Phase 3) or in execution(Integrated Phase 4). Learning from phase 2 has been taken onboard in the design of these follow-on projects and the area will deliver robust value to PDO / Oman for generations to come.

This paper will outline some of the key challenges that were overcome by the design and project execution teams on the phase 2 project and how lessons learned were taken onboard to facilitate project delivery of the extended larger MGI development for follow-up phases and in similarly challenging projects in PDO.
Micro Rhombic Calcite of a Giant Barremian (Thamama B) Reservoir Onshore Abu Dhabi - Clumped Isotope Analyses Fix Temperature, Water Composition and Timing of Burial Diagenesis
Authors: Vahrenkamp V. , Barata J. , Van Laer P. J. , Swart P. , Murray S.
Published: December 2014

Micro porosity associated with micro-rhombic calcite provides volumetrically the largest pore volume in Middle Eastern Cretaceous carbonate reservoirs. With progressing reservoir development and depletion of macro-pore systems the low permeability micro pores have ever increasing importance as host to remaining hydrocarbons and for reservoir performance. A new technique is presented – Clumped Isotope Thermometry – which yields significant new insights on burial depth, timing of diagenesis and the nature of the diagenetic fluids. This in turn helps to better understand the widespread distribution of micro porosity in Abu Dhabi reservoirs.

The genesis of micro-rhombic calcite has previously been placed into the shallow burial realm under the influence of meteoric or marine pore waters (Budd, 1989; Moshier, 1989) using oxygen stable isotopes and petrographic observations. However, the interpretation of oxygen isotope data is limited by the fact that the isotopic composition of calcite minerals is determined by two independent factors: the isotopic composition and the temperature of the precipitating water. The new analytical technique of clumped isotopes has established a way to independently determine one of the variables (temperature) thus allowing the other (water composition) to be fixed. The new technique has been applied to 15 samples from three cores of a giant Abu Dhabi reservoir. Samples are from the Barremian Thamama B reservoir unit. Stable isotope data exhibit a normal range for Thamama B calcite (δ13C: 2.8‰ to 3.9‰; δ18O: 4.6‰ to 5.9‰). Clumped isotope analyses indicate a most likely precipitation temperature of 65°C to 72°C and an isotopic composition of precipitating waters of 3.3‰ to 4.9‰ δ18O. Using a well calibrated basin model the temperature range places the depth of diagenesis between 0.65 km and 1.1 km and the timing of diagenesis into the Late Cretaceous (Turonian to Campanian). This coincides with the subsidence of the eastern Arabian plate margin caused by the opduction of oceanic crust (Semail ophiolite and associated marine sediments). The heavy oxygen isotopic composition of the diagenetic water of 3.3‰ to 4.9‰ δ18O corroborates a burial setting for diagenesis. Results imply that diagenesis was driven by a regional east to west burial flow system driven by compaction and convection with likely significant implications for the regional distribution of porosity & permeability.
CO2 Rich Natural Gas Conditioning Technologies: Comparison Study
Authors: Farges O. , Fränkie S. , Linicus M. , Terrien P.
Published: December 2014

Nowadays, a growing interest is shown for CO2 rich natural gas fields. Especially South East Asia, Australia and South America are regions where the exploitation of such gas fields is investigated.

A wide range of proven technologies for CO2 removal exists, from the traditional amine units, membrane systems including one or multiple stages, to newly developed cryogenic technologies and combinations of the above. These technologies need to be adapted and optimized providing technically and commercially viable solutions to gas field operating companies for the conditioning of such a low caloric natural gas.

This paper presents the results of a study comparing the most promising natural gas conditioning technologies considering various process parameters like CO2 and hydrocarbon feed content, plant capacity, treated gas specification, hydrocarbon recovery requirement and the potential CO2 valorization application (e.g. enhanced oil recovery (EOR)). Air Liquide Global E&C Solutions has a unique position in performing such a technology comparison as a technology provider for all bricks. Inhouse and commercial tools were used in order to optimize each technology brick independently as well as to intregrate the bricks together.

Various process schemes have been studied for natural gas feedstocks containing up to 60 vol% CO2. This paper comprises general process description of the conventional amine and membrane setups as well as more information about the innovative cryogenic solution proposed herein. The total costs of ownership for the different processes have been evaluated taking into account capital and operational expenditures as well as the hydrocarbon recovery of the applied processes.

Although the optimum solution strongly depends on the specific project's parameters, some general trends and conclusions can be derived from the results of the study: the combination of membranes with cryogenics is the most suitable solution in case of high CO2 containing feed stocks and if the CO2 product is used for EOR applications, means a pure CO2 product delivered at high pressure. Amine wash and hybrids of amine wash and membrane seem to be favorable at low to medium CO2 containing feed stocks and if the CO2 product shall be supplied at low pressure to battery limits. Beyond that, the paper also comprises conclusions and recommendations taking into account the other project and process parameters and their respective operating ranges.
Paper Title: Workforce Nationalization in Emerging Oil and Gas Markets
Authors: Paydar Masoud
Published: December 2014

In oil-rich markets from Africa to the Middle East, recruiters and employers are reacting to government pushes to see a higher proportion of the workforce made up of native-born workers. It's become the responsibility of global organizations to support the local workforce and ensure integration of the local and expatriate talent. Government-owned National Oil Companies (NOCs) demand heavy investment and commitment in the development of educational institutions, workforce nationalization, and investment in foreign countries' critical infrastructure.

International energy companies utilize Workforce Nationalization programs as they expand operations into foreign countries. These programs employ nationals in oil and gas projects, making them stakeholders, as their participation adds value to their local economies. The programs also enable Multinational energy companies to integrate into the communities they operate in.

For Workforce Nationalization programs to be effective, companies need to provide the necessary technical, safety, and cultural training to develop people for operational roles. Post-secondary institutions are responding to this market need for customized training, which is delivered offshore or in-country. Training programs leave a positive impact by contributing to the overall economic development of the country, and by providing individuals the opportunity to not only enter into the workforce but also to develop a career path and to expand their cultural horizons.
Unified Communication and Collaboration from office to Rig
Authors: Moussa Mohamed Samir
Published: December 2014

The aim of this paper is to demonstrate the experience of Abu Dhabi Company for Onshore Oil Operations (ADCO) during the implementation of Unified Collaboration and Communication across the wide company assets covering the offices in the headquarters till the remote areas such as fields and rigs. The demonstration highlights the pre initiation and preparation activities that occurred in the earlier phases before starting the implementation and how corporate information technology department established its implementation methodologies and strategies that helped later to shape the road before implementing the project. The history of collaboration implementation in ADCO was among the first collaborative working environment in the region back in 2006. Adopting the latest technology back on that time and utilizing the visualization and audio technologies, in addition it was the first to introduce the 3D projection for subsurface modeling in the region that changed the user experience and move it to different levels. While the paper focuses on the whole project stages, it emphasis as well the theory behind the collaboration and communication in any enterprise and argue that companies born collaborative by nature as communications methods and techniques are naturally agreed upon between its employees with no define rules and boundaries. The theory illustrate that the human nature and culture by default embraces the collaboration in its basic means but on the other hand corporate directions, polices and rules might exploit such collaboration and have an effect on it in such way that can result in positive or negative directions. The importance of applying Unified Communication and Collaboration was great step for ADCO as a company toward its operation excellence that enabled ADCO as an organization to better utilizing the existing solutions, accelerating people processes and technologies associated in any given job, putting all that information in one particular place, rational decisions can be made by experts using the correct tools as well as the right information and sharing it in real-time. There is no doubt that the project faced challenges before, during and post implementation, as result lesson learnt was important to be captured to be a later reference to implementation of such similar projects. In addition management of change as well was a crucial milestone of this project while giving proper planning enough time and determining right approach of user adoption will affect how users will be embraces or resisting such change or to be part of the new collaborative experience.
Automation of ADCO Well Delivery Process - A Dream that has Become a Reality
Authors: Zahran Hussein F , Al-Fardan Firas I
Published: December 2014

The process of well planning & well delivery consists of several connected sub-processes and major activities that are carried out across different organizational functions and disciplines; on the other hand demand for energy increases, and ADCO as an organization is seeking new ways to optimize and improve operations – shortening timeframes to production and optimizing cash flow; taking those facts into consideration ADCO decided to take a lead in building an innovative solution entirely in-house gaining from the technical expertise of the different business units within the organization and its CIT division to provide a cutting-edge solution.

Electronic Well Delivery Process (eWDP) provides a standardized method to easily manage and track all pre-drilling/post-drilling activities including tasks, documents, people & rigs.

With the eWDP release, a measurable positive impact has been observed and the mentioned below is a set of day to day savings eWDP is contributing for the overall corporate objectives

Different asset teams were able to smoothly communicate the drilling requirements in a productive manner allowing obtaining the right approvals on time, giving an edge for management to forecast the set strategic objectives and enabling the right decisions to be taken. Planning teams are able to forecast the drilling materials requirements at an early stage through navigating automatically the store inventory and identifying the availability of drilling materials. eWDP provides drilling operation teams with tools to forecast the best rig move route for the allocated rigs "Rig Move Optimization", allowing optimization in terms of both cost and duration optimization. Planners are able to optimize drilling plans according to the performance of the execution of the strategic objectives, which allows for taking the corrective actions on time and avoiding potential planning risks.

As a conclusion the eWDP provides a local knowledgebase for the practices ADCO follows in the well delivery process, setting the basis for optimizing the overall business performance in alignment with set goals.
Sweetening and Sulfur Recovery of Sour Associated Gas and Lean Acid Gas in the Middle East
Authors: Hauwert Peter
Published: December 2014

With increasing numbers of remote fields of a small-to-medium sulfur load (1-100 tpd S) starting to produce in the Middle East, the demand has arisen for sulfur recovery processes that operate safely and reliably at this scale. While several processes have been presented in the last two decades, some doubts exist with operating companies on the reliability, the operational simplicity and flexibility regarding inlet conditions. In this paper, several processes are compared qualitatively for desulfurization of associated gas. Specifically the applicability of the Thiopaq O&G bio-desulfurization process for treatment of associated gas in the Middle East is investigated in more detail.

The Thiopaq O&G process combines sweetening and sulfur recovery of gas streams containing H2S (50 ppmv-100% vol.), and is relatively insensitive to fluctuations in feed flow, pressure and H2S concentration. Because of this robustness, it is ideally suited for treatment of sour associated gas, as the composition and flow vary more than that of typical natural gas or amine tail gas feeding Sulfur Recovery Units (SRU). Besides associated gas, the broad range of suitable H2S concentrations makes it also very interesting for sulfur recovery from lean acid gas streams.

As a large part of the world's sour associated gas is found in the Middle East, the influence of a desert environment on this ambient temperature process using bacteria is further investigated. Plant data are presented that underline the operational stability of the process. Also the simple engineering measures taken to apply this process in a desert environment (hot, arid, limited operators) are presented, along with the economic impact of these measures. Finally, a typical design of a sour associated gas treatment process is shared. In conclusion, the Thiopaq O&G process is a highly suitable solution for desulfurization of sour associated gas sources in (sub)tropical and desert climates.
Role of Integrated Asset Model in Selecting an Optimum Development Scenario and Assessing Uncertainty of a Multilayered Rich Gas Condensate Reservoirs – A Case Study from ADCO Fields, UAE
Authors: El Bahri Sami , Al-Shaarawy Osama , Chouaibi Mohieddine , Torrens Richard , Ghorayeb Kassem
Published: December 2014

For a field development planning (FDP) study of a multilayered, thin, and relatively tight, rich gas condensate reservoir in an Abu Dhabi Company for Onshore Oil Operations (ADCO) field, integrating surface and subsurface elements provided more accurate accounting for the backpressure impact of the production system on the reservoir than is traditionally achievable using standalone reservoir simulation. The backpressure response is a critical factor that must be properly taken into account when modeling multilayered rich gas condensate reservoirs when an early water production is expected.

This gas condensate field is located an environmentally sensitive area, which has dictated a shallow water and onshore strategy to minimize the number of drilling facilities. The development wells will be drilled from several well pads (up to six) located in both shallow water and onshore.

The integrated asset model (IAM) has three components: the reservoir simulation model (built using a compositional finite difference simulator), the well models, and the surface network model (built in a steady-state multiphase flow simulator). The individual models were linked together within a production operations software platform that enables dynamic linking and controlling of the various packages.

Several development scenarios (43) were used to investigate the impact of the following sensitivities on field performance: production phasing, separator sizing, flow assurance, well tubing and flowline sizing, and compression. The IAM was also used to facilitate the economic evaluation for each case. The ultimate objective of the IAM is to select the optimal FDP for multilayered rich gas condensate reservoirs.