bluuebunny/crossref_metadata_2025 huggingface dataset:
A New ICD/ICV Well Completion Design Optimizer and Well Management Logic for Full Field Reservoir Simulation with Multiple ICD/ICV wells
Authors: Li D. , Alobedli A. , Selvam B. , Azoug Y. , Obeta C. , Nguyen M. , Al-Shehhi B. H.
Published: November 2017

In the current practice, ICD/ICV design parameters (e.g., number of compartments, compartment size, number of nozzles, and nozzle sizes) are optimized by a manual trial-and-error approach that requires tens to hundreds of iterations. To make the design process efficient and effective, an automated optimizer is desired. In addition, as more and more ICD/ICV wells are completed, reservoir simulation faces a challenge on how to efficiently run full field models with multiple ICD/ICV wells. This paper presents a new automated ICD/ICV design optimizer and an efficient way to run full field reservoir simulation with hundreds of ICD/ICV wells.

The new optimizer uses oil recovery efficiency as its objective function. The optimizer works on injectors and producers separately. For injectors, the optimizer adjusts the packer locations, number of nozzles, and nozzle sizes to make the injection velocity along the wellbore as uniform as possible to ensure a uniform injection front. For producers, a five step optimization process is applied. Step 1 is to generate injected fluid flow travel times in 3D from injectors to producers and all major flow "highways" are identified. Step 2, the optimizer uses fluid travel times in a producer to automatically estimate number of compartments needed and adjust the compartment boundaries (packers) to match the "highways" identified, estimate number of nozzles needed and initial nozzle sizes to maximize oil production rate. No reservoir simulation is required in steps 1 and 2. Step 3 is to run a full field reservoir simulation with all design wells to tune and achieve the final nozzle sizes. Step 4 is to QC and analyze the results of all ICD/ICV wells and select all successful candidates for the final step, i.e., step 5 reconciliation of the designs with all other drilling/completion constraints. The optimizer is fully supported by the efficient well management logic which accurately and efficiently links ICDs/ICVs with reservoir simulation. Using the well management logic removes the needs of coupling between well simulation tools (e.g., NETool) and reservoir simulation software, and then makes full field simulations efficient.

The new optimizer and well management logic have been applied and demonstrated significant values in a giant oil field in UAE. Compared to the traditional one-well-at-a-time well design, the new optimizer optimizes multiple ICD/ICV design wells at a time and results in better and faster designs with speedups in a range of several factors to an order of magnitude. The optimization is global and within the context of full field model. Running 370 ICD/ICV wells with the well management logic for a multi-million-cell reservoir simulation model only slows down the full field simulation around 10%.
Slim-hole Straddle Packer Microfrac Testing and Tectonic Stress Calibration in UAE Carbonate Reservoirs
Authors: Franquet J. A. , Smith S. S. , Noordin F. B.
Published: November 2017

The development of Lower Cretaceous reservoirs in a mature field located 84 km southwest of Abu Dhabi required a series of stress measurements across the reservoirs to tectonically calibrate the 3D Geomechanical model. The stress measurements were acquired by multiple straddle packer microfrac tests conducted through pipe-conveyance in a slim openhole wellbore. Various pore pressure depletion conditions across the reservoirs make the deployment of straddle packer tools in slimholes a very challenging operation.

Five in-situ stress measurements are acquired in this study from the proper identification of fracture closure pressure after reaching the formation breakdown pressure. Each microfrac test consists of three pressurization cycles and three pressure decline (fall-off) periods after fracture propagation. The fracture closure identification is achieved using three different pressure decline analysis methods on each fall-off test: (i) square-root of time, (ii) G-function and (iii) Log-Log plot. The final fracture closure measurement is obtained after consolidating the three fracture closure identification results in all three injection cycles conducted on each microfrac station.

The Microfrac tests conducted in the vertical pilot borehole provide precise in-situ measurements of formation breakdown, fracture reopening, propagation and closure at multiple reservoir layers. These in-situ measurements provide an accurate present-day stress profile across the reservoirs for constructing a proper 3D geomechanical model of the field. These microfrac tests measure minimum horizontal stress gradients of approximately 0.66 to 0.76 psi/ft, confirming the normal faulting stress regime in these reservoirs. The tectonic stress calibration is obtained by adjusting the value of tectonic strains across the reservoirs until the log-derived minimum horizontal stress matches the fracture closure pressure from the microfrac tests.

These in-situ stress measurements provide the subsurface information required to fully calibrate the tectonic stress acting on the reservoirs. This tectonic stress calibration is needed to create a representative 3D geomechanical subsurface model to predict accurate subsurface responses to stress and fluid flow over the field development. Additionally, conducting microfrac tests in slimholes provides multiple acquisition benefits: the straddle packer tool tolerates higher differential pressure across the elements than in large borehole, achieving higher absolute bottom hole pressure to induce formation breakdown; the borehole induced stress zone is radially smaller compared to larger hole sizes; the induced fracture does not required excessive propagation away from the borehole in order to capture the far-field in-situ closure stress.
Safer, Faster and Efficient Operations Through Operation Offline Stand Building: A Case Study
Authors: Belbaraka Chaima , Abd Elnaby Osama
Published: November 2017

Drilling industry is renowned to be one of the dangerous occupations with numerous catastrophic incidents that lead to significant fatalities, loss of assets, and impaired corporate reputations and businesses. There have however been significant strides in recent years after the 2010’s Gulf oil spill event, to improve operational efficiency and personnel safety. In response to the stringent safety protocols and industry’s increasing focus on operational safety and efficiency, significant improvements have been made in towards mechanization of pipe handling operations. These advancements have tackled some of the most laborious and imperative drilling operations; namely, pipe handling, tripping and making connections. This paper will describe in detail the adaptation of offline stand building system on island rigs fleet as a mitigation measure towards some HSE incidents from pipe handling habits of rig crew. The adaptation will illustrate a comparative study that has been made to two vendors systems and criteria entailed to choose the best-fit system design in a case study.
Impact of Change in Reservoir Dynamics and ESP Installation on Subsea Pipeline System
Authors: Selvam Rajendran , Qambar Najem A , Shebli Adnan Al , Bufalah Salah Jebara , Ismail Jawed , Singh Devinder , Panambur Sandeep
Published: November 2017

It is a known fact that reservoir characteristics are never the same and have always been continuously evolving and changing either because of natural factors or due to sustained water and gas injection activities to meet the target production. Changes are not only observed in crude chemistry but also with regards to fundamental pressure, temperature and quantum of formation water, considered as among the most important and critical parameters affecting the design and layout of any surface facilities and subsea infrastructure such as existing and new pipeline networks including the downhole system. To meet and balance this ever-growing short term and long term demand for production, it has always been a common practice to install ESPs (Electrical Submersible Pumps) as it serves the intended purpose. Parametric studies have shown that drawing flow through ESPs have affected the integrity and life of existing infrastructure particularly "subsea pipeline network". Therefore, efforts have been made in this paper to highlight the extensive study that has been carried out in assessing the unprecedented damage caused to one of the subsea oil pipeline including capturing the business risk it has imposed. Further details of evaluation of several mitigation options have been presented trying to bringing down the corrosion but also actions taken towards securing a permanent long term solution.
Kuwait's First Successful Implementation of MPD in Deep Jurassic Reservoirs of Abdulyiah Field in West Kuwait
Authors: Al Moraikhi Rasha , Kulkarni Nitin , Patil Dipak P. , Sounderrajan Mahesh , Verma Naveen K. , Quttainah Riyad , Al-Kandari Eman , Al-Mohailan Mohannad
Published: November 2017

Jurassic Reservoirs in Abduliyah field of West Kuwait are characterized by abnormal pressure variation within and across Jurassic formations, which cause profound drilling problems such as well kicks and mud losses resulting in increased drilling time, cost and materials in addition to reservoir damages.

The development of Najmah –Sargelu (NJ/SR) unconventional fractured reservoir requires drilling through high-density fracture swarms to ensure well productivity, which in many instances result in "alternate loss & gain scenario," occasionally, making the well control options limited. On the other hand, drilling through Marrat section encounters drilling difficulties such as mud loss and differential sticking in depleted middle Marrat layers juxtaposed to high-pressure layers of upper intervals. Keeping the above problems in mind, Managed pressure Drilling (MPD) was applied first time in both 9-1/4″ NJ-SR & 6-1/2″ Marrat reservoir sections in a deviated well of Abduliyah field. The Use of MPD in this well offered several advantages and improvements in drilling and completion performance as given below:

Reduction in Operation Time: Successfully drilled through Base Gotnia, Najmah-Sarjelu & Marrat Formations to Target Depth smoothly without any Non-productive Time (NPT)

Down hole problem avoidance: No downhole complications experienced during drilling to Target Depth.

Implementation of new casing design: Drilled Najmah-Sarjelu, Dharuma, Up. Marrat and Upper part of Middle Marrat in the same section for the first time in Abduliyah field which allows future re-entry sidetracking using 6 ½″ horizontal wellbores to enhance productivity for cost-optimal development of NJ-SR & Marrat reservoirs.

Reduction in drilling fluid density: The sections were drilled with lower drilling fluid density by 1.5-2.0 ppg resulting in optimum overbalance pressure to avoid formation damage while reducing the risk of differential stuck pipe, with savings in mud cost.

Health Safety & Environment (HSE) Improvement: The MPD sections were drilled without any incident indicating improved HSE performance.

Reduction in overall well cost: Significant cost reduction was achieved by using MPD for drilling the sections.

The paper aims to share the successful case study of drilling through Jurassic reservoir sections of Abduliyah deviated well using MPD technology along with lessons learned and benefits for its future implementation in similar wells across all KOC assets
Optimized Engineering Under Current O&G Industry Scenario
Authors: Moro Sudhakar , El-Sawah Mohamed , Shabaka Ashraf , Mentheri Ibtihaj Al
Published: November 2017

Abstract: Optimized Engineering under current O&G scenario:

Context

Optimization, price reduction, efficiency, leaner, fit-for-purpose, etc., are the buzzwords doing the rounds in any Oil and gas Industry meet nowadays. Automation by means of well-engineered Instrumentation and Control is a major asset in any production facility. This papers raises awareness on how optimization can be achieved in Instrumentation & control items during detailed engineering, without compromising on safety and operation requirements of any O&G asset.

Objectives/Scope

The current market scenario mandates the need to discuss and understand the various cost saving or value engineering items related to O&G industry. It is only wise that when the best of experts in industry meet, we deliberate on same. During the presentation, we would like to instigate the participants to a healthy discussion and finally carry forward a list of major cost savers in Instrumentation and control, which could be implemented in O&G projects.

Methods and Processes

Automation through state of the art technology is still the best bet for optimization and economics of operation and maintenance in Oil & Gas industry. However the methods and processes of below optimization items need stringent review prior to implementation. The brown field projects have various challenges of structural extension, weight concerns, Power, Utility adequacy, huge barge costs, etc. Is it not time we had strict gates during design stage and include only the mandatorily required equipment and cut away the frills.

Package type equipment like Flare system, Compressors, Electro chlorination unit, etc. which are vendor specific design is another vast area where good optimization can be worked out. Footprints can be optimized leading to major reductions in project cost.

Results, Observations, Conclusions

Optmization in Instrumentation items always have a chain effect on other areas like power, cable, spares, replacement throughout the lifecycle of the plant, etc. The resultant list of cost savers will be much longer definitely. To conclude we recollect one old quote "Beware of little expenses, a small leak will sink a great ship" and we propose to reevaluate our basis of design and justify every expenditure.

Novel/Additive Information

During the presentation we want to kindle the out of box thinking, for novel and innovative but safe ways to save every dirham in our business today.
Pressure Build-Up Test Interpretation Studies: Models, Numerical Simulation, and Field Test in the Huabei Oilfield
Authors: Miao Y. , Li X. , Zhou Y. , Li H. , Shi J. , Chen Y.
Published: November 2017

Accurate pressure build-up test interpretation technologies for both conventional and unconventional reservoir development have been highly applied in oil and gas industries in recent years. However, for the late development stage of wells, current well test interpretation methods lose their accuracy to characterize fluid flow behavior and fracture properties etc. due to the complex underground situation and interference among adjacent wells. Novel pressure build-up test interpretation methods should be developed with the incorporation of these effects.

We developed a novel model to interpret formation pressure and formation physical properties, during the process of pressure build-up test, by incorporating stress interference among adjacent wells and two-phase flow of oil/water directly into the model. Trial approach was utilized to iteratively correct average formation pressure and permeability of oil and water phase, depending on the complexity of well interference systems. A simulation was developed based on this semi-analytical model which is capable of interpreting formation pressure and formation physical properties during the process of pressure build-up with much higher accuracy compared with traditional methods.

A numerical simulation in Eclipse was utilized to validate our model. Our interpretation results, including formation pressure, skin factor and permeability etc., are in fair agreement with the numerical simulation. We applied our model to conduct pressure build-up interpretation tests for testing wells in the Huabei Oilfield, and the precision of our model can reach up to 35.15% which has greater accuracy compared with traditional methods.

This novel model exhibits high efficiency and accuracy for pressure build-up test interpretation for the case with interference among adjacent wells and oil and water two-phase flow. This work provides an effective framework for pressure build-up test interpretation in fractured reservoir development.
Building Synergies, Strengthening Fundamentals, and Driving Leadership in Investment Decision Process within Petroleum Fields
Authors: Kenzhetayeva Z. , Fleming R.
Published: November 2017

Objectives/Scope

Development of the oilfields today contains significant complexity owing to competing technical, commercial, and risk requirements, requiring smart investments to yield positive returns. Tougher capital allocation and sustained low prices expose reservoirs' challenges, countries' risk and contractual issues bringing into a spotlight shortcomings of the decision-oriented process used by shareholders. The current paper presents a balanced approach to reduce overconfidence and bias in decision-making, strengthen financial position to meet new investment thresholds, and maximize the value from existing operations to sustain the ventures through a turbulent time.

Methods, Procedures, Process

The overall methodology represents a structural process for option evaluation and selection, providing end-users with the unified toolbox including visualized framework, recommendations, decision trees and diagrams. The proposed method 1) balances intuition and rules of thumb with conventional capital-budgeting methods and quantitative modeling, 2) supports an investment decision process focusing on implications of different sets of decisions, 3) applies probability theory with emphasis on the concept of expected value (EV), 4) detects areas to reduce risk and develop economic opportunity cost of capital, 5) finally, helps to form an understanding of different project variables, their interdependencies and influence on the overall result.

Results, Observations, Conclusions

The case study suggests that the initial set of decisions required an evaluation of 100 alternatives with hours of manpower and computer runs per outcome. By pairing down some of the constraints, we were able to generate a solution with 35 outcomes. This data was used to build technical scenarios and screen options in terms of economic attractiveness and ability to sanction. The 5 workable solutions with the highest ability to deliver value were scrutinized to select a development option. Further simulation has advised on specific areas that should be progressed to optimize the selected strategy, resulting in a reduction of upfront expenditures by 20% from the initial threshold and potential to deliver financially 43% of NPV growth, making a protracted and laborious process much simplified and rational.

Novel/Additive Information

The novelty of the concept is in its ability to tackle complex disparate issues by being a holistic and balanced in nature as well as equally efficient at different stages of a project. This allows an early focus on areas that have a genuinely significant impact on project commerciality. The findings will stimulate new progress - streamlining of proposed practice is key to drive robust engineering decisions in petroleum industry and enhance the value of decision process making it more flexible and accurate, and thus more attractive.
Evolution of the West Alboran Basin, Mediterranean, Offshore Morocco: Implications for Hydrocarbon Prospectivity
Authors: Aitken John F. , Beach Alastair , Al-Mansoori Khalfan
Published: November 2017

The West Alboran Basin, lying in the westernmost Mediterranean between Morocco and Spain, contains a thick (≥ 10 km), Tertiary sedimentary fill with abundant structures and excellent coverage by vintage 2-D seismic datasets. There are good indications of a working petroleum system yet the basin is highly under-explored with only a single well on the Moroccan margin and three wells offshore Spain.

It is a young basin (at oldest, latest Oligocene) and lies between the Betic and Rif fold and thrust belts, part of the Gibraltar Arc. The West Alboran Basin has typically been interpreted as a back-arc basin, however, by integrating all available data, it is proposed that it is more probably a fore-arc basin.

Hydrocarbon seeps from mud volcanoes indicate the presence of thermogenic hydrocarbons. Biomarker analysis suggests oil-window maturity of the oil seeps, indicating a Lower to Middle Miocene source. Although there is strong evidence for the presence of a mature oil source rock, the areal distribution, quality, age and type of the source rock remain largely unknown. Basin modelling suggests that the Middle and Lower Miocene are mature and capable of generating substantial hydrocarbons. The distribution of suspected oil seeps is best matched by a Middle Miocene oil-prone source while biogenic gas migration modelling results in a good match between predicted pools and known gas seeps.

Potential reservoirs are interpreted to comprise the deposits of various deep water environments, including turbidite fans, turbidite channels and mass transport complexes. Seismic geometries suggest the presence of such features.

Numerous leads at various stratigraphic levels have been identified. The majority of these are related to mud diaper traps but, in addition, a few 4-way dip closures as well as several stratigraphic trapping configurations also occur. Overall, the well-developed structures and good indications for a working petroleum system mean that the West Alboran Basin has significant potential as a new hydrocarbon province. The next logical step is to acquire high quality 3-D seismic data to further derisk the basin.
Electric Submersible Pump Performance and Numerical Modeling in Two- Phase Flow
Authors: Rutter Risa , Ye Zheng , Lack Ryan
Published: November 2017

Differential pressure (DP) between stages of multi-stage diffuser type centrifugal pump of an electric submersible pump (ESP), system was measured in a two-phase flow environment. The test results were used to improve existing numerical models and bubble size models for better prediction and to improve the design process. This paper details the comprehensive testing and model validation process for ESP pump stages.

Various sizes and types of ESP pump stages were tested in a high-pressure two-phase flow loop. Each stage performance was monitored using high-precision DP transducers. Test results were used to calibrate numerical simulation in two-phase flow. The correct bubble size for individual test conditions was calculated based on the test results. The bubble size calculation was crucial for good model prediction in two-phase flow. After several types and sizes of ESP stages were validated, same bubble size model could be used on other pump stages that have similar sizes and designs.

Presented in this paper are the actual gas volume fraction (GVF) handling capabilities of typical ESP stages, including the effects of flowrate, GVF, pump speed, inlet pressure, flow mixing and inlet/outlet effects.

After the lab test was complete, computational fluid dynamics (CFD) was used to investigate the hydraulic performance of the same stages and conditions tested in the lab. Simulation results were compared with test results and optimized for the correct bubble size of the secondary phase. The current bubble size model predicted very well for the lower GVF combined with large flow rate pump. The low flow pump had DP errors in excess of 10% for GVF values over 40%.

The validated numerical model can be used to improve pump modeling and enable improvements in pump design that could increase the gas-handling capabilities of pump stages of similar size and styles.
Implementation of a Successful Talent Management & Succession Planning Governance Framework
Authors: Khare Naveen , Koyadan Santhosh
Published: November 2017

Objectives/Scope

It is crucial for an integrated talent management and succession planning strategy to have close ties to organizational strategy and buy-in from the senior leadership. However, often the onus of applying these processes lies solely with the human resource function thereby not involving the line managers in the process. The purpose of this paper to present a best practice model to effectively integrate management personnel in the talent management and succession planning framework thereby fully utilizing them in ensuring optimal development of the talent pipeline.

Methods, Procedures, Process

In order to make the senior leadership active stakeholders in driving the process, we instituted ‘Talent Review Committees (TRC)’ at various levels to drive Talent Management and succession planning. The brief structure and role is as follows:

ADNOC Group level - chaired by ADNOC Group CEO with all Directors as members. Key positions considered - Directors and Group Company CEOs

Directorate level (one per directorate) - chaired by the director with all related group company CEOs as members. Key positions considered - SVP & equivalents

Group Company level (one per group company) - chaired by the Group company CEO with all SVPs as members. Key positions considered - up to VPs and technical positions

These committees review and approve the key positions, select potential successors, review their level readiness and recommend and monitor development activities. The output of these TRCs is combined at the corporate level to deliver a coherent talent management solution.

Results, Observations, Conclusions

Since ADNOC is a group of independent companies it is necessary to unify the talent management strategy in order to have a group-wide talent pool so that the need for capable leaders and specialists across the Group is continuously met. Multi-level governance structure to drive the talent management and succession planning process helps us in efficient identification and utilization of talent, making succession planning effective and accurate. The key results and conclusions are as follows: Identification, assessment and development of group-wide pools of internal candidates to improve their readiness to compete for future openings in key positionsAvailability of qualified successors and improved readiness & performance in target positionAccurate data availability to facilitate cross function/ company mobility and development opportunitiesEnsure that leadership continuity is in place and that strategic and operational capacity is sustained.

Novel/Additive Information

The paper offers an insight into the framework of multi-level talent review committees (TRCs) instituted across the ADNOC group as an effective model for integrating senior leadership into the talent development and succession planning framework.
Resolving Shale Drilling Instabilities in the Middle East: A Holistic & Pragmatic Geomechanical Method
Authors: Singh Hemant , Yadav Prahlad , Imtiaz Saad , Perumalla Satya
Published: November 2017

In the Middle East, a significant amount of Non-Productive Time (NPT) has been associated with controlling wellbore instability caused by weak shale before reaching the reservoir. Due to limited availability of pad locations and complex well trajectories, operators are now forced to drill high angle wells through shale as compared to vertical or low angle wells in the past. This has resulted in a substantial increase in drilling complications in terms of controlling shale instability.

Comprehensive geomechanical studies from various fields of Middle-East have helped to determine most plausible root causes of shale rock instability and to draw a holistic geomechanical approach to solve the problem. Shale samples (core and cuttings) were collected from multiple fields, and various types of lab tests were performed on these samples including XRD, XRF, chemical tests, rock mechanical tests etc. Geomechanical modeling and drilling analysis were performed to compare the drilling events to the shale characteristics in order to determine the mechanisms of rock failure. Chemoporoelastic and plane of weakness modeling techniques were also performed to understand some less-common failure mechanisms that were driving instability within these shales.

It was noted from the analysis that not all shales behave in a similar fashion. A potential solution that may solve instability problem in a particular field/region might not be effective in the other field/region. Geomechanical analysis suggested that a range of shale instability mechanisms ranging from stress induced failures and planes of weakness to complex rock-fluid interaction were responsible for hole instability, and different mud and drilling parameters are required to keep the hole stable in different shales. Raising the mud weight exclusively during drilling of these shales with multiple failure mechanisms was found to be ineffective and potentially counter-productive. A customized solution along with real-time geomechanics monitoring can help to mitigate shale instability in drilling of high angle wells.

A customized methodology for shale stability has been proposed in this paper based on integrated mechanical and chemical characteristics of most commonly encountered shales in the Middle East. This approach has helped to devise a comprehensive as well as practical approach to enhance drilling efficiency through shales in various fields in the region.
Development of Novel Foaming Agents for High Temperature Steam Applications
Authors: Sanders Aaron , Nguyen M. N. , Ren Ginger , Westemoreland Dana , Nguyen Quoc , Dong Susan , Rojas Carolina
Published: November 2017

The development of a new class of surfactants for high temperature steam foam applications has been investigated using both a new bulk foam screening test and core testing in the presence and absence of bitumen. A new screening methodology utilizing a high pressure cell fitted with viewing windows is described. Data is presented for the initiation and degradation rate of bulk foams for a number of surfactants at 190°C and 250°C.

Two surfactants Agent X and Agent Z were examined in core flood in the presence and absence of bitumen. At both 190°C and 250°C, the foaming agents were capable of creating stable foam. Core flood results in ~15 D sand pack at 250°C show that in the absence of bitumen, Agent X and Agent Z were capable of creating apparent foam viscosities of 3.9 and 17.7 cP, respectively. In the presence of bitumen the foaming ability was decreased, but foams created by both surfactants still maintained apparent viscosities of >1 cP. Both surfactants produced foams that have shown shear thinning behavior under the conditions tested. Potential applications for high temperature foams are discussed in light of the results.
Quantification of Oil Recovery Mechanisms during Gas Injection EOR Coreflood Experiments
Authors: Wanat Ed , Teletzke Gary , Newhouse Dan , Lawrence John , Shehhi Rashed Al , Willingham Thomas , Jawhari Mohammad Omar
Published: November 2017

This paper presents results of gas injection enhanced oil recovery (EOR) core flood experiments to highlight mechanisms of oil production throughout the life of an EOR project. The relative contributions of vaporization and condensation/swelling production mechanisms are quantified by analyzing the compositional results of a series of gas flood experiments conducted with live fluids at reservoir temperature and pressure and a variety of gas injectants including CO2 and various hydrocarbon gases. The compositional information is useful for calibrating tuned equation of state (EOS) and gas flood simulation models, thus enhancing confidence in field-scale performance predictions.

When analyzing results from such gas floods, care must be taken to properly account for changes in oil composition. Using the black oil assumption, the composition and formation volume factor (FVF) of the oil produced throughout the gas flood is assumed to be constant. The consequence of this assumption can lead to inaccurate estimates of oil recovery. To overcome the limitations of the black oil assumption, we introduce a rigorous methodology to account for changes in oil composition. A tuned 10-component EOS, is used to reconstruct the produced fluid compositions, measured at laboratory conditions, back to reservoir conditions. Conversion of detailed oil composition measurements to the 10-component compositions used by the EOS while honoring the weight fraction composition measurements is accomplished using a gamma probability distribution function.

As expected, gases with lower minimum miscibility pressure (MMP) recovered a higher percentage of remaining oil in the core. In addition, the reconstructed reservoir-conditions compositional data revealed especially useful information for understanding the physical processes involved in oil recovery. The weight fraction of produced components as a ratio of the weight fraction of that component present in the original live oil was especially illustrative. Significant differences in the relative contributions of the vaporization and condensation/swelling mechanisms were observed depending on how close the reservoir oil was to its saturation pressure. Finally, results of history matching the gas flood experiments using compositional simulation confirm the results seen in the laboratory data.
Unlocking Bypassed Oil in Mature PDO South Oilfields by Developing Gharif Low Resistivity Pay
Authors: Mahaldar S. , Mandhari S. , Jorgensen W. , Busaidi H. , Saadi H. , Yaarubi A. H.
Published: November 2017

PDO has a large portfolio of mature Gharif fields with significant hydrocarbon potential to be unlocked by efficient well and reservoir management (WRM). In 2016, focussed surveillance on Closed-in Wells (CIW) in a mature PDO South Gharif field, highlighted significant bypassed oil opportunity in Low Resistivity Pay (LoRP) reservoir –"C". Presence of conductive minerals and different clays in the LoRP sands, led to a pessimistic assessment of resistivity based hydrocarbon saturation. As such, histrocially, these oil bearing sands were not perforated. LoRP was production tested in 2 CIW & 3 New Oil (NO) wells in 2015, doubling field's net oil production (Figure1). Insights from historical field production, pressure depletion, core and Nuclear Magnetic Resonance (NMR) data were integrated to update the static subsurface model which led to an increment of 21% in the field STOIIP.

Current inventory of high water cut (>95%) and high sand producing oil producers are being converted to dedicated LoRP producers on opportunity basis. This has reduced the frequency of expensive well workovers. Quick screening of LoRP has been initiated for all PDO South fields. Initial results show that similar bypassed oil opportunities exist in other mature brown PDO South fields as well. Broadly speaking, such bypassed oil opportunities can be attributed to one of the following subsurface mechanisms at play i.e. presence of thin sand- shale intercalations which are not vertically resolved on wireline logs, presence of condutive minerals e.g. pyrites or clays and high irreducible water saturation in microporous rocks.

With the current low oil prices, re-exploration of mature fields by interpreting and maturing low resistivity pay reservoirs, presents an attractive business proposition.
Corrosion Control in Sulphur Recovery Units – Claus Process
Authors: Alkasem A. , Slavens A. , Dhinda H. , Berrouk A. S.
Published: November 2017

Today there are more than 100 Sulphur Recovery Units in the Middle East and many of them have been in operation for 10 years or longer. Corrosion can be one of the most challenging issues in these units due to the presence of hydrogen sulfide, sulphur dioxide, elemental sulphur and water. If operated within the normal operating temperature range, corrosive conditions should not occur; however, if upset conditions result in temperatures which are too high or too low, several corrosion mechanisms are possible. This issue has resulted in many instances in which existing units have been forced into emergency shutdown for several days to perform maintenance. This results in production loss and the potential for significant environmental impact due to flaring acid gases.

API 571 documents most of the major corrosion mechanisms in the Claus process such as sulfidation, oxidation, flue gas dewpoint corrosion and wet sulphur corrosion. However, it does not address specific means of controlling corrosion, taking into account different technologies available for tail gas treatment.

This paper demonstrates the fundamental corrosion issues encountered in SRUs and proposes protective actions. Guidance related to start-up, shutdown and normal operation is also provided for establishing appropriate operating limits to achieve safe and reliable operation for corrosion avoidance.

This paper takes a unique approach which considers both theoretical and practical, real-world experience in the mitigation and monitoring of corrosion control. Operators are provided with tangible recommendations that can be applied to their facilities. Protection against atmospheric corrosion is not in the scope of this paper.

This paper has been prepared based on a review of several industry publications, which address specific corrosion mechanisms in SRUs. The main objective of this paper is to provide a high-level overview of these works, while also offering guidance on the safe operating envelope of the facility, to avoid excessive corrosion. Most of the metallurgy in an SRU is typically specified as carbon steel, which is adequate when the unit is operated within safe operating limits. However, if operated outside the acceptable range (above or below), corrosion can be swift and severe, as will be described.
Delineation of Fracture Clusters by Integrating Tectonic Events, Seismic Attributes, BHI Interpretation, Mud Losses during Drilling and Well Test Data – A Case Study in a Carbonate Reservoir, Offshore Abu Dhabi
Authors: Hou Lian , Lavenu Arthur P. , Xi GuiFen , Al-Kaabi Ahmed Saeed , Van Kleef Franciscus , Lecoq Thierry Francis , Al Blooshi Asma Mohamed
Published: November 2017

Faults and fractures play an important role in reservoir production, since they can act either as barriers or conduits for fluid migration. They are also one of the key factors to be considered for drilling trajectory design. However, it is very challenging to delineate fractures due to the limitation of seismic resolution. The objective of this study was to conduct fracture cluster characterization for one of the carbonate reservoirs in Abu Dhabi, using a recently acquired 3D seismic survey.

In this study, the similar workflow used by Singh et al. (2009) was followed. First of all, structural evolution and regional paleo including current principal stress orientations were investigated. Three major tectonic events were identified, and they are the main contributors to the development of faults and related fractures. Secondly, seismic data was processed based on an objective-driven processing sequence. Three fracture volumes were generated and five sets of fractures were interpreted. They were validated against the regional principal stress orientations, BHI interpretation, mud losses and well test data.

In addition, previously the discontinuities along NNE-SSW direction in the area of interest were considered as seismic acquisition footprints. Through this study, it was proved that those discontinuities are small scale faults, hereby enhanced the existing reservoir characterization.

The findings on faults and fractures characterization in the study area are critical in field development plan and drilling efficiency. This study showed that integrating data from different disciplines is a reliable and effective way to delineate fracture clusters.
Acquisition of Satellite Derived Bathymetry Data for Offshore Engineering Projects - Island Case Study
Authors: Athmaram Jayaprakash , Srinivasan Ashish GS
Published: November 2017

Recent advances in satellite technology such as improved image resolution and use of multi-spectral bands have increased its potential as an alternative source of hydrographic data. Recent applications in the surveying industry have proved the usefulness of Satellite Derived Bathymetry (SDB) as a low cost source of good quality bathymetry data. In order to support ADNOC's efforts to fast track new field development projects and timely delivery of high value data, ZADCO as part of its survey campaign selected SDB as a tool to source quality near shore hydrographic data.

Offshore bathymetry derivation was realized using WorldView-3 satellite scenes. These scenes were processed by following a rigorous processing methodology for the correction of atmospheric adjacency. The processed and corrected satellite image provided a spatial resolution of nearly four metres and covered depths from the 0m depth contours up to the 15m depth contours. The accuracy and reliability of the satellite images are dependent on the optical conditions of the satellite scene, the sensitivity of the satellite's sensor and the accuracy of the calibration.

After detailed multi-level quality checks for various systematic and non-systematic errors, the most reliable bathymetry that was found to meet ZADCO selection criteria was noted to be between 0m and 3m water depths, with an error of ±0.3m. Water depths between 3m and 5m presented themselves with an error of ±0.4m, whereas for depths between 5m and 10m, the errors varied between 0.5m to 1.0m. It was found that in the extreme nearshore areas with depths between 0m and 3m water depths, SDB could be accepted for use as it was falling within the tolerance limits of ±0.3m, with most areas having a tolerance of ±0.2m. While satellite derived bathymetry between the 0m to 5m water depths was found to be of acceptable quality, those over drying heights were found to be completely unreliable.

The reliability factor that could be established for SDB data between 0m and 3m implied that dangerous and logistically challenging nearshore survey operations using conventional methods, that is, using shallow draught survey motor boats could be done away with. This also presented an interesting corollary in that it can also remove a huge HSE risk factor associated with shallow water survey boat operations, which are otherwise a significant risk due to the presence of underwater obstacles such as corals, rocks, reefs and surface dangers such as wave action and tidal influences.

In conclusion, high resolution multi-spectral satellite imagery corrected for atmospheric and underwater refraction effects combined with the correct processing techniques and multi-level quality control mechanism provides a reliable source for bathymetry in extreme nearshore areas. Based on the results achieved it was concluded that SDB data can be used for engineering planning and estimation applications, for quick turnaround.
Hybrid Multi-Stage Acid-Fracturing in Deep Carbonate Gas Wells with HTHP in Anyue Gas Field of Sichuan Basin, SW China
Authors: Suzhen Li , Yun Xu , Yujin Wan , Mingguang Che , Liao Gao Yuebin , Zhanwei Yang , Rui Gao , Xinwei Lu , Lang Zhou , Yezhong Wang , Weihua Chen , Hao Zhou
Published: November 2017

The naturally fractured Anyue Gas field contains Longwangmiao (Cambrian) and Dengying (Sinian) formation. The oldest age formations were formed large-scale marine carbonate gas reservoirs with buired depth from 4500m to 5500m, temperature of 150°C and pressure coefficient of 1.6. Approximately one-third of wells cannot reach the economic production because of serious reservoir heterogeneity; therefore, a novel hybrid acid-fracturing technique was applied to enhance the gas production by increasing stimulated reservoir volume. Hybrid multi-stage acid-fracturing technique was used to the reservoirs with poor connectivity between vugs and fissures. Large quantity slick water with 100 mesh proppant as pad was injected with high pump rate to reduce sand plug risk and form shearing fractures,and then ground cross-linked acid and gel acid were injected alternatively to corrode the fissures far away wellbore to form fracture network.

It is the first time that hybrid multi-stage acid-fracturing technique was used to stimulate the low permeability and low porosity carbonate gas reservoir with poor connectivity between vugs and fissures in China. The introduction about this technique will provide some reference for the stimulation design in the similar reservoirs in spite of the non-ideal stimulation result.
Forty Years of AlMansoori Focused Workforce Engagement. A Catalyst for Customer Value, International Growth, Profitability with Happy Clients and Happy Employees!
Authors: Al Alawi Ibrahim , Kuijken Chris
Published: November 2017

This paper describes the successful staff engagement strategies underpinning the leadership and continuous transformation journey of the 100% UAE Company AlMansoori whereby a slickline services start-up company in the year 1977 in only one geographical location (Abu Dhabi) transformed into a large conglomerate covering upstream and downstream businesses in oil, gas, chemicals, manufacturing and supporting services.
Offshore Pipeline Failure Root Cause Analysis
Authors: Iyeh Emmanuel , Adams Grant
Published: November 2017

Objective/Scope

The objective of this study was: ▪To evaluate potential causes of failures of several (9) pipelines operating in shallow waters 8m to 14m water depth in the Gulf of Guinea and develop an analysis / programme to identify the root cause of failure.▪Perform analysis to confirm the causes of failures,▪Assess remedial measures to find the most suitable remedial option,▪Recommend remedial measures to prevent future pipeline failures,▪Perform high level engineering to confirm suitability of chosen option

These studies and assessments have been performed in accordance with API RP 1111 and DNV RP F109. From 2009 to 2016 several pipelines failed in this region (shallow waters 8m – 14m offshore Nigeria) in the Gulf of Guinea, resulting in a huge amount of deferred production (deferred revenue). To forestall future occurrence, this study was performed to identify the root cause of failures and provide recommendations to mitigate these failures in both existing pipelines and future pipelines (in design) operating in such environment.
Deblended-Data Reconstruction for Time-Lapse Seismic Monitoring
Authors: Ishiyama Tomohide , Ali Mohammed , Blacquiere Gerrit , Nakayama Shotaro
Published: November 2017

We introduce a generalized concept of the so-called blending and deblending, and establish the generalized-blending and -deblending models. Accordingly, we establish a method of deblending, or deblended-data reconstruction, using these models.

The generalized blending can handle real-life situations; this includes random encoding both in the space and time domain, both at the source and receiver side, thus all incoherent shooting, inhomogeneous shooting, non-uniform and under sampling. Similarly, the generalized deblending includes data reconstruction that works for all shot-generated-wavefields separation, spectrum recovery and balancing, regularization and interpolation, again both at the source and receiver side. However, we do face a challenging question: how to fully reconstruct deblended data from the fully generalized blended data. To address this challenge, we consider an iterative optimization scheme using a so-called closed-loop approach. We use the properties of blended signal specified by the blending code: the coherency of blended signal versus the incoherency of blending noise in the pseudo-deblended domain. This can be posed as an inverse problem with quantifying the coherency and its solutions by selecting optimal metrics of the coherency. We applied this method to synthetic datasets. The results show that our method succeeded to fully reconstruct deblended data from the fully generalized blended data.

We discuss its applicability to time-lapse seismic monitoring as it ensures high repeatability of the surveys. Our methodology should reduce the repeatability problem because reconstructing deblended data in monitor surveys is much more realistic and reliable than positioning sources and receivers exactly as the baseline survey.