bluuebunny/crossref_metadata_2025 huggingface dataset:
Optimizing Spacing of Horizontal, Multistage Fractured Wells in Gas Reservoirs
Authors: Alghannam Maryam , Rahim Zillur
Published: December 2014

The growing demand for gas in the Kingdom of Saudi Arabia and the availability of multistage fracturing (MSF) of horizontal well technology have opened up the development of tight gas reservoirs throughout the country. Draining the reservoir efficiently using MSF strongly depends on well spacing, especially for low permeability reservoirs. The majority of the work done by the industry to find the optimum well spacing was based on economic considerations. Saudi Aramco optimizes field development based on sustained rate and ultimate hydrocarbon recovery. Natural gas is treated as one of the most essential commodities supporting the country's infrastructure based on the increased domestic energy demand.

Some of the significant parameters to consider for well spacing optimization are the drilling azimuth and well completion strategy that include a number of induced fractures, fracture conductivity, and fracture half-lengths. In addition, reservoir properties, such as formation thickness, reservoir permeability, and the permeability anisotropy ratio are to be considered. Due to the scarcity of interference test data in gas wells and the inaccuracy of analytical solutions, numeric simulation is the most suitable approach for such a study. To find the optimum well spacing, several simulation runs are carried out for a realistic range of well and reservoir variables. The outcomes are then translated into a 20-year cumulative production as a function of the well spacing, with the results indicating that lower permeability reservoirs require closer well spacing. In the case of a large number of long fractures, wells need to be placed further away from each other to minimize well interference. This paper gives the recommended MSF horizontal well spacing for several development scenarios in Saudi Arabian gas reservoir environments. Although each area must be individually studied and optimized, the results will provide engineers with guidelines to better plan gas field development with the application of MSF technology.
CCS for Enhanced Oil Recovery: Integration and Optimization of a Post Combustion CO2 Capture Facility at a Power Plant in Abu Dhabi
Authors: Reichl Albert , Schneider Gernot , Schliepdiek Torsten , Reimuth Oliver
Published: December 2014

Masdar has initiated the Abu Dhabi Carbon Capture and Storage (CCS) Project, with the objective to develop an Abu Dhabi-based carbon capture network capable of creating large reductions of CO2 emissions as well as the capacity to increase oil extraction by use of CO2 for enhanced oil recovery (EOR). Since Siemens has developed, tested and piloted a proprietary post-combustion CO2 capture technology (PostCap™) for the removal of CO2 from the flue gas of coal and gas fired power plants suitable for the project, both parties decided to cooperate in executing a FEED study. The solvent Siemens based its technology on is an aqueous amino acid salt solution.

Siemens and Masdar have completed a FEED study for capturing 1,800,000 tons of CO2 annually from a natural gas fired power plant in Abu Dhabi, by application of the PostCap™ technology.

Various opportunities and challenges were encountered during the design of the retrofit capture plant. Challenges were often specific to the region, including local climate, water availability and flue gas quality. Design and optimisation of the plant was influenced by local energy and labour prices. Further opportunities included integration with the power plant and a local industrial facility.

The power plant had to supply the capture plant with steam and power without reducing the original electricity production capacity. In order to accomplish this, several heat and power integration concepts were evaluated with respect to their feasibility, including the application of a back-pressure steam turbine and the retrofit of a simple cycle gas turbine to combined cycle.

Various cooling options were considered, in view of climate and resource challenges. Cooling water had to be extracted from a reflux stream produced by an adjacent industrial facility.

Drawing on the results of the FEED study this paper presents how the Siemens PostCap™ technology can be applied for capturing CO2 at a power plant in Abu Dhabi for the purpose of EOR while satisfying specific local needs, and how simultaneously utility supply and power plant integration can be facilitated.
NMR as a Characterization Tool for Wormholes: The Complete Picture
Authors: Al-Duailej Yaser , Mahmoud Mohamed , Al-Khaldi Mohammed , Kwak Hyung , Shebatalhamd Abdullah , Al-Yami Ibrahim
Published: December 2014

Acidizing is a common practice aspired to recover the initial skin factor or even decrease it further. Acids tend to create conductive channels (wormholes), through carbonate formations which connect the reservoir to the wellbore and bypass the damaged zones. Optimum wormholes are formed when certain conditions are met, such as optimum acid concentration and optimum injection rate. In order to thoroughly grasp wormhole creation, several characterization techniques should be performed.

Computerized tomography (CT) scan and differential pressure data are two common practices to characterize wormholing in laboratories using core plug samples. Differential pressure data and CT scan can verify acid breakthrough occurrence, and qualitatively suggest the size and path of a wormhole. Nuclear magnetic resonance (NMR) was introduced in earlier studies as a new characterization tool for wormholes. It was able to detect the changes in micro- and macro-pores, due to acid injection. In addition, it was able to indicate the changes in interconnectivity between different pore systems and detect the materialization of formation damage. Nevertheless, NMR technique could not detect the new porosity corresponding to the generated wormhole due to inability to sustain saturation fluids inside the core plug samples.

In this study, the NMR technique was further improved using a customized Teflon tube as a container for core plug samples. Since Teflon material does not interfere with NMR readings, this improvement allowed the core plug samples to maintain full saturation, which enabled the detection of the new wormhole porosity. As a result, NMR was able to indicate different characteristics of the generated porosity, including the size of wormhole, the changes in diffusion coupling, and in the distribution of each pore size. This technique can significantly elaborate new aspects of wormhole generation and characteristics in carbonate reservoirs.
Experience of Using a Fibre Optic Pipeline Monitoring System in a Remote Desert Environment
Authors: Espiner Richard , Pickburn Alastair , Smith Gerald
Published: December 2014

BP Oman has recently come to the end of a three-year extended well test (EWT) project to provide field data for the $17+bn Khazzan major project, involving the development of a tight gas field with approximately 300 wells and due to commence production in 2017/8.

The EWT facilities included a gathering pipeline network and gas & liquid export pipelines. The major pipelines were equipped with a fibre optic pipeline monitoring system that was developed, and field trialled through a BP-led technology project. The monitoring system has the capability of continuously monitoring the full length of the buried pipeline on which it is installed, as well as provide real-time indication of leaks, third party activity around the pipeline, ground movement and the passage of maintenance or inspection pigs through the pipeline. The implementation of the monitoring technology for the Oman EWT project was the first full-scale implementation of the system.

The paper describes the capabilities of the fibre optic monitoring system and the experience gained throughout the three years of operations experience in Oman. In particular, operating experience has proven the system's capability of accurately tracking pipeline pigs, and this is illustrated using data from a cleaning & inspection pigging campaign.
Successful Batch Processing of Heavy Oil Sludge at Oman (2011 to 2014)
Authors: Nahmad D. G. , Al Ghafri F. , Rasheed R. , Sajid S.
Published: December 2014

Sludge is an intrinsic by-product of the Oil & Gas Industry, it is considered a hazardous waste and there are few technologies within the industry to process it under an environmentally sound protocol.

Sludge to Oil Technology (STO) is a proprietary process utilized to break emulsions of hydrocarbons/water/solids. The process is based on a series of chemical reactions involving surfactants that interact with other reagents in releasing heat and neutralize the non-covalent forces that form the bonds between the substrate and the wetting agent. Final separation is achieved by using specific gravity differential between the different components of the de-emulsified mixture. The byproducts of the reactions are inorganic salts, water and carbon dioxide.

Two different centrifuges are used to achieve a fast and accurate separation. The byproducts of the reactions are inorganic salts, water and carbon dioxide.

This technology has been successfully implemented at the operator site by the contractor under a pilot project. Over the term of the contract, more than 100,000 bbl of raw sludge had been treated meeting the following KPI's: Oil < 1.0% BS&W, Water < 20 ppm OIW and Solids < 1.0% TPH.

The process has been applied in-situ where the emulsions are stored and has recovered more than 50,000 barrels of saleable crude oil. The recovered water has been sent for re-injection and the solids meet all the requirements of the Ministry of Environment and Climate Affairs (MECA) - Oman as a treated waste under international standards. At a time when crude oil prices have reached over $100.00 USD/bbl this technique can prove to be not only environmentally sound but also an addition value to the operator's production bottom line.

The STO process was applied directly in the field where the emulsions are stored and can bring great technical and economical advantages to the user.

At a time when crude oil prices have hiked this technique can prove to be very economical not only for oil recovery, but for also as preventative maintenance and to mitigate from potential environmental liabilities.
Advanced Technique In Designing An Inflow Control Device Completion for The Development Of A Giant Offshore Oilfield In The UAE
Authors: Bachar S. , Khedr O. , Jackson A. , Qotb M. , Alhajeri A.
Published: December 2014

An integrated completion design modeling approach has been implemented for development wells in a giant offshore field to maximize asset value and recovery. The modeling approach enables the selection of lower completion inflow control devices and well path compartmentalization strategy for every well based on predefined criteria.

The development of the field under consideration is progressing with a water flood recovery scheme that requires the use of new technologies to achieve higher oil recovery and controlled water production. Since the only contact with reservoir is the wellbore, efficient reservoir sweep and recovery can only be achieved by putting the right well equipment in the right location.

In this paper, the design process which has been adopted for well completion design using Inflow Control Devices (ICDs) will be shared and explained. An interactive loop is used to optimize the number of ICDs and nozzle sizes using reservoir simulation coupled with specialized well and completion modeling software.

A number of ICD well completion design examples are presented. From these examples, predefined design criteria are applied in an iterative manner targeting optimal sweep and maximum recovery as an objective function. The key criteria elements are:

Predicted water flow mechanism from nearby injectors into the well. Reservoir pressure contrast along the well path and variation over time to account for additional pressure drop imposed by ICDs. Permeability contrast along the well path. Effect of nearby producers, if within the same drainage area.

When concluding the detailed completion design, the outcome is shared with the Drilling operation team for fine-tuning, materials selection, materials procurement, and implementation. Further modeling work will be discussed covering the impact of the stimulation design resultant skin on predicted recoveries.
Innovative Approach to Increase Name Plate Capacity of Oil and Gas Gathering Centre: A Case Study of North Kuwait Facility of Kuwait Oil Company
Authors: Parikh Chirag , Al-Saeed Abdulaziz , Mahmoud Bader A. , Kukreja Rajiv
Published: December 2014

The Oil and Gas gathering and processing facility of Kuwait Oil Company was built with a nameplate capacity of X MBOPD with 50% water cut. However, the facility was operating with a water cut of 35% since its commissioning in year 2011. This comprehensive technical study was conducted to evaluate possibility of increasing oil processing capacity of this facility in line with current lower water cut and other operational flexibilities available in the facility without utilizing its design margin.

This paper shares an innovative approach to increase name plate capacity of oil and gas processing facility utilizing available operational flexibility and operational margins with minor modification. It shares a case study where facility capacity is increased by around 19% without utilizing design margins of equipment or pipeline. Such approach can easily be applied to all similar facilities across oil & gas industry.

The study confirmed that facility name plate capacity can be revised from X MBOPD (with 50% w.c) to X+32 MBOPD (with 45% w.c). It is observed that minor modification in control loop of separator to utilize three phase separator as two phase separator, lower water cut of the feed stream and margin available in feed specification of Desalter trains are major contributors to get leverage in increasing name plate capacity of facility.

The paper provides detailed guideline for such out of the box technical evaluation of facility to operate it at higher capacity without any major modifications which will result in significant financial / production gains for any organization.
Challenge of Acidizing Horizontal Wells in Tight Carbonate Reservoirs - Weak Acid and Non-acid Alternates
Authors: Punnapala Sameer , Rahman Maryam Abdul , Misra Sanjay
Published: December 2014

Horizontal wells have become a norm in ADCO for effective and efficient reservoir recovery. At present ADCO is embarking on development of tight carbonate reservoirs where permeability ranges from 0.2 – 10 mD. While carrying out a review of the 214 acidization jobs conducted from 2005 to 2013 in two of ADCO's fields, it was found that conventional acid stimulation with 15% hydrochloric acid in horizontal wells in tighter parts of the reservoirs did not seem to provide expected results. Use of selective stimulation in segmented completion and diversion also did not yield the desired results. The reaction rate of 15% hydrochloric acid is too fast to create effective wormholing when tightness of the reservoir exceeds certain degree. A thorough survey of market and the published literature was carried out to analyze the root cause of the poor performance. Wormholing is the desired mechanism for carbonate stimulation, which is governed by the reaction kinetics and rate of transport. Optimal wormholing is obtained at a right balance between these two mechanisms. Literature is abundant with references on use of weak acids and non-acid stimulation chemicals like acetic acid, chelating agents and nano emulsions for stimulation of carbonate reservoirs. These chemicals have an advantage over 15% hydrochloric acid in terms of wormholing potential owing to slower rate of reaction. The study revealed that in a field, permeability and length of treatment are the main parameters in deciding the optimal stimulation chemical. A correlation was developed based on the kinetic parameters of various chemicals and field experience which can act as a guide in selecting the right acidization formulations. Such correlations will go a long way for ADCO in acid stimulation of horizontal wells in tight carbonate formations.
Modification in Conventional Depressurization Calculation in Quest of More Pragmatic Minimum Design Temperatures in Complex Isolatable Blowdown Zone
Authors: Nandi Bashistha
Published: December 2014

Blow-down system under discussion was complex in nature and Hydrocarbon gas was methane rich. In an isolatable section there were a big inventory of slug catcher, piping, inlet separator and two trains of Glycol contactor getting depressurized by two BDVs simultaneously. For such a big system it would be unrealistic to consider a single bulk vessel (as Aspen HYSYS does) and use the same Minimum Design Metal Temperatures (MDMT) throughout as different section had different Surface area upon volume ratio and varying thickness. While reviewing (By conventional Aspen HYSYS Blow down calculation) Minimum Design Metal Temperature (MDMT) of equipment inside blow down inventory and Flare network, it was found that metallurgy needed to be more exotic than selected during FEED as inner wall temperatures were much lower than selected particularly for Piping as heat transfer co-efficient (HTC proportional to velocity^0.8) in piping is much higher than the vessel. As changes involved a significant cost and a common MDMT throughout such a complex system seemed to be impractical, Aspen HYSYS Blow down utility calculation had been modified by considering credit for actual surface Area, actual metal mass, volume averaged thickness and splitting the system in several hypothetical blow down zones to arrive at much practical MDMT and exotic metallurgy was averted.

The above non-conventional MDMT study can find significant application for appropriate selection of metallurgy in complex blow down inventories in gas processing industry and avoid over conservative exotic metallurgy selection.

Rigorous Blow down calculation and minimum temperature analysis were taken up in-house and most pragmatic MDMTs were predicted at different parts of the complex section and appropriate metallurgy selected with respect to predicted MDMT by the study and significant project cost was averted. The blow down study subsequently was verified by a Third Party Consultant through a Dynamic Study and existence of problem, methodology applied and recommendations were acknowledged and approved by them.

Based on above study, exotic metallurgy hence significant cost to the project was averted in a recently concluded gas processing project in Algeria.
Successful Execution of Offstream Inspection at ADCO NEB Asset
Authors: Al-Marzouqi Abdulla
Published: December 2014

ADCO North East Bab (NEB) field is located at approximately 90 KM from Abu Dhabi town. It comprises of two Central Processing Plants (CPP); one at Al Dabbiya (DY) and the other at Rumaitha (RA). The two plants are located 20 KM away at the west and the east side of Al Sila road respectively.

NEB field consists of around 165 wells (some located in clusters and other are remote wells) along with pressure vessels, connected piping and pipelines. Pressure vessels located in clusters are mainly Closed Drain Vessel or Oil Test Separator. The Central Processing Plant (CPP) at Al Dabbi'ya consists of two trains of oil treatment and stabilization while CPP at Rumaitha consists of one train. In addition to oil treatment, the CPP includes facilities for storage & export, gas compression & gas drying, water injection, water treatment & disposal, and utilities. All vessels/equipment in CPP are in service since 2006.

In October 2013, ADCO-NEB asset successfully carried out off-stream inspection of twelve (12) pressure vessels located in various clusters. Equipment covered were mainly Oil Test Separators and Closed Drain Vessels. Subsequent to off-stream inspection of pressure vessels at clusters, random on-stream inspection of piping in both the CPP was also carried out.

This paper highlights the salient points in successful and safe handling of the off-stream inspection and presents the case study of two major findings. Vessel bulging: Inspection revealed bulging of one of the horizontal closed drain vessel located in one of the on-shore cluster. A closed drain network and a closed drain vessel are installed in clusters to collect drained fluids from Oil producer Wellheads, Piping manifolds, Gathering manifolds, Test separator, Pig traps, PSV discharge and Let down station when installed. The closed drain vessel is open to the atmosphere through the cold vent stack.Flare Header corrosion: CPPs have extensive network of Flare header piping which includes LP, HP, Cold and Tank Flare headers. During on-stream inspection, random ultrasonic thickness survey of piping revealed severe internal corrosion of Low Pressure (LP) flare header. LP flare header combines with HP flare header and Cold flare header and discharges to HP Knock Out drum. Perforations were also noted on the several locations. Consequently, shutdown was taken and LP header was replaced with the new piping.

This paper also describs in brief the root causes analysis of above failures and corrective actions taken. Timely detection of these damages prevented the potentially more severe failure consequences.
Review of BP's Global Gas Injection Projects
Authors: Jhaveri Bharat , Brodie James , Daae Victoria
Published: December 2014

Miscible gas flooding is an established method for enhancing oil recovery that can be successfully deployed in secondary or tertiary mode. BP has developed a range of innovative techniques to maximize economic oil recovery from its miscible gas floods. While some of these gas floods have been applied early in field life, in other cases gas flooding has significantly extended the life of mature, water-flooded fields. The results have been reported in a series of publications over the past three decades. The purpose of this paper is to provide an overview of BP's experience of establishing, managing and optimizing miscible gas floods.

Prudhoe Bay (Alaska) is the world's largest rich hydrocarbon miscible gas project. Conventional and unconventional methods have been applied in a variety of different settings in secondary and tertiary mode. An extensive surveillance program has facilitated a good understanding of the processes operating at field scale and routine surveillance data are used to optimize the flood. In 2002, a large-scale gas cap water injection project was implemented to slow the decline in field pressure. This project has enhanced the efficiency of the various recovery processes operating across the field, resulting in additional recovery. As a result of the success in Prudhoe, miscible gas flooding has been extended to numerous other fields on the North Slope of Alaska.

BP has two active miscible gas projects in the North Sea, Magnus and Ula. In both cases, gas injection began after extensive water flooding. Tertiary miscible water-alternating-gas (WAG) flooding in Magnus field started in 2002 after construction of a gas pipeline from fields located west of the Shetlands and its impact on reservoir performance is significant and well understood. Tertiary miscible WAG injection in Ula field started in 1998 and has played a key role in arresting production decline. In both fields, the miscible gas flood is currently being expanded. In addition to these miscible gas projects, BP jointly operates a CO2 injection project in Algeria and, with its heritage companies, has a long history of operating CO2 floods in the US. BP is actively pursuing new opportunities for gas flooding around the world.

Miscible gas injection has generated considerable benefits for BP over the past three decades and will continue to do so. The potential availability of large sources of CO2 in the future, supplied by carbon capture, could help maintain a leading role for miscible gas injection for years to come.
A Novel Approach for Reservoir Simulation and Fluid Characterization of Unconventional Fields: Phase 1 Molecular Level Considerations
Authors: Diaz-Campos Mery , Hobson Stephen
Published: December 2014

In spite of the Shale Gas revolution, that has changed the dynamics in US supply and while today's combination of hydraulic fracture and horizontal drilling has made certain shales economic. This study presents that the fundamentals for fluid behavior in Unconventional reservoirs remain unknown. As the amount of reserves in the world is massive, today's technologies and workflows need to evolve more and systematically apply the correct science to extract full value of every shale.

Unconventional fields contain hydrocarbon fluids that are under strong influence of their pore-walls. The reason for such behavior is attributed to pore-size distribution being at nanometric level (10-9m), widely demonstrated by scanning electron microscopy (SEM), simulation and adsorption data (Diaz-Campos et al., 2008; Ambrose et al., 2009). At this tiny scale, fluid behaves different to what it is known conventionally.

Current methods for calculating gas reserve in a typical unconventional field attempt to take such complexity into account by modifying methods used in conventional fields without definitive and clear success. The modified method utilized today is known as modified "Langmuir isotherms" (M. Gasparik et al., 2012). Such approaches require detailed isotherm analysis in the laboratory and iterative calculations to estimate its unknown constants Langmuir volume (VL) and Langmuir pressure (PL). It has added variables to the Langmuir's equation, adsorbed methane density, adding complexity to the original equation and making its application difficult if not impossible. Furthermore the constants and added variable are representative to a single well level only, utilizing such values at a reservoir level are prone to compromise the accuracy of the results. Novel approaches to generate datasets for unconventional gas reservoirs are therefore needed.

In this study, it is used a molecular-modelling approach to analyze how hydrocarbon fluids accumulate in such nano-pores and how the pore-size affects its mobility. Molecular modelling is a form of computer simulation (Allen M.P and Tildesley D. J., 2007) that is been used in the biomedical industry, material science, chemistry, chemical engineering and has been evolved to be an essential means with which to explore chemical and physical interactions in unconventional reservoirs.

We characterize methane behavior when confined to a nanoporous medium, by means of Computer Simulation at molecular level. From the results of the fluid characterization at molecular level we observe that methane adsorbed density changes with reservoir pressure. Furthermore we conclude that the methane permeability is reduced with pressure, specifically when the reservoir is above ~5700psia methane shows a liquid-like behavior, such findings generate a fundamental insight about fluid behavior when confined to shale type of reservoirs. The experimental method for validating the MD simulation results is also discussed.
Successful Reservoir Management and Field Development Strategy Through Integration of Field Data Analysis with The Simulation Model - The Case of an Abu Dhabi Offshore Mature Complex Carbonate Reservoir
Authors: Ali Issa Abdelkerim , Uematsu Hiroshi , Bellah Samir , Al Hashemi Mohamed A.
Published: December 2014

A complex heterogeneous carbonate reservoir, located in the offshore of Abu Dhabi, started oil production in 1985. The initial field development plan consisted of drilling crestal deviated producers and peripheral sea water injectors. As the reservoir is highly faulted and fractured with underlying high column of aquifer, water cut rapidly increased by channeling through faults system, reducing oil production. Consequently, the field development team decided to drill horizontal producers, and then later equip them with ESP. In the meantime, water injection rate was significantly curtailed due to uncertainty on injection benefit, which resulted in declining reservoir pressure, limiting production from some wells. In 2012, the team analyzed the historical production data to reassess water injection benefit. The study included areal analysis and correlations of reservoir pressure, voidage replacement ratio, logging data, production decline trends, bubble and saturation maps, and geologic data. The results indicated hydraulic communication between all reservoir areas, increased production decline rate with continuous reservoir pressure depletion due to low VRR and insufficient aquifer support, and poor pressure communication in some peripheral areas due to low reservoir quality resulting in lower transmissibility. Based on the analytical study results, reservoir simulation model was used to optimize water injection scheme, including optimum injector locations and optimum injection volume. Along the process, reservoir uncertainties were assessed through simulation sensitivities. The study results suggested maintaining the current peripheral water injection locations, increasing injection rate to minimize reservoir pressure depletion, working over the existing injectors/drilling new injectors to meet injection volume target, and carrying out further optimization after improved understanding of remaining geologic uncertainties.

This reservoir management approach allows to continuously integrate reservoir geology and field dynamic data to reduce reservoir uncertainties and to optimize field development plan and operations.
Applications of Wintershall's Drilling Complexity Index (DCI) in the Well Delivery Process
Authors: Nzeda Blaise G. , Schamp Juergen H.
Published: December 2014

Wintershall has developed a Drilling Complexity Index (DCI), which is a tool that is used to measure the complexity of a well. It is an early warning indicator and a measurement of how easy or difficult a specific well can be delivered. The DCI can be used at any phase of the well delivery process; from the pre-screening or conceptual phase through the detailed design phase to the execution phase.

Wintershall's HQ based Best Practice unit for Well Engineering (ESW) used well data from existing databases to compare the DCI to other complexity indexes. Furthermore, ESW analyzed the impact of the DCI on key performance indicators (KPI) such as non-productive time (NPT), cost per meter, and meter per day. This paper will present the work performed and the results that show a strong impact of the DCI on all the above cited key performance indicators.

This DCI tool was initially planned to be used by drilling teams to plan wells. Following its successful development and roll out in the drilling groups, Wintershall looked at ways to expand its use and quickly realized that its usefulness extend beyond the drilling groups.

This paper will further describe how the DCI can be used for the following purposes: Predict NPT of drilling projects based on DCIDetermine the time contingency for a wellDetermine the cost contingency of a wellTrigger peer-assists, well examination and staffing of well projectsSupport role in the project approval processPortfolio management

The work which will be presented has accelerated the acceptance and the utilization of the DCI tool within Wintershall, and represents a significant improvement in assessing the inherent risks and hazards and potential consequences for exploration/appraisal/development wells.
Accurate Geometric Well Placement of the First ERD Producer Well Drilled From the Artificial Island in UAE
Authors: Elgizawy M. , Grini M. , Al Junaibi H. , Rachi H. , Chandran K. , Adewumi F. , Day T. , Batu A.
Published: December 2014

Accurate wellbore geometric placement is fundamental to achieve the objective of maximizing hydrocarbon production and recovery. It is especially essential in real time to drill complex 3D well trajectories that penetrate multiple thin geological targets. Accurate placement is also critical to avoid catastrophic subsurface collision of nearby offset wells. This is critical in particular in this gigantic field with over 800 wells drilled by two different operators with several hundreds more wells to follow.

Almost all Bottom Hole Assemblies (BHA) run in this field include a Measurement-While-Drilling (MWD) survey tool to survey the wellbore while drilling. The MWD is a magnetic survey tool that is subject to errors that limit the magnetic survey accuracy. One of the main sources of error is the variation in the local magnetic field due to the crustal anomalies in this field. The magnetic surveys can provide an accurate geometric well placement by incorporating the knowledge of the local magnetic field disturbance to the main geomagnetic field model and by compensating for the drill-string magnetic interference.

The Geomagnetic Referencing Service (GRS) technique based on magnetic surveys was introduced in this field. This technique utilizes the local magnetic data that is measured over the field by acquiring a high-definition airborne gravity and magnetic survey. The accuracy of the geometric well trajectory of the first oil producer well is compared between the MWD, cased gyroscopic and GRS surveys and the advantage of the GRS is presented.

The benefits of applying GRS in real-time while drilling is paramount, where it provides an accurate well position in real time when corrections to the well trajectory are still possible. It prevents the costly sidetracks if the post drilling gyroscopic survey shows the well has missed its target. In most cases, GRS is an alternative to the gyroscopic surveys where it provides magnetic survey accuracy that is comparable to the casing gyroscopic survey tools. Hence, it saves the cost and risk of running gyroscopic survey tool as well as the cost of the extra rig time required to run a gyroscopic tool after drilling.
A Comprehensive Risk Management Review Related to the Application of Low Salinity EOR Process in Offshore Carbonates Reservoirs.
Authors: Al Busafi Badar S. , Draoui Elyes , Al-Hendi Ahmed
Published: December 2014

This paper sheds some light on the emerging EOR recovery mechanism related to modified ionic design of the injected water, sometimes referred to as low salinity or smart water EOR process. Many laboratory water-flooding experiments have been conducted with mixed outcomes on the benefit of the technology. Relative to the existing field applications in sandstones, this technology is less mature in carbonates. Many researchers support the theory that this process is very complex in carbonates and chemical reactions within productions time-scale are not well-understood. The literature lacks the connection between what researchers address in laboratory work and considerations for full-field applications. Therefore, this work aims to bridge some gaps between what is considered in experiments and what is relative to full-field applications.

The paper offers a comprehensive review of the risk management framework related to the application of Low Salinity EOR process in offshore carbonates reservoirs in the UAE. Some risks/opportunities related to subsurface, flow assurance, surface facilities and operations will be addressed. The work presents an example of a risk matrix and remedial actions that must be considered during the design phase. For example, the root causes of souring, scaling, anhydrite participation, nepthenate solid precipitation and divalent cation migration will be presented and their possible impact on flow assurance will be addressed during the application of the low salinity flooding on different types of carbonate rocks. Furthermore, uncertainties related to pore-volume contact to reach the threshold salinity, temperature/cooling impact and chemical modelling limitations are addressed and related to the quantifications of the technology benefits as the study evolves from lab work, field trials and eventually to full-field applications. With such visibility of the full spectrum of the technology impact, laboratory experiments can be tuned with the focus to minimize specific risks and maximize benefits to the addressed field.
3D Geomechanical Models Inverted From Pre-Stack Seismic Data
Authors: Azevedo Leonardo , Nunes Ruben , Pereira Maria João , Soares Amílcar , Guerreiro Luis , Caeiro Maria Helena
Published: December 2014

In order to optimize the development plans of complex, and unconventional, oil and gas reservoirs it is essential to achieve reliable 3D geomechanical models. These models need to comprise the description of the subsurface geology (e.g. lithologies and petro-elastic properties) and simultaneously the in-situ stress fields affecting the reservoir. Currently, the available geomechanical models are often too simplistic and built based exclusively on sparse well-log data. Therefore, they do not translate properly the complexities and heterogeneities of the subsurface geology for the entire reservoir area. We present herein a novel approach to model seismic-driven 3D geomechanical models based on geostatistical seismic AVO inversion. This novel iterative geostatistical inversion methodology allows retrieving density, P-wave and S-wave velocity models from where dynamic moduli properties can be calculated. The resulting models are then used to derive horizontal and vertical stress field models. It is important to highlight that the resulting seismic-driven 3D geomechanical models are simultaneously conditioned locally at the well locations by previously modeled 1D geomechanical models and by the available seismic reflection data for the rest of the reservoir area. The proposed workflow has been successfully tested on synthetic and real pre-stack seismic data. The synthetic example shows that the resulting high resolution inverse elastic models, as well as the dynamic moduli properties, match the real ones. The inverted petro-elastic models derived from the real pre-stack seismic data allowed a better characterization and management of the reservoir in study.
Failure of Internally Coated Fusion Bonded Epoxy in Water Injection Flowlines
Authors: Luqman Abdulla , Nour Maher M.
Published: December 2014

The failure of internally coated fusion bonded epoxy that occurred in ADCO's Water Injection Flowlines was investigated. These lines were made of Carbon Steel and were internally lined with Fusion Bonded Epoxy. There was a separation of the Positive Seal Coupling (PSC) accompanied by the detachment of the coating from the flowline. The PSC was inspected and sent for further investigation. Thermal expansion of stressed line, improper burial of line and the extensive de-bonding of the internal FBE coating were the possible causes for the PSC failure.

Later, another two lines, commissioned and constructed by the same contractor, failed. This time no PSC failure occurred, which left the disbondment of the internal FBE coating to blame and to be further investigated. Pipe samples, both used and unused, were sent to an independent laboratory for (1) visual examination, (2) coating thickness measurements, (3) holiday testing and (4) coating adhesion testing. The holiday test on the unused pipe samples was found to have some holidays. This suggested that the coating had peeled off at pinhole locations, where water permeation was able to occur and assist in the formation of corrosion products. This would easily cause this failure to occur.

Other possible causes may have been; incorrect surface profile of the metal surface, possible contamination products during the surface preparation or even the degradation of the coating itself. This investigation lead ADCO to change its practice with Water Injection Flowlines and adopt the use of bare Carbon Steel Pipes with 3mm Corrosion Allowance in addition to continuous injection of Corrosion Inhibitor.

This paper describes the different investigation techniques used and the methodologies of identifying the problem leading to future plan of action along with correction.
ICD Well History and Future Use in Giant Offshore Oilfield, Abu Dhabi
Authors: Edmonstone Graham , Kofoed Curtis , Jackson Alfred , Parihar Shardul , Alvarez Adriana , Mumtaz Saad , Abdouche Ghassan , Shuchart Chris , Mayer Christian , Troshko Andrey
Published: December 2014

As part of the Islands Project which involves the use of 4 artificial islands to drill & complete over 300 ERD wells in a giant offshore oilfield, several completion designs have been piloted to test & monitor their suitability for the brownfield development.

One well design incorporated the use of Inflow Control Devices (ICDs) & swell packers which was ZADCO's first use of such technology in a production well. The technology was installed in the pilot well to test in-flow control along a 10,000ft lateral & to manage future water production.

The Paper will cover:

The design of the well detailing the ICD configurations & swell packer arrangements providing 15 compartments along the reservoir section, The inflow performance recorded annually along the lateral showing differing results, The outcome of an extensive intervention program in 2013 utilising different logging tools to record internal & external data, live camera to view condition in low water cut well & venturi tool to recover downhole samples that concluded the mechanical failure of ICDs in the heel, The extensive post-failure investigation undertaken such as extensive review of installed ICD design, flow assurance, computational fluid dynamic (CFD) simulations, laboratory testing for different conditions & materials, comparison of modelled with actual data to determine failure mode & The way forward for future ICD installations with initial short term solution & plans for future long term design solutions to give a required 30 year life.
Enhanced Interpretation Of Salt-Related Structures In Abu Dhabi Using Improved Seismic Data Processing And Interpretation Techniques
Authors: Obaid Khalid , Neves Fernando , Mahgoub Mohamed , Taher Ahmed , Noufal Abdelwahab , Matarid Tarek , Inoue Hiroyuki
Published: December 2014

In recent years, advanced and integrated seismic processing and interpretation workflows have been adopted in ADNOC. The application of new processing routines to legacy seismic data has shown to be valuable in improving the quality of the seismic data. This improvement has had a positive impact on our understanding of complex geological settings, in particular in areas where salt movement has had an influence on the structural framework of the field.

In this paper, case studies are presented for salt-related structures in Abu Dhabi. Salt structures have been classified into three classes according to their complexity and each of these classes asks for a different type of seismic data volume and a different interpretation workflow. With the help of better reprocessed seismic data and seismic attribute analysis, complex structural uncertainties are better appraised, allowing less operational problems in wells due to drilling through faults and more optimal field development plans.
Flare Stacks Integrity Management: GASCO Approach
Authors: Al Awadhi Ibrahim , Chaudhary Sumit , Rahim Nasheed Ur
Published: December 2014

Guy wire supported flare stacks, Seven Numbers, in GASCO-Ruwais NGL plant are in service for more than three decades. The stacks and wire ropes sustaining them in position were mainly designed for a life of 20 years & subjected primarily to visual inspections (on-stream / during shutdown).

Consequently, stack structural integrity may be compromised causing costly downtime & possible fatal injuries which is more relevant in Ruwais area since continuing deterioration of aging wire rope / stack is a major problem in marine environments. Any flare related failure / unplanned downtime may disrupt operations, lower customer confidence & damage company's HSE reputation along with revenue reduction.

Accordingly, an online state of art integrity management approach has been adopted to mitigate threats to stack integrity since visual inspection only proves to be inadequate especially for assessing guy wire condition. Main elements of this online strategy are:

Guy wire tensioning/ flare stack verticality checks: Done annually & proactive recommendations issued. Electromagnetic inspection of guy wires (Remote operated Magnetic Flux Leakage): Detection of Loss of Metallic Cross Section / Local Faults caused by internal wear etc done & condition based proactive recommendations issued. Activity done every five under 5 year business plan. Optical imaging of flare stacks & thermal imaging of flare tip using remote operated unmanned aerial vehicle: Assess flare tip condition (esp hot spots) during operation by thermal imaging & evaluate coating damage / external corrosion (esp above flare stack platforms) by optical imaging.

Based on survey findings & past reports assessment, a flare stack refurbishment strategy is being proposed. Additionally, as per findings of finite element based stack design appraisal, corrective actions are executed to extend life of stacks by another 20 years.
Application of Vacuum Forces by Utilizing Reservoir or Available Inherent Energy of the Process Fluid to Maximize Production & Minimize Environmental Impact
Authors: Chockalingam Esakkimuthu , Baratam Gangadhar
Published: December 2014

Vacuum is a negative pressure force generated due to space devoid of matter either partially (Partial vacuum) or entirely (absolute vacuum). Vacuum plays vital role in the research field of chemistry, biology and physics. It is also indispensible in many industrial applications. Generally Vacuum can be generated by equipment's called vacuum ejectors, displacement and kinetic pumps. Vacuum ejectors are special static equipment's can utilize the available energy in the oil and gas reservoir or process. In Some applications available pressure energy from reservoir fluids and compressor discharge pipeline are wasted through chokes and other pressure reduction devices (Recycle flow control or pressure let down controls) which can be exploited to generate vacuum forces by utilizing ejectors. Ejectors are simple and portable static equipment's works by venture principle. By using ejector to create vacuum forces, underutilized or inherent pressure forces generally wasted are used to boost or resume production by lowering well head flowing pressures. This technique avoids oil and gas flaring during well unloading & clean out operation, applied in the field of flare gas recovery, environment sensitive carbon foot print reduction as well. Utilizing Ejectors or Gas jet pumps are the promising technology to tap the hidden available energy in the field of oil and gas. This technology can be considered particularly in place of wellhead compression, Unloading well & Flow to clean operation using atmosphere flaring packages, addition of other equipment's which needs work done through environmentally damaging conventional energy sources. This technology is best suited and can be applied to boost production or recover oil and gas, prevent high sour gas flaring, remote applications of fields which are having multiple reservoirs with different pressure, flow and fluid profile. Economical, environment, convenience of remote handling are some of the advantages which makes them very attractive and are not fully exploited in oil and gas E&P business.