bluuebunny/crossref_metadata_2025 huggingface dataset:
Simultaneous Well Stimulation and Scale Squeeze Treatments in Sandstone and Carbonate Reservoirs
Authors: Jordan M. M.
Published: November 2012

In many oilfields the relatively small number of high-cost, highly productive wells, coupled with a carbonate and or sulfate scaling tendency (upon waterflood breakthrough of injected seawater) requires effective scale management along with removal of near-wellbore damage in order to achieve high hydrocarbon recovery.

The nature of the well completion strategy in new fields such as frac packs for sand control and acid stimulation for carbonate reservoirs had resulted in some wells with higher than expected skin values due to drilling fluid losses, residual frac gel, fluid loss agents, and fines mobilization within the frac packs where applied.

The paper will present how the challenges of managing impaired completions and inorganic scale forced innovation in terms of when to apply both stimulation and scale inhibitor packages to sandstone and carbonate reservoirs. This paper will outline a novel process for non-conventional batch chemical applications where bullhead stimulation treatments have been displaced deep into the formation (<20ft) using a scale inhibitor overflush. Not only does this benefit the stimulation by displacing the spent acid and reagents away from the immediate wellbore area, but the combined treatment provides cost savings with a single mobilization for the combined treatment. The paper will describe the laboratory testing that was performed to qualify the treatments for both sandstone and an HP/HT gas condensate carbonate reservoir. The lessons learned fromcarbonate corefloodevaluationunder HT/HP conditions when appling stimulation fluids with and without scale inhibitor present in the treatment stageswill be presented.

Many similar fields are currently being developed in offshore Brazil, West Africa and Middle East, and this paper is a good example of best-practice sharing from another oil basin.
New Project Management Approach for Offshore Facilities Rehabilitation Projects
Authors: El-Reedy Mohamed Abdallah
Published: November 2012

All the offshore facilities for most oil and gas companies are matures now as most of the offshore platforms were constructed from 1960 with life time over 50 years. Therefore, most of the owner companies start to perform a rehabilitation projects for the structural, mechanical, piping, electrical and all the other facilities to maintain then to have a safe longer life and to comply with the recent standard and technical practice. Therefore, the project strategy for this type of brown field project is totally different than the applied strategy for green field for a new offshore platform.

In these type of projects there are many stakeholders to manage that influence the project as the endeavor users are usually have a higher expectation from these projects, In addition to that the new facilities will use a new technique match with the up to date technology.

This paper will present the nature of project management for this type of projects and the challenges that faces the team along the project life cycle. The new approach for the whole building commissioning system technique will be discussed as a solution that cover the pitfall for applying the normal project management procedures in the brown field for oil and gas projects.
Successful Application of a Fit-for-Purpose Acid Program in the Tengiz Field
Authors: Ussenbayeva K. , Utebaeva D. , Molesworth G. , Dunger D. , Howery R. , Akwukwaegbu C. , Salikhov T. , Kamispaev A. , Zielinski M. , Yakovlev T. , Savin A. , Aglyamov M.
Published: November 2012

Tengiz is a unique, super-giant oil field located in western Kazakhstan that is characterized as a fractured carbonate reservoir with high concentrations of H2S. It is operated by TengizChevroil (TCO). Current production is ~ 530,000 BOPD from 70 active producing wells. As part of an effort to increase the field's production output, a workover and stimulation program was initiated in 2011 after a hiatus of more than five years from such activities.

A sizeable part of this workover effort was a matrix acid stimulation program which took lessons learned from earlier acid stimulation campaigns in the Tengiz Field to develop a modified acid stimulation treatment design. The result of this most recent program was a significant and sustained response in well productivity.

The key components of the 2011/2012 acidizing program include: 1) increased acid volumes ranging from 50-100 gal/ft and 2) an acid diversion system that included the use of a viscoelastic diversion acid and degradable fibers.

Another factor that supported the success of the acid stimulation program was the involvement of a multi-disciplinary team that addressed both candidate selection and acid stimulation design.

The TCO 2011/2012 Acid Program has shown incremental improvement in all 19 wells stimulated to date. The average initial incremental gain following stimulation is ~4, 240 BOPD per well and the overall improvement in the Productivity Index (PI) has more than tripled. Post-stimulation production logs have confirmed improvement in the production profiles, indicating the acid diversion methods are having a positive impact.
The Use of a Formation Tester to Characterize Permeability and Vertical Communication across Stylolite Zones in a Carbonate Reservoir - Case Study
Authors: Al-Amrie Omar Yahya , Saad Mohamed Ahmed , Marzouqi Khalid Ibrahim , Kshirsagar Atul , Coskun Sefer B.
Published: November 2012

Quantifying the vertical permeability and sealing capability of the stylolite zones in a Middle East carbonate reservoir is critically important for the enhanced recovery, water coning, perforation policy and well-placement choices. A wireline formation tester was used to perform four vertical interference tests (VIT) in a newly drilled well. The objective was to obtain permeability, permeability anisotropy and vertical communication across the stylolite zones.

The formation tester was configured with a straddle packer, acting as a source of fluid flow, and two observation probes that recorded the pressure disturbances originating from the source. The formation testers were strategically placed so that the stylolite zones were located between the two observation probes. The simultaneous analysis of pressure transients from the straddle packer and the first probe provided the permeability and the permeability anisotropy of the main reservoir units. The vertical communication across the stylolite zones was evaluated by analyzing the pressure transients from the second probe.

The results of the four VITs indicate varying degrees of vertical permeability across the stylolite zones, implying none have the sealing capability for fluid flow. Reservoir simulation studies were performed to evaluate the impact of stylolite sealing capacity on field performance. Results show that the model cannot match the actual production and pressure data if the stylolite zones were sealing. Therefore, this confirms that the stylolite zones in this field have no sealing capacity as shown by the VIT test results.

The result of this study concludes that VITs can provide valuable dynamic data for reservoir characterization and could be extended in a field-wide approach to evaluate the lateral continuity of the vertical permeability variation across the stylolite zones. The results will be used in determining the perforation and well-placement policy and modeling the enhanced oil recovery studies.
Fracture Growth Monitoring in Polymer Injectors- Field Examples
Authors: Shuaili Khalfan , Cherukupalli Pradeep Kumar , Al-Saadi Faisal Salim , Hashmi Khalid Al , Jaspers Henri F , Sen Subrata
Published: November 2012

The objective of injecting polymer in brown fields is to increase recovery beyond primary and secondary recovery mechanisms. However, generally it is difficult to achieve adequate (viscous) polymer injectivity in depleted sandstone reservoirs without fracturing. Therefore, monitoring fracture propagation is required in order to control vertical conformance and areal sweep and avoid early polymer breakthrough.

Different surveillance methods are used to identify the existence and properties of fractures in polymer injectors. Pressure Fall off (PFO) survey data in conjunction with time-lapse temperature surveys are extensively used to determine the fracture dimensions. PFO tests in Polymer injectors have particular characteristics since they are influenced by shear-dependent viscosity seen in non-Newtonian fluids. A specially developed Injection Fall-off (IFO) model was used to determine fracture dimensions which is based on exact semi-analytical solution to the fully transient elliptical fluid flow equation around a closing dynamic fracture developed by Shell, (Van den Hoek 2005), as static fracture models are inadequate.

This paper presents different phenomena in polymer injection seen in PFO tests such as fracture closure, the effect in-situ polymer rheology and the detection of the polymer front. The paper demonstrates the effect of liquid-level drop observed in PFO survey in under-pressured reservoirs and its impact on determining fracture and some other reservoir properties. It also shows how plot-overlays of time lapse PFO's for a particular well can be used to track changes in fracture dimensions. All of these are illustrated by a number of field examples of polymer PFO which also demonstrate the calculated fracture dimensions from the data. Finally, some recommended best practices are suggested for fracture monitoring.
A Diagenetic Diagram as a Tool for Systematic Detailed Characterization of Carbonate Rocks: Applications to the Diagenetic Evolution of Hydrocarbon Reservoirs
Authors: Inês Nuno , Azerêdo Ana , Bizarro Paulo , Ribeiro Teresa , Nagah Adnan
Published: November 2012

Carbonate reservoirs are commonly heterogeneous and their reservoir quality results from complex interactions between depositional facies and diagenetic processes. The Diagenetic Diagram is a powerful tool that helps in the characterization of the diagenetic processes that have affected the reservoir. From this knowledge, it is possible to significantly improve the understanding of the reservoir's pore system and permeability distributions, which are key factors for development optimization and production sustainability.

A multi-scale and multi-method study (petrography, blue-dye impregnation, selective staining and porosity determination) of Middle Jurassic carbonates from the Lusitanian Basin (Portugal) has been undertaken, to find the best systematic approach to these reservoirs. It has involved thorough diagenetic characterization of each lithotype (lithofacies, texture, porosity, qualitative permeability assessment and diagenetic evolution). The study area was selected based on its excellent and varied exposures of carbonate facies and availability of core.

Methodological and terminological challenges were faced during the study, especially dealing with data coming from several scales (macro, meso, and micro). In order to overcome these challenges, a diagenetic diagram was developed and applied to the selected rocks. It is a tool that allows the integration of data coming from outcrops, hand samples, cores, cuttings, thin sections, and laboratory experiments.

This is carried out in a dynamic, guided, systematic, and rigorous way, enabling the evaluation of the relationship between facies, diagenetic evolution and pore systems. The latter are characterized regarding size, geometry, distribution, and connectivity. This enables the identification and characterization of permeability heterogeneities in the rocks. It was concluded that the main porosity class (i.e. secondary) was created by diagenetic processes.

The proposed method has strong application potential for: detailed characterization and understanding of porosity and permeability in carbonate reservoirs, from a diagenetic evolution and fluid flow perspective (e.g. SCAL and pore system description); definition of diagenetic trends for modeling petrophysical properties and rock types. In this regard, the method is being applied to a Valanginian carbonate reservoir in Kazakhstan, and some preliminary results are presented in this paper. Refining this technique may be helpful for similar carbonate studies, enhancing the results of typical diagenetic studies by improving the characterization of reservoir properties at various scales, thus contributing to a more sustainable exploitation of hydrocarbon reservoirs.
H2S Early Notification System for Production Pipelines: A Pilot Test
Authors: Hirezi George J. , Al-Khelaiwi Faisal T. , Al-Khamis Mohammed N.
Published: November 2012

The produced fluid of an oil field located in the Eastern Province of Saudi Arabia contains relatively high levels of H2S. A pilot test was conducted by Saudi Aramco to install a wireless gas detection system along an oil pipeline in this field. The pilot test objectives include:

Determining the communication availability and reliability of the remote wireless sensors where extending hardwired and fiber optic networks proved impractical and expensive. Evaluating the usefulness of this system for early notification of toxic gas releases or pipe leaks in and around critical geographical areas by alerting the console operator and via e-mail and Short Message Service (SMS).

The piloted system includes six wireless sensors separated at an equal distance along a 2 km oil pipeline. The sensors communicate wirelessly with a gateway receiver located in a shelter at a producer site. The wireless gateway is integrated with an existing Supervisory Control and Data Acquisition (SCADA) system by connecting it serially to a Remote Terminal Unit (RTU). Accordingly, the sensor's measurement and diagnostic data is monitored by the operators at their console in the control room. The same data is also accessible to the engineers at their desktops for real time monitoring and long-term archiving purposes via the OSI PI system.

The test results of the year-long pilot indicated that the gateway receiver demonstrated very high reliability and availability since it had no failures during the test period; however, initially some of the wireless sensors had experienced minor but recoverable communication errors.

This paper describes the details of this pilot test and discusses the difficulties encountered during the project's testing phase along with the actions taken to mitigate such problems, and subsequently improve the overall reliability and availability of the wireless communication.
Advanced Utilization of Downhole Sensors for Water-cut and Flow Rate Allocation
Authors: Al-Amri Meshal A. , Al-Khelaiwi Faisal T , Al-Kadem Mohammad S.
Published: November 2012

Downhole pressure and temperature sensors have been installed either separately as stand-alone sensors hanged on the production tubing of a well or jointly with Electric Submersible Pumps (ESPs) or Intelligent Well Completions (IWC). However, their utilization thus far has been limited to static/flowing bottom-hole pressures measurement for buildup/drawdown pressure tests analysis or ESP/intelligent well performance monitoring.

Eighty-eight (88) wells located offshore Saudi Arabia have been equipped with ESPs combined with downhole pressure and temperature sensors installed at the intake and discharge of the pumps. Each well was equipped with a surface coriolis meter to measure the total liquid flow rate and water-cut assuming that the well's production will be maintained above the bubble point pressure. However, the coriolis meters’ readings have become erroneous ever since the wells’ flowing wellhead pressure declined to and below the saturation pressure due to the flow of liberated gas through the meters. In order to compensate for the meters’ measurement deviation, wellhead samples had to be collected and analyzed to determine the wells water-cuts where the total flow measurement was still acceptable. Alternatively, other means of multiphase flow rate measurements were used. This has proven to be costly and time consuming.

This paper proposes a technique which uses real-time data transmitted from existing surface and subsurface sensors to calculate the water-cut and flow rate of each well and avoid the risky and costly field trips for wellhead sample collection and analysis. In addition, the paper describes an innovative technique to estimate the error in the measured density and calculated water-cut based on the bubble point pressure which accurately determines the application envelope of this method. The paper provides examples to illustrate the validity of the proposed technique in comparison with measured and sampled water-cuts which were collected above and below the bubble point pressure. Furthermore, the paper sheds light on the main issues impacting the method's reliability.
ADCO's Experience and Lessons Learned in Quality Management of Major Projects
Authors: Daoud Mohamed , Mohamed Alaa , Fawzi Mohamed , Hegazy Haytham , Folathi Ali al
Published: November 2012

ADCO has recently managed a major project called 1.8 MMbd Bab Thamama G and Habshan 2 consists of additional wells, flow lines, new process units and modification of existing surface facilities that are required to increase oil production in the Bab field by a sustainable rate of 80 MBOPD.

The facilities will include four additional Remote Degassing Stations (RDSs), namely RDS-7, RDS-8, RDS-9 & RDS-10 that gather from numerous production flow lines and deliver the raw crude to the BCDS through transfer lines.

Overall Project Objectives is to achieve EPC completion by Q4 2012, improve on ADCO's HSE targets, and Implement project within approved budget

The purpose of this paper is to share ADCO's experience during project execution, both in terms of technical and project quality management issues. The paper highlights the challenges faced, achievements and lessons learnt during execution of the project.

Mitigation of increased risk and consequences of failures due to higher service severity, Cost/time optimization drive due to material delivered from new and cheap suppliers with less quality level, Increasing inspection tasks of materials from different sources, and Management of the Third Party Inspection (TPI) to control all scattered activities locally and overseas were some of the major quality challenges during execution of the project.

The projects quality control practices implemented throughout the lifecycle of the project, starting with conceptual and preliminary engineering, through detailed engineering, procurement and construction are highlighted in the paper.

Major lessons learnt, quality control improvements tools, and other project quality issues are discussed in the paper.
Computation of Axial Load and Torque Distribution in Tubulars Used for Extended-Reach Horizontal Wells Using A Holistic Design Philosophy
Authors: Omojuwa E. , Osisanya S. , Ahmed R.
Published: November 2012

Drilling extended-reach horizontal wells (ERHWs) have become a viable option for field development because these wells bring additional reserves on line which may not be accessible with conventional well designs. Tubular design for ERHWs must be compatible with the intended well objectives, target location, wellbore trajectory in order to minimize the downhole dynamic events such as torque and drag, buckling and vibrations. Presently, the dynamic models used for calculating expected axial load and torque transfers along tubulars in ERHWs consider only the effect of the contact loads and frictional forces generated from torque, drag and buckling events. The expected axial loads and torque calculated during tubular design process are been underestimated using present dynamic models. However, the contact loads and frictional forces generated by lateral and torsional vibration events are critical to the tubular design for ERHWs and should not be ignored.

This study in this paper incorporates torque and drag, buckling and vibration models into the Newton second law of motion/instability in order to derive an integrated dynamic equation for torque and axial load distribution along tubulars in ERHWs. This study also uses theories of unbalanced centripetal force and fluid added-mass to quantify the magnitude of the normal contact load generated during lateral vibrations of a near-straight tubular section in an ERHW. The developed equations can be used for calculating axial load and torque transfer along drilling and completion tubulars depending on assumptions of hydraulic effects, buckling and inertia terms. Results show that the occurrence of downhole dynamic events contributes a relatively higher percentage to torque transfer than they do to axial load transfer. Also, when all the downhole dynamic events occur together and the critical buckling loads have not been reached, torque and drag events contributes the major portion of the axial load transfer followed by lateral vibrations.

The dynamic equations developed in this paper are validated using data from one of the world longest ERHWs. This study will lead to better tubular design through the minimization of failures, non-productive times, and ultimately reduced total drilling and completion costs.
Engineering Aspects in the Design and Implementation of Onshore Smart Oil Fields
Authors: Hafez Mohamed , Jakeman Simon , Al Azawi Bahir , Ur-Rahim Ihtisham , Khaled Moutaz
Published: November 2012

The Smart Field concept is deployed through disseminating elements of tools and infrastructure integrated to bring a level of smartness that can improve the performance of an oil field asset in a sustainable way.

The design and implementation of these tools and infrastructure underpinning smartness can however differ based on the oil field conditions. Green fields for example, can be engineered up-front to leverage all tools and deliver Smart Field value from the beginning of the asset's life. On the other hand, smart field tools and infrastructure for brown fields would be selectively designed and implemented based on several engineering and economic considerations.

The main functionalities of onshore Smart Field are remote operation, real time information and Collaboration realized by the following tools and infrastructure:

Subsurface Measurement Subsurface Flow Controls Wellhead Instrumentation Telecom Infrastructure SCADA and Control System Fields to HQ Connectivity Collaborative Work Environment

This paper outlines the engineering aspects to be considered in the selection, design and implementation of tools and infrastructure for onshore Smart Fields.
Optimized 3D Seismic Design Geometries for High Density Surveys
Authors: Ajlani Ghiath , Boukhanfra Fawzi
Published: November 2012

Despite the fact that wide azimuth land 3D seismic acquisition was introduced a couple of decades ago, the use of sparse 3D seismic designs continued for some time to be dictated by economic and technical limitations leading to poor quality and noisy seismic data. These design shortcomings were exacerbated by source and receivers arrays that failed to fully avoid aliased organized noise such as ground-roll and guided waves compromising the integrity of processing, imaging and reservoir characterization results.

To meet these challenges and motivated by increased demands for high resolution seismic data, leading-edge high-density and highresolution recording systems were developed potentially capable of recording as much as one (1) million channels at 2ms sampling rate. To optimize productivity and economics these recording systems have been combined with technologies that allow for shooting above 20,000 vibrator points per day and reaching very high trace densities. These technologies offer the possibility to deploy symmetric wide azimuth land source and receiver high density geometries and acquire non aliased signal and noise benefiting from all offsets and azimuths.
Black Oil, Heavy Oil and Tar in One Oil Column Understood by Simple Asphaltene Nanoscience
Authors: Seifert Douglas J. , Zeybek Murat , Dong Chengli , Zuo Julian Y. , Mullins Oliver C.
Published: November 2012

A Jurrasic oilfield in Saudi Arabia is characterized by black oil in the crest and with mobile heavy oil underneath and all underlain by a tar mat at the oil-water contact. The viscosities in the black oil section of the column are fairly similar and are quite manageable from a production standpoint. In contrast, the mobile heavy oil section of the column contains a large continuous increase in asphaltene content with increasing depth extending to the tar mat. The tar shows very high asphaltene content but not monotonically increasing with depth. Because viscosity depends exponentially on asphaltene content in these oils, the observed viscosity varies from several to ~ 1000 centipoise in the mobile heavy oil and increases to far greater viscosities in the tar mat. Both the excessive viscosity of the heavy oil and the existence of the tar mat represent major, distinct challenges in oil production. Conventional PVT modeling of this oil column grossly fails to account for these observations. Indeed, the very large height in this oil column represents a stringent challenge for any corresponding fluid model. A simple new formalism to characterize the asphaltene nanoscience in crude oils, the Yen-Mullins model, has enabled the industry's first predictive equation of state (EoS) for asphaltene gradients, the Flory-Huggins-Zuo (FHZ) EoS. For low GOR oils such as those in this field, the FHZ EoS reduces to the simple gravity term. Robust application of the FHZ EoS employing the Yen-Mullins model accounts for the major property variations in the oil column and by extension the tar mat as well. Moreover, as these crude oils are largely equilibrated throughout the field, reservoir connectivity is indicated in this field. This novel asphaltene science is dramatically improving understanding of important constraints on oil production in oil reservoirs.
A Novel Approach to Measuring the Quality of Well Integrity Performance in ADMA-OPCO
Authors: Al-Marri Faisal M. , Abdalla Hussein S. , Hussain Ashiq , Chishti Khalid
Published: November 2012

Several papers have been written to discuss various aspects of well integrity management such as technical standards, new software for data management, different approaches for risk management and using new technology to improve the operational efficiency. However, the literature lacks insights about how to measure the performance quality of well integrity operations. Measuring performance quality serves several objectives; it provides an insight into the overall performance; it highlights successful initiatives that could be expanded; and it identifies key areas for further improvement.

This paper presents one approach to measure well integrity performance quality using a Quality Index (WIQI) in a manner similar to that adopted by other industries. The Quality Index samples key activities such as planning, execution, monitoring and review to collect parameters that are consolidated in a weighted index to reflect performance quality. The paper will discuss ADMA-OPCO experience in adopting the new index and the impact it had on its operations.
Compression Solutions for Co2 Enhanced Oil Recovery
Authors: Dekker Gerrit Jan , Keim Benjamin , Mathijssen Gaston
Published: November 2012

A narrative on injection of CO2 for enhanced oil recovery considering the advantages of the integrally geared compressor over the single shaft compressor, and using the Siemens hermetically sealed canned motor-compressor in the process of separating export gas and CO2 for reinjection.

When injecting CO2 for EOR we have investigated the most important market requirements to identify the best solution from the existing portfolio of turbo machinery, when comparing a standard single shaft inline compressor to an integrally geared compressor, and have concluded, based on economics, efficiency, and power consumption, that integrally geared turbo compressors incorporate the optimum design concept for economic CO2 compression.

When re-injecting the produced gas after oil and gas separation there is a mix of saturated CO2 and hydrocarbons and other contaminants possibly containing hydrates, mercury and H2S. Gases and components which are preferably contained in the process equipment without possible leakages to the atmosphere due to seal leakages or malfunction of the compressor units dry gas seals. With the above in mind we developed a sealless (no dry gas seals) compressor which could add strategic benefits and eliminate the need for continuous flaring and venting of the seal gas and barrier gas to the atmosphere. And in conjunction with a fully categorized material selection provide the best solution with high availability and reliability.

Combined with the increased robustness of the overall system with less instrumentation and auxiliary systems and thus less spurious trips and downtime it is obvious that the integrally geared turbo compressor, STC-GV, in combination with the hermetically sealed compressor, STC-ECO, has the potential to considerably contribute to minimizing the environmental foot print, higher reliability and lower OPEX in the Oil & Gas operations especially in the process of mixed flow dirty gas separation found in the CO2 reinjection application.
Experimental and Numerical Modeling of Double Displacement Oil Recovery Process in Tight Fractured Carbonate Reservoirs
Authors: AlSumaiti A. M. , Kazemi H.
Published: November 2012

Waterflooding has been the most popular post-primary production approach for improving oil recovery. In fractured reservoirs with large structural relief, gas injection can produce much of the post-waterflood remaining oil by gravity drainage. Oil recovery by gas-invoked gravity drainage in waterflooded reservoirs is known as the double displacement process (DDP). One major reason, among many, is that the three-phase relative permeability residual oil saturation endpoint is generally smaller than the residual oil saturation endpoint for the water-oil displacement.

Field data indicate that the DDP has been successful in single-porosity sandstone formations. Intuitively, one can expect that DDP should produce similar results in reservoirs with ample intercommoned vertical fractures, which is the objective of this work. With the aid of tests on tight reservoir cores from a major Middle East carbonate reservoir, this study focuses on evaluating the DDP in fractured carbonate reservoirs where the wettability ranges from neutral to oil-wet conditions. The scope of the study includes: (1) assessment of the DDP experimentally in fractured cores using a high-speed centrifuge, (2) simulating the experiments numerically, and (3) upscaling laboratory results to field applications.

Results from water-oil gravity drainage tests followed by gas-oil gravity drainage in fractured and unfractured cores are presented. We also show numerical simulation results of matching the experiments using both transfer function and 2-D numerical simulation, and how results from our study can be used in field applications.

Typical waterflood oil recovery from 0.1-md to 2-md fractured carbonate cores has been noted to be around 38% of the initial oil in place while incremental additional oil recovery for gas-oil gravity drainage is nearly as much as the recovery from water.
BP North Sea Gas Injection Projects: Sustaining Offshore Production
Authors: Brodie James , Zhang Pinggang , Mellemstrand Hetland Sigrun , Moulds Tim , Jhaveri Bharat
Published: November 2012

BP has been operating gas injection projects in a variety of challenging environments throughout the world for more than three decades. Numerous innovative techniques have been used to optimize oil recovery and the results have been reported in a series of publications.

The focus of this paper is the North Sea, where BP operates offshore miscible gas floods in the Magnus and Ula fields and an immiscible gas flood in the Harding field. Tertiary miscible WAG in Magnus began in 2002 and its impact on reservoir performance is significant and well understood. More than 112 Bscf of gas have been injected into three mature panels, yielding 11.5 mmstb of oil at a very high net efficiency of 3.5 mscf/stb. The contribution of EOR to total field production has increased to 40% by 2010. In Ula, tertiary miscible WAG started in 1998 and has played a key role in arresting production decline. More than 23 mmstb of oil has been recovered by gas injection, which accounted for 60 – 70% of total field production in 2010. Key to the success of both projects has been securing a source of miscible gas and pursuing an active surveillance and reservoir management programme to monitor and optimize the flood.

The success of the North Sea projects is partly based on the experience of operating the world's largest miscible gas flood at Prudhoe Bay (Alaska), where conventional and unconventional techniques have been successfully applied in a variety of different settings. The knowledge acquired in Prudhoe Bay has been shared with other assets, including the North Sea, through a series of managed moves and master classes.

Miscible gas injection has generated considerable benefits for BP over the past three decades and will continue to do so in the future. The potential availability of large sources of CO2 in the future, through carbon capture, could help maintain a leading role for miscible gas injection for years to come.
100MBD Interface and Shutdown Management
Authors: Binthabet Hussain Ahmed , Cochrane Marc , Pettigrew Michael
Published: November 2012

ADMA-OPCO's approach, 100MBD Interface and Shutdown Management

In 2006, ADMA-OPCO embarked on a programme to increase the oil production from one of its offshore fields by 100 MBD. This involved a portfolio of 8 projects consisting of, on both offshore and onshore facilities and a drilling programme covering 40 wells. In addition to oil, ADMA OPCO also manages the offshore gas network and all offshore gas irrespective of source flows through its facilities. Therefore, any shutdown of gas facilities could impact gas and oil production from other offshore companies operating in the waters of the UAE, which has the potential to impact a significant portion of the offshore oil production in the UAE.

This paper will outline how ADMA OPCO managed the interfaces between projects, existing facilities and sister companies to both maximise oil, gas production facilities availability, and minimise hydrocarbon lost opportunities during shutdown and interventions whilst delivering the 100MBD Project portfolio.

The main areas of discussion will be

Organisational structure – ADMA OPCO set up a new organisational division, which included new focused teams dedicated to management of projects; minimising losses; programme & interface management. Case study – the paper will detail how a specific event was managed involving several projects interfacing with offshore and onshore facilities with the potential to impact oil production and how total shutdowns were eliminated and oil losses were reduced by over 75%

The success of this initiative resulted from focusing on

Identifying and quantifying potential shutdown reduction opportunities. Identifying opportunities to minimise plant preparation and return to service times. Optimising plant configuration to maximise production opportunities during intervention. Identifying any works or modification required to accommodate identified production opportunities

Application of methodology

This methodology is applicable to any Brownfield intervention covering one or more work fronts or projects, and has a demonstrated successful outcome
Engineered Internal Downhole Coating Solutions for Corrosion & Deposition Control in Downhole Production Tubulars
Authors: McKeen Laurence W. , Hofmans Jurgen , Nelissen Joke
Published: November 2012

During the last decade, DuPont™ has been developing an engineered fluoropolymer based internal downhole coating system, for downhole production tubes. This development work came as a response to critical needs expressed by major oil and gas producers in Europe, the Middle East and Northern / Latin America, in order to have a polymeric based coating solution that could be applied internally in downhole production tubes for the purpose of:

Offering an enhanced corrosion resistance in HP/HT (8000 psi / 350 Deg F) sour and sweet corrosive environments Reducing substantially difficult type of organic and inorganic depositions, such as asphaletene, paraffin and BaSO4 scale.

The ultimate objective of this exercise is to offer the oil and gas industry a reliable and sustainable static solution that would not require costly intervention for wells clean-up and maintenance and also to reduce the number of workovers required on oil and gas well producers, which would ensure lower production cost.

In order to develop such a new polymeric solution, a new approach versus the resin matrix design had to be used. The new coating system has an effective combination of a very low finished surface energy coupled with an improved pressure / temperature design envelope. Given the inherent design envelope limitations of current coating systems used by the oil and gas industry, fluoropolymers were selected in order to develop such a new internal downhole coating system.

The high thermal stability and high flexibility of fluoropolymer-based materials provide a significant advantage in terms of mechanical properties retention in high pressure and high temperature environments, which is a must for an effective internal corrosion control. On the other hand, it has the lowest sticking tendency versus difficult type of organic and inorganic depositions, such as asphaltene and BaSO4, which provides an opportunity for a new cost effective approach in terms of maintaining oil and gas producing wells prone to such problems.
Achievements and Expected Challenges of the Current Maintenance Strategy
Authors: Elmi Mokhtar
Published: November 2012

The importance of maintenance in the oil and gas industry is well recognized and as such every year great sums are spent on reducing turnaround and mean time between failures while all the more increasing equipment availability and achieving acceptable levels of work force certification. ADMA-OPCO as one of the world's largest companies in the upstream sector of the oil and gas industry has managed to utilize various available technologies to achieve high standards of maintenance. However, the field of engineering maintenance and reliability is an ever evolving one and due to many factors such as aging machinery and the expansion of operations, the company's underpinning maintenance practices and strategies require constant review and update. For this purpose the paper will present a review of the company's achievements in this regard as well as outlining solutions for future challenges. The findings will be based on scrutinizing current practices such as the utilization levels of the computerized maintenance systems in use in ADMA. Moreover, this paper will endeavour into finding out how well the company's maintenance strategy is adhered to and the major constraints that hinder its smooth execution. Age of the rotating equipment plays an important factor in the levels of maintenance they require; therefore this paper outlines the effect this has on the maintenance strategy and the likely future consequence of this factor taking into account the challenges ahead.
IP of Pipelines with Associated Subsea Tie-Ins
Authors: Al Hammadi Hassan , Alshehhi Ebrahim , Hadji Djaffar , Dognon Olivier
Published: November 2012

Mechanical cleaning and Intelligent pigging (IP) are essential to reduce corrosion effect and identify the integrity status of pipelines and to know the weak point within the pipeline to avoid pipeline failure which might have serious environmental and business impact. Therefore, pipeline inspection is critical to ADMA OPCO to assure integrity compliance and determine the remaining life of the pipeline to plan for future replacement.

The Intelligent Pigging is a method of pipeline internal inspection used to detect external and internal metal loss, cracks, geometry defects or video of the internal condition.

Mechanical cleaning and can only be run on pipelines equipped with special facilities in order to launch and retrieve IP tools. IP always needs proper cleaning prior running of the IP tool using cleaning pigs (foam and Bi-Di with brushes). Pipelines without permanent pigging facilities can not IP until temporary facilities is installed (pig traps, pumping facilities, hoses, etc). Pipelines which are attached to other pipelines through Tie-in (Spur lines) are considered not piggable as the pigs can not be received and retrieved. The pipeline without pigging facilities requires longer shut down period than the pipelines fitted with permanent facilities.

Cleaning and IP of pipelines with subsea Tie-in (Spur lines) at their end are not possible as the debris will stay in the pipeline attached and pigs will stay in the pipeline which will result in blocking the pipeline.

The innovative approach was to take the pipeline offline and flood it with water and use Bi-Directional pigs (cleaning and specific IP tool) with direct co-ordination with the contractor. This approach solved and eased the inspection of the Spur lines on the oil and water systems, which has assured the integrity of the Spur lines for the operator.
ADMA OPCO Development of Asset Replacement Plans for 20 Years for Zakum, Umm Shaif and Das Island
Authors: Balmer Brian , Khorooh Ali Saleh
Published: November 2012

ADMA OPCO operates facilities in the Zakum, Umm Shaif and Das island sites more up to 45 years old. The Asset Field Life is expected to extend to more than the next 20 years with existing and New Field production projects currently indentified and future developed also expected.

In this context the Asset Integrity of aged equipment is a major challenge in the oil and gas industry. ADMA OPCO has developed a risk directed strategy to identify, assess and mitigate risk across all existing facilities and develop inspection, assessment practices and maintenance and repair approaches that will provide the asset integrity assurance required for current and future business requirements. The Asset Replacement Plan - 20 Years is under development for all sites based on this risk directed approach. The work described in this paper was carried out in the period 2011 to 2012.

Key aspects of the asset replacement plan include the principle that ADMA OPCO will seek to fully utilize the existing equipment capabilities, consider improved practices for inspection, maintenance and remedial works, recognize the potential impacts of Brownfield Project developments and link all existing Development, Engineering, Maintenance and Integrity studies and identify where additional studies are required.

The deliverables from this across the ten identified equipment types include;

An equipment strategy to meet business requirement. Plan for equipment and improved practices opportunities Costs by year of replacement expenditures Supporting links to existing studies supporting the strategy and plans

The paper provides the background and business benefits of the development of the Asset replacement plans, the approach taken to develop strategy, plans and costs. The discussion is supported where appropriate by description of the development process, example case to explain issues faced, decision a making and the basis for the final results.
A Unique Integrated Asset Modeling Solution to Optimize and Manage Uncertainty in a Giant Offshore Oil Field Development Mega-Project
Authors: Khedr Osama , Amur Jayant , Al Ameri Rakkad , Torrens Richard , Amtereg Ahmed
Published: November 2012

This paper presents the application of an integrated modeling approach to the facility design and construction stages of a mega-project for a giant oilfield offshore Abu Dhabi. The scale of the EPC task is unprecedented in the UAE and requires careful design to optimize the capital investment. In addition, the project uncertainties require that a high degree of flexibility be factored into the design process.

The integrated modeling approach couples surface and subsurface flow models to achieve a complete system solution that incorporates many levels of constraints and realistically represents future behavior. This approach addresses a number of key issues. Firstly, multiple different quality reservoirs produce to a shared surface facility. Consequently, the field is highly sensitive to back pressure variation and so requires a rigorous treatment of well and surface physics. Secondly, the sub-surface uncertainties and sheer size of the investment requires a flexible approach to design, hence, many simulation scenarios are required to provide improved decision support. Finally, close collaboration is required between the sub-surface and surface teams to ensure optimization of facilities design and reservoir management for cost and recovery. The adopted methodology utilizes an integration framework which couples reservoir and topsides models into a predictive tool for development planning. This paper describes how the integrated modeling approach was utilized to provide input to design process for several aspects of the field development plan during the design and construction stages. This will include discussion of the phasing of the production facilities, requirement for temporary facilities, modular compression and separation units and the optimization of the drilling program for planned infill wells.

The paper presents a best integrated modeling practice supporting facility design process which is applicable for similar scale projects, highlighting the role of integrated model as a means to foster collaboration between surface and sub-surface teams.
Successful Application of Extended Reach Drilling (ERD) Technology in Super Giant Onshore Middle East Field, Case Study
Authors: Al Shamsi Juma , Al Menhali Adnan Mohammed , Hamdy Ibrahim , Parkinson Andrew , Kuyken Chris
Published: November 2012

Extended reach drilling (ERD) represents one of the industry's most impressive engineering accomplishments in terms of wellbore construction. As the recovery of oil and gas becomes more complex, these wells have pushed drilling engineering boundaries to new limits to meet the world's demands in the safest, most environmentally conscious and cost effective manner. Drilling ERD wells requires the latest innovations in drilling engineering principles; such wells are more interrelated and sensitive to smaller changes than conventional wells. An integrated approach for both planning and execution becomes more critical due to the high operational risks and all uncertainties must be properly assessed by solid engineering planning. In addition to that, it brings engineering challenges from many disciplines, which must be met and addressed for proper execution. Integration of drilling and real time evaluation allows engineers and geoscientists to take the proper drilling decisions and lead to reduce operational risk. It will also provide an accurate well placement; improve drilling efficiency and maximum recovery.

Well-1 & Well-2 were the latest ERD wells drilled in Abu Dhabi. Abu Dhabi Company for Onshore Oil Operations (ADCO) has drawn on extensive experience from numerous ERD Projects around the world, successful engineering tools and proper assessment for the several of challenges of those projects. In addition to the positive contribution from National Drilling Company (NDC) in providing all the necessities in terms of equipment and support which enabled the land rig to drill the well Well-1 to a total depth of 19,725 ft MD with a horizontal displacement (HD) of 10,131 ft. In addition, Well-2 was drilled to a total depth of 20,003 ft MD with a horizontal displacement of 10,303 ft, which was a bench mark record in the United Arab Emirates (UAE). The numerous challenges faced on those two wells in terms of planning and the rich experience gained from successfully executing such wells are all highlighted in the attached paper.