bluuebunny/crossref_metadata_2025_split huggingface dataset:
Conceptual Structural Model of an Onshore Carbonate Hydrocarbon Field in Abu Dhabi: Constraints and Implications
Authors: Sirat Manhal , Mahmoud Sabry L. , Popa Desdemona Magdalena , Koyi Hemin 
Published: November 2012

Abstract
A carbonate field in Onshore Abu Dhabi is characterized by its complicated structural setting, which involves basement tectonics. A new seismic attributes analysis has been conducted to reveal the structural style, and to identify significant lineaments representing possible major and minor faults. Based on this analysis, a conceptual model is presented, which reveals the development mechanism of the major structure and associated faults.
Structural constraints such as lineaments length, faults throw and displacements are strongly related to the seismic resolution constraint. Whereas timing of the structural development events represents a challenge and needs to be linked to sedimentation and sequence stratigraphic framework and thus needs further study.
In total, six fracture sets have been identified including the N75W, N45W, NS, EW, NE-SW and N70E. The Conceptual structural model shows that the contractional structure has been modified as a giant positive flower structure-like associated with a basement strike slip fault. At least two major longitudinal faults bound the structure parallel to its fold axis (NE-SW), which pose sigmoidal map geometry. There are numerous transverse faults linking and/or cross cutting those longitudinal faults creating andulations that may define new minor plays.
Significant implications of this study include better understanding of the regional structural geology of Abu Dhabi, and define new plays within the studied structure. In addition, the new identified fracture system provides essential information for the ongoing and future development plans for this field and for other fields in the region with similar structural settings.
Geophysical Fluid Monitoring Strategy and Roadmap - From Concept to Field Acquisition and Analysis for a Giant Offshore Carbonate Field, Abu Dhabi, U.A.E
Authors: Zhang Jie , Al Dhaheri Amna , Skeith Gene , El-Awawdeh Raed , Jan Kamran , Borland William , Campbell Allan , Safdar Muhammad , Atif Muhammad , Wilt Micael , Bryans Bradley 
Published: November 2012

Abstract
The field presented in this paper is a giant carbonate oil field located in the offshore area of Abu Dhabi, United Arab Emirates. It has been on production for several decades and high water breakthrough is occurring in some reservoir intervals. Hundreds of wells will be drilled over the next few years to increase and sustain production for decades to come. Accordingly, the main challenge for Geophysics is to provide effective fluid monitoring tools to help identify bypassed oil, increase oil recovery and minimize infill drilling cost. After an extensive technology screening effort, well-based technologies such as Cross-well ElectroMagnetics (EM), Cross-well Seismic (CS), and 3D Vertical Seismic Profiling (3DVSP) were identified as potential lower cost and high chance-of-success tools to address current field development and future sustainability needs.
Feasibility modeling studies for EM, CS and 3DVSP were conducted to understand the applicability, resolution and limitations of each technology before proposing a field campaign. The modeling results indicate that each technology has different physical measurements, resolution and limitations for fluid monitoring. The EM results show high sensitivity to water saturation distribution and changes although limited by resolution. The CS provides the highest resolution interwell image with acoustic measurements that potentially relate to both water saturation and pressure changes. Time-lapse VSP modeling provides 3D seismic images and acoustic measurements at surface seismic scale. The results are promising for high water replacement cases although provides the lowest resolution amongst the three technologies modeled.
A geophysical fluid monitoring pilot consisting of EM, CS and 3DVSP is planned to be conducted during 2013. This paper will describe the objectives and challenges along with the strategies to address them, feasibility modeling, survey procurement and planning. This pilot will be industry's first joint acquisition project for all three technologies. The learnings from the pilot could provide significant impact to the field development and EOR activities of our field and industry.
Axis of Success: A Unique Professional Plug & Abandonment Project, In Populated Town Area
Authors: Abdelsalam Hazem , Al Rhama Rhama , Al Mazrouei Manal , AL-Hosani Mohamed Salem , Kuyken Chris , Al Menhali Adnan Mohammed 
Published: November 2012

Abstract
In 2011, ADCO embarked on a project of well abandonment in Town field, Located in an urban area approximately 25 km South-East of the main island of Abu Dhabi. Each of the three wells presented individual technical challenges and, due to proximity of the populated areas, complexities with logistics and emergency response planning arose. As well as significant presence of toxic H2S in the Town field reservoirs this categorizes those wells as critical high profile wells. And this necessitated extensive engagement with ADCO coordinating with external authorities of concerned parties’ throughout the project.
This paper presents a successful case study and project over view with focus on the Three wells, one well T-09 required measures to be taken to address the Sustainable Annulus Pressure (SAP) in the Casing x Casing annulus SAP(B) as well as address accessibility issues associated with a stuck plug inside the tubing. The other well consider is T-06, which over Ten years before, been plugged & abandoned with cement to surface but had subsequently also developed Sustainable Annulus Pressure between Casing x Casing.
Fast and efficient 2G&R workflow on a large mature carbonate field
Authors: Gommard Denis , Wagner V. , Bockel-Rebelle M. O. 
Published: November 2012

Abstract
Integrating new data in a fast way is a key issue for optimizing the field development but when field are getting mature this process becomes fastidious and time consuming. Updating Geological and Reservoir models often and rapidly is crucial. This calls for time optimized procedures where full 2G&R workflows become powerful tools to respect modeling techniques as know-how and data integrity. The project, presented in this paper, targeted to test, optimize and validate a full operational 2G&R workflow within a 18 month time frame on a large mature carbonate field with almost 200 wells and having produced for more than 40 years. A full engineer's team (geophysicians, geologists and reservoirs) was mobilized to conduct this work starting from data processing to full field development plan through reservoir simulation. Innovative and key processes were highlighted in this work: Reconciliation of seismic fault picking with well data and well tests carried out very early in the studyTOTAL's Carbonate geological modeling workflow allowing keeping track of the facies identity up to the reservoir modelUpscaling techniques used at the geological model to be able to share the same grid between reservoir and geology allowing easy and fast iterationsPermeability field calibration validated by well test simulationFor simulation of miscible gas injection, residual oil saturation better apprehended by the use of alpha factors
Innovative Rigless Application to Reinstate Surface Control of Downhole Safety Valve System and Restore Well Integrity (Case Study)
Authors: Al Braiki Saleh Abdul , Al Sawadi Obadah , Afzal Mohamed , Odeh Nadir , Khan Naeem , Al Hosani Abdullah , Bani Malek Ahmed , Yousef Anwar , Faruqi Shamim 
Published: November 2012

Abstract
In ZADCO's giant offshore oilfield, the Surface-Controlled Downhole Safety Valve (SC-DHSV) system of some oil producers failed to operate. Thorough investigation revealed that SC-DHSV landing nipple sealbore damage was the root cause of failure. The failed SC-DHSVs were temporarily replaced with A-3 Storm Choke Valves.
The conventional solution to restore the integrity of a failed SC-DHSV was the workover. However, efforts were made in identifying a viable rigless solution by thoroughly reviewing the available options and as an alternative, special oversized B-Type seals were chosen to substitute the existing conventional V-Type packings that failed to seal in said valves.
To ensure safe field implementation, a risk assessment was conducted followed by successful yard testing. Field implementation was successfully completed by utilizing conventional slickline unit which saved significant time and cost. A standard SC-DHSV was redressed with the oversized B-Type seals, set in the landing nipple and functioned normally. The redressed SC-DHSVs were routinely tested during the following year with no concern reported. The successful implementation was documented and is recommended for future use in similar cases.
Teamwork and Technology Improve Efficiency and Well Performance in Offshore Deep Carbonate Gas Development
Authors: Ibrahim Mohamed El-Sayed , Al Marri Faisal M. , Hassane Mohamed Abdelsalam , Khalil Hassan Ibrahim , Sultan Emad , Salsman Alan , Abdel-Shakour Sherif 
Published: November 2012

Abstract
The development of deep tight gas deposits in the UAE is a priority as gas demand increases. The deep carbonate gas reservoir described in this paper is over 1000 ft thick and about 13,000 ft deep and consists of many different layers with different petrophysical properties all capable of gas production with about 2-3% H2S concentration. These complex offshore reservoirs are completed with 7in. CRA (Corrosion Resistant Alloy) casing with monobore designs and are selectively perforated and acid stimulated, a process requiring significant rig time to execute. Any improvement in efficiency and productivity is highly sought after.
Working closely with its contractors during the completion of more than 10 of these wells ADMA-OPCO developed a completion process that provides improved gun performance and running efficiency. Efficiency gains have been significant with the adoption of special fit-for-purpose hardware allowing increased gun lengths and higher payload weights per run. Detailed prejob planning with increased efficiency and improved gun performance have positively impacted total job cost and productivity.
This paper reviews the development of the best practices for these complex operations, the technologies and procedures employed to improve efficiency, the perforating systems used to improve productivity and the plan going forward for additional improvements in efficiency and well performance.
The lessons learned from these operations resulted in significant cost saving and improved productivity to ADMA OPCO and will be of benefit to other countries in the region that are developing similar complex gas reserves.
HP / HT Field Development Tied Back to an Existing Host
Authors: Crowe Trevor , Koninx Jean-Paul , Slater Crispin 
Published: November 2012

Abstract
The Linnorm gas condensate field, located in the Norwegian Sea is technically challenging. The high pressure and high temperature reservoir contains gas with CO2, H2S and traces of mercury. Although the gas is relatively lean, the associated condensate has waxy properties. The field is located in ~ 300 m of water, ~ 5,000 m below the sea bed and 200 km from land. Although there are production facilities within 30 to 70 km, this discovery was initially seen as "stranded gas" due to the absence of an export route with available capacity.
The chosen field development is in the FEED phase and comprises of subsea wells tied back to a 20 year old oil production platform, with a ~ 55 km direct electrically-heated flowline. The gas is processed on the platform for export, via a new, joint venture pipeline to an onshore terminal.
This paper will discuss the key development decisions, and issues, regarding this technically and economically challenging project, from the reservoir to the export of the processed gas. Specifically it will address the reservoir development strategy considering decisions taken to exploit the different reservoir formations with individual wells, in the context of maximizing gas recovery, within the sub-surface constraints. The wells and subsea concepts are particularly challenging, pushing the limits of existing technology and requiring some world first solutions for what will be the highest temperature subsea field development on the Norwegian continental shelf with the world's longest electrically heated flowline. The surface facilities design will add significant gas processing facilities (separation, mercury removal, water and hydrocarbon dewpointing and compression) onto the platform and extend its economic life. Along with the safety, space and weight issues to be managed, there are also numerous other platform integration decisions to be made in relation to the process, flare and electrical and instrument integration.
Seismic Reprocessing in Mature Production Environments; Defining Critical Objectives and Objective Assessment of Potential Solutions
Authors: Reilly J. M. 
Published: November 2012

Abstract
It is widely accepted that surface seismic surveys are essential to hydrocarbon exploration, development and production. Furthermore, advances in acquisition, processing, computing hardware and theory continue to enhance seismic-image quality. However, since major 3D seismic projects often require large financial commitments, an investment decision should be based upon a reasonably quantifiable expected value.
Determining whether additional investment in seismic processing of existing data would provide significant added value late in the life of a field can be challenging. In some cases, application of recently developed algorithms can mitigate known deficiencies in older technologies. However, in many instances, reservoir challenges cannot be addressed simply by applying the "most current" seismic technology to an existing dataset. Alternative processing strategies must often be considered to replace more conventional approaches and/or to prepare the data so that they conform to the physics assumed by follow-on specialist applications.
The optimum technology usually depends upon the specific reservoir objective. For example, geophysical solutions for monitoring a deepwater clastic reservoir are very different from those required for a shallow-water carbonate reservoir. In these situations it is critical for us to avoid relying upon "faith-based" assumptions, such as "a modern processing flow" will solve all problems.
To be successful, it is important to objectively assess the fundamental reservoir problems that need to be resolved and develop a clear and explicit understanding of how additional seismic investment can address those issues. The estimate of future value should be calculated as an addition to the "base case" scenario, which would include all existing seismic dataset(s) as well as all the available borehole data. This last point is critical, since the new seismic information must effectively "compete" with information that is already available from direct well measurements and the extrapolation of those measurements into the geologic model. This is perhaps the most difficult concept for the practicing geophysicist to understand and accept.
This paper mainly focuses on the imaging challenges common to several UAE oil fields. The majority of these fields have been on production for over 30 years and are in the mature phase of exploitation. Structural dip at the reservoir level is generally one to two degrees and only occasionally reaches five degrees. However, stratigraphic features both on the overburden and reservoir can exhibit locally steep dip.
The motivation for evaluating the potential benefit of further investment in seismic data arises from ongoing field-redevelopment efforts. For such fields, the opportunity space for seismic information expands from simply supporting ongoing field activities to potentially impacting a drilling program of several hundred wells.
Uncertainty Identification Using Pressure Transient Analysis for a Complex Carbonate Reservoir
Authors: Uematsu Hiroshi , lino Atsushi , lizuka Ryo , Al Hashemi Mohamed 
Published: November 2012

Abstract
For robust field development and reservoir management, it is essential to properly identify reservoir uncertainties. In this paper, we present case studies on the analysis of pressure transient data acquired in one of the offshore Abu Dhabi carbonate reservoirs. The complexity of the reservoir creates a number of uncertainties in the pressure transient behavior, making application of conventional analytical solutions insufficient to fully understand the characteristic of the reservoir fluid flow behavior.
The field was first developed by drilling vertical/ deviated wells in 1980's and then horizontal sidetrack was conducted to enhance the well productivity and improve sweep efficiency since early 1990's. We reviewed the pressure transient test data throughout the field history including past surveys for original deviated holes. It was found that most tests in original vertical/ deviated holes were conducted under the oil-water two-phase flow due to the early water encroachment from the underlying thick aquifer. A close examination of these tests showed that wellbore effects associated with the oil-water two-phase flow significantly influenced the acquired pressure data masking reservoir responses. We also identified major static and dynamic uncertainties complicating the pressure transient analysis in this field. The major feature of the pressure transient behavior is a decreasing trend of the pressure derivative. Due to a number of uncertainties existing in this field, this behavior can imply more than one geological setting: thick active aquifer, faults, and vertical transmissibility reduction.
In each pressure transient analysis, we consequently examined all the identified possible mechanisms adopting different fit-for-purpose analytical and numerical models. The fit-for-purpose modeling was found efficient to evaluate many uncertain factors including geological heterogeneities, multi-phase flow effects, and even the pressure interference from neighboring wells. This approach considering all the possible mechanisms enabled us to understand remaining reservoir uncertainties to be further investigated. In other words, this study is useful to identify major reservoir uncertainties and consider further reservoir surveillance to reduce such remaining uncertainties.
Overview of Optical Distributed Sensing for Reservoir Monitoring in TOTAL E&P
Authors: Allanic Christophe 
Published: November 2012

Abstract
Permanent downhole gauges are today routinely part of completion design and the data can be quickly analyzed to accelerate the decision making, with in particular the development of integrated surveillance platforms. However, this classical permanent monitoring is limited, at best, to only few points of measurement, which is, in some cases, not enough to fulfill the monitoring requirements.
Distributed sensing becomes a firm favourite item within all Oil and Gas operators to improve well and reservoir monitoring. Optical technologies provide a distributed measurement all along the well trajectory. A lot of in-well installations have been performed worldwide; however the added value of such monitoring technology still remains to be shared to become a standard or a base case for reservoir engineers in charge of field monitoring plans.
Optical distributed sensing started in TOTAL E&P in 2001 with a first trial in Sincor field (Petrocedeño) (SPE paper). Following this success, TOTAL E&P deployed different DTS or optical sensing systems in different areas and for different reservoir monitoring objectives:
well clean up control well performance monitoring in well flow profiling ...
This paper partly describes he background and current activity of TOTAL E&P in distributed sensing systems and provides some feedbacks from routine monitoring, details from recent pilots, field trials. Capitalizing the experience acquired from the various installations and applications, including treatment and interpretation capabilities, proved to be valuable to promote the deployment of in-well optical distributed sensing technologies with respect to monitoring requirements.
The Benefits of Cold-Work in Middle Eastern Brownfield Projects and High Pressure Subsea Piping Operations
Authors: Homilius Christian , Patel Nitin 
Published: November 2012

Abstract
Two of the biggest drivers in Middle East oil & gas operations today are the continued development and upgrade of existing facilities (Brownfield Projects) and the challenges involved in developing high pressure, high temperature (HP/HT) fields.
These developments come with very different piping and pipeline challenges. In the case of Brownfield projects, it is the ageing piping installations with increased corrosion and leaks, and the need to carry out piping modifications while continuing production. And in the case of HP/HT developments, the challenges include the need to develop robust and effective instrumentation, reliable connections, reduce subsea intervention costs, and operate around existing infrastructure.
This paper will look at how cold-work piping connection solutions can accommodate the challenges involved in Brownfield projects and HP/HT applications, as well as alleviating concerns over traditional methods, such as welding. Such concerns include time, cost, resources, and safety implications.
Referring to the experience gained from installing over 3,000 cold-work connections worldwide, this paper will examine how cold-work solutions generate a simple mechanical connection; the technology of using hydraulic pipes to flange expansion in developing leak-free connections; the importance of no gasket, seals or moving parts in the connection; and the flexibility needed to handle a range of piping diameters.
The paper will provide an example of a recent topside cold-work installation offshore Abu Dhabi - on a field in production for more than 40 years, where the cold-work piping technology was found to significantly reduce the traditional work scope. It will also provide an overview of the choices in taking the technology subsea and applications for critical, high pressure applications through recent testing with Petrobras in Brazil
The paper will provide an important technical contribution to Middle Eastern operators in the form of i) a low impact and flexible piping solution that reduces production shut-down time; ii) increased safety; and iii) introduce significant financial savings.