bluuebunny/crossref_metadata_2025 huggingface dataset:
Use of Real-Time Surveillance Data for Reservoir Management in a Heterogeneous Carbonate Reservoir
Authors: Konwar Lakshi , Al Zaabi Noura Sultan , Mirza Assif , Mohamed Al Ameri Shaikh Rakkad , Tariq Syed
Published: November 2012

This paper demonstrates the value of collecting and interpreting real-time data for reservoir surveillance. We present three examples of real-time data acquisition and interpretation. The first example shows how formation pressure while drilling (FPWD) data provides permeability quantification for placement of a horizontal lateral. Initial performance of the pilot injector confirmed optimum placement of the well demonstrating value of information (VOI) from real-time data acquisition. In addition, pressure data helped in understanding the pressure distribution along the lateral due to support from a nearby gas injector and also in adjustment of mud parameters for drilling.

The second example highlights the use of downhole fluid analysis (DFA) to confirm gas breakthrough detected earlier by open hole logs, to estimate gas oil ratio of the producer and help selection of fluid sampling point. Integrated analysis of logs, modular formation-dynamics tester (MDT) pressures, DFA results, flow test data and subsequent PVT analysis of oil provided indication of complex gas movement from injector to producer and provided insight on vertical sweep of gas.

The third example demonstrates the use of permanent downhole gauges (PDHG) data for real-time performance monitoring of a maximum reservoir contact (MRC) well. Results of the analysis show clear evidence of voidage balance from nearby MRC injector and underscore the feasibility of field development with water injection in a lower permeability area. Combining the effective well length derived from production logging tool (PLT) data, the example also illustrates pressure /rate deconvolution analysis to determine permeability and skin. Additionally, rate-transient analysis (RTA) is done using rate and high-frequency long-term pressure data to compute permeability, skin and drainage area of the well.
Using Residual Oil Saturation (Sor) to Reduce Uncertainty in Reservoir Modeling - A Case Study
Authors: Al-Housani Habeeba , El Wazeer Fathy , Elsayed Ali Ahmed , Al-Sahn Hani , Xu Siqing
Published: November 2012

Residual hydrocarbon saturation is one of many important inputs necessary to have an accurate dynamic model. It is defined as the remaining hydrocarbon after the reservoir has been fully flooded. An Sor study has been performed in one of the major carbonate fields onshore Abu Dhabi UAE. The hydrocarbon is oil and the flooding fluids are water and lean gas. The residual oil saturation to both water flooding (Sorw) and to gas flooding (Sorg) were calculated.

The determination of Sor is one of the most difficult Petrophysical parameters to be precisely determined in carbonate reservoirs due to their high degree of heterogeneity. In this study we applied practical methods using all available data such as Core data (Sponge core, Liquid trapper & Imbibitions SCAL), Cased hole PNS logs and Open Hole Resistivity logs. Pros and cons of each method will be addressed in the paper. A comprehensive data matrix & analysis was completed; results from different methods were compared to select the appropriate value to be used in the dynamic model.

The impact of the Sor uncertainty on oil recovery was evaluated by performing an uncertainty analysis in the dynamic modelling, for example, an on-going major project which aims to assess the value of developing one of the most complex areas within the field. Uncertainty of both Sor to water and gas were evaluated by assigning ranges based on actual measurements. The study results lead to recommendations for additional field Sor measurements and data acquisition optimisation to reduce remaining uncertainties, which will be presented.
Challenges in Managing Mega Projects in Oil Refining Industry
Authors: Al Yabhouni Al Dhaheri Mohamed O. , Harrision Philip S
Published: November 2012

This paper reviews the challenges faced in the Management of TAKREER's mega Ruwais Refining Expansion Project to achieve high standards for Safety, Quality, Schedule and Costs.

Applications

During the Front End Engineering & Design (FEED), it was recognized that the Project could not be handled as one Contract, for the following reasons:-

Facilities over widespread area. Facilities over widespread area. Numerous process units that are technology intensive. Large utilities requirements Widespread offsites. Huge tankage and product blending requirements. Separate marine facilities requirement. Large financial risk Schedule risk

Seven separate EPC Packages are identified that were defined along logical boundaries and quantum of works. This Strategy presents challenges due to:-

Separate EPC Packages have created numerous interfaces between each Package. Over three thousand interface points have been identified with Responsibilities defined between Packages. There are multiple Process Technology Providers that are interdependent through the processing train requiring efficient and accurate detail design. There are many issues related to logistics such as movement of men and materials. A large multi-national/cultural labour force is engaged comprising 50,000 peak manpower. It is important to ensure that EPC Contractors carry out Engineering, Procurement and Construction as one integrated activity and not each in isolation with different aims and ideals. Otherwise Project will succeed to fail.

Results and Conclusions

The scope of mega Projects needs to be well defined with all entities working together cohesively to achieve success. Manage the Interfaces so that barriers are not formed. Team work is the answer. Manage the Logistics to move men and materials safely and efficiently. Engender Top-down Safety Culture.
Enhancement of Geosciences Workflow through an Efficient, User–Friendly Database Management System
Authors: George Bina , Rudiyono Rudi
Published: November 2012

TOTAL ABK has been operator of the offshore Abu Dhabi field, Abu Al Bukhoosh (ABK) for nearly 40 years. As the field has matured, the field has increased in complexity as has the volume of data, the number of users and the requirements for data handling. With the constant movement of personnel within the affiliate it is absolutely essential that the gold mine of data is kept up-to-date with new users confident that historical data has been reliably stored. When the field came on stream in 1974, slow, unwieldy computer technology had only just begun to emerge in some of the larger companies but technology has advanced dramatically since then and the power of IT is now revolutionizing the way we perceive and use data. The challenge, today, is thus to improve efficiency of storing and accessing data, which is continuously required for interpretative engineering work.

Efficient data management along with a user-friendly interface can help overcome this challenge. The concept of a "GeoInformation" Department was invented by TOTAL to manage the company's data efficiently, so their engineers could focus on field studies. Capturing the data from its birth, checking its quality, classifying it and finally storing it with standard templates is the key to data management. The workflow and the quality control check for each data point and type is different.

Once data is stored in a database, a user-friendly interface (Integrated Reservoir Tool, IRT) with single access point is used to access, visualize and extract the data efficiently. IRT with different charts for various data types enables users to make quick analysis and decisions. Some automated data extractions are also made simple.

By having a master database, the quality and uniqueness of the data is guaranteed. Moreover, the historical data recovery is centralized. If the data is not present in the master database, the user can be confident that the data does not exist. User can access and extract the data by themselves without any support.

The beauty of the system is that it is an IT system built by IT specialists but designed and used by geoscientists. The database is no longer a "black box", it is a living system accessed every minute by geoscientists both onshore and offshore.
Full Integrated Diagenesis and Reservoir Rock-Log Typing: Case Study of Two Complex Carbonate Reservoirs
Authors: Al Mazrooei Suhaila , Matthews Anna , George Bovan , Looser Mirko , Allen Joseph , Soyhan Nurgul , Abbassi Hamid , Mittal Vinod , Al Ali Ibrahem , Hall Jonathan
Published: November 2012

Development of complex carbonate reservoirs requires a thorough evaluation of rock properties, especially when the reservoir has been highly influenced by diagenetic processes. Understanding the distribution of reservoir quality is a prerequisite to successful prediction of reservoir performance. This study focuses on the integration of diagenetic studies with reservoir rock-log typing. The objective was to understand the present day pore space system by evaluating the diagenetic overprint and its control on the studied reservoirs porosity, permeability and capillarity.

In the cored intervals of the studied reservoirs the lithofacies indicate a high energy shallow, water platform environment prevailing during Early Cretaceous time. Both reservoir thicknesses vary between 20 and 30 feet in thickness. Average porosity and permeability are less than 20% and 20 mD, respectively.

Detailed petrographic evaluation, stable isotope analysis, cathodoluminescence and fluid inclusion analysis were employed to develop the diagenetic model. The major controls on reservoir quality and diagenetic feature distribution were integrated and mapped within the sequence stratigraphic framework.

Furthermore, a diagenetic facies scheme was established incorporating core description, petrography, RCA and MICP. The diagenesis evaluation was followed by a reservoir rock typing study to demonstrate the relationship between the identified diagenetic facies and established reservoir rock types using RCA, MICP and log data.

Reservoir rock types were distinguished by their distinct storage and flow capacity characteristics from MICP and RCA. Multivariate statistical techniques were used to classify reservoir intervals into their reservoir rock types from the log data. Correspondence analysis was performed to corroborate relationships between the diagenetic facies and reservoir rock types. This was validated using saturation height functions within/between rock types.

The results of this study will have lasting value to the asset. The geological and reservoir models being developed reveal controls and distribution of reservoir quality and can be updated and optimized with future planned data acquisition.
Challenges Make Championship, First Dual Lateral Well with Slotted / Blank Liner in ADCO: Utilizing Latest Technology to Challenge the Business Plan
Authors: El-Saify Abdel Fattah , Al Menhali Adnan Mohammed , Al Shamsi Juma , Kuyken Chris
Published: November 2012

Dual lateral drilling represents one of the industry's most challenging engineering accomplishments, which will have huge impact on saving days and cost in business plan. Dual lateral is a technique delivering higher production by drilling minimum number of wells as the recovery of oil and gas becomes more complex. Those drilling techniques would broaden our limits to comply with the world's increase in demand while maintaining the high level of Health Safey Enviroment (HSE).

Multi-lateral drilling techniques were successfully enhanced and implemented in one of ADCO's highest risky potential fields. The project was successfully delivered ahead off the planned duration leading to a positive significant impact on saving business plan days and cost. There were numerous challenges in terms of the harsh sour gas environment and successfully achieving the highly complex directional requirements. In addition, the open hole logging data were safely acquired. The well was completed with a 6628 ft slotted liner and blank off bottom liner with External open hole Circulating Packer (ECP) with successful cementing operation.
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

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

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

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

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

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

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

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

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

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

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

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.
A Scenario for the Creation of H2S Heterogeneities in Acid Gas Reservoirs in Contact with an Active Aquifer: a Simulation Study
Authors: Bonnaud E. , Dessort D. , Lagneau V. , Chiquet P.
Published: November 2012

Compositional heterogeneities of H2S have been noticed in many sour gas reservoirs. Its occurrence is an important factor of economic depreciation. Thus, the knowledge of its content and distribution is a critical parameter when planning field development. The paper aims at exploring the role of an active aquifer in the creation of H2S heterogeneities in high H2S-bearing gas reservoir. Indeed, under conditions of pressure and temperature of typical reservoirs, H2S is far more soluble than hydrocarbons and other gases. A preferential leaching of H2S (e.g. versus CH4) over time is thus possible.

This mechanism is controlled by: (1) Differential solubility of gases, which change the relative amounts of each gas near the gas-water contact (GWC); (2) Contact with an active aquifer, which can export the dissolved gases thus enhancing dissolution on the long-term; (3) Diffusional transport in the gas phase, which transfers the compositional anomalies farther from the gas-water contact; (4) Geological parameters (type of aquifer, permeability heterogeneities) which can modify the transport scenario.

To illustrate and quantify this process, we show the results of numerical simulations, performed with the two-phase transport and geochemical software Hytec. First, a very schematic reservoir with a composition considered uniformly distributed within the reservoir, has been simulated to quantify the leaching of H2S. The results highlight the potential role of the active aquifer, which can leach the gases and export them outside the reservoir. In a second phase, the effect of geological parameters on the H2S heterogeneity development was studied: additional simulations were performed on geometries closer to natural cases. The amount of leached H2S depends strongly on the geometry: the larger the GWC area, the larger the amounts leached.
Four-Fluid-Phase, Fully Implicit Simulation of Surfactant Flooding
Authors: Patacchini Leonardo , Loubens Romain de , Moncorgé Arthur
Published: November 2012

The Microemulsion phase behavior model based on oleic-aqueous-surfactant pseudo-phase equilibrium, commonly used in chemical flooding simulators, is coupled to Gas-Oil-Water phase equilibrium in our new four-fluid-phase, fully implicit InHouse Research Reservoir Simulator (IHRRS). The method consists in splitting the equilibrium in two stages, where all the components other than surfactant are equilibrated first (e.g. using a black-oil, K-value or equation of state model), and the resulting Gas, Oil and Water phases are then lumped into pseudo-phases to be equilibrated using the Microemulsion model. This subdivision in stages is conceptual, and at each converged time-step the four phases (Gas, Oil, Water and Microemulsion, when simultaneously present) will be in equilibrium with each other.

The fluid properties (such as densities, viscosities and interfacial tensions) and rock-fluid properties (such as relative permeabilities), required in the transport equations, are evaluated with models from well-known industrial or academic simulators. Surfactant flooding being usually implemented as a tertiary recovery mechanism, on fields for which complete models that we do not wish to modify already exist, particular care is devoted to ensuring continuity of the physics at the onset of surfactant injection.

Our code is validated against a reference academic chemical flooding simulator, on 1D corefloods where the original hydrocarbons in place form a dead-Oil phase, possibly with free dry-Gas. Some numerical aspects of our implementation such as numerical dispersion versus time-step size and nonlinear convergence performance are also discussed. As an application example of our code where it is necessary to account for four phases in equilibrium, we consider a scenario where the chemical flood is preceded by a vaporizing Gas drive.
Improving Waterflood Recovery Efficiency in Carbonate Reservoirs through Salinity Variations and Ionic Exchanges: A Promising Low-Cost "Smart-Waterflood" Approach
Authors: Zhang Yi , Sarma Hemanta
Published: November 2012

Our recent study demonstrates significant improvement in waterflood recovery efficiency could be possible in carbonate reservoirs through adjusting the salinity and/or ionic composition of injecting brine, and hence, this approach holds a huge potential to enhance oil recovery from the carbonate reservoirs in the UAE and elsewhere at a much lower cost while freeing up cleaner and greener hydrocarbon gases for other use.

A set of comprehensive tests using carbonate rock have been completed to estimate displacement efficiency, assess wettability variation through wettability monitoring, optimize brine composition vis-à-vis the oil recovered and to explore and better understand the possible mechanisms that are at play. Tests were conducted at temperature ranging from 70°C to 120°C to mimic the UAE reservoir conditions to the extent possible. For both coreflood and wettability monitoring tests, salinity and composition variations were tested on the injection brines, seawater and formation water. In addition, certain mechanisms at play have been identified. Although the research on this approach is still in progress, the following key findings have been noted to date and they appear to have a direct relevance towards improving oil recovery from several UAE carbonate reservoirs:

Reducing water salinity and increasing sulfate concentration of the injection brine could mobilize a significant amount of extra oil beyond the conventional seawater and formation water injection at both 70 ° C and 120 °C. At 70 °C, lowering the water salinity was more effective than raising the sulfate concentration in injection water in terms of incremental oil recovery after secondary conventional waterflood, whereas they exhibited similar potential at 120 °C. And at 70 °C, wettability alteration towards less oil-wetness could be triggered by low salinity water. The process was sensitive to temperature. Lowering water salinity and raising sulfate concentration of the injection water at 120 °C led to a much higher incremental oil recovery than that at 70 °C. At 90 °C, water-wetness of our carbonates could be enhanced by either reducing water salinity or increasing sulfate concentration of the surrounding water. However, the divalent cations in the surrounding water had limited effect on rock wettability. During low salinity water injection process, oil production was usually accompanied with pressure difference increase.
Successful Case Histories of Smart Multilateral Well with Inflow Control Device and Inflow Control Valve for Life-cycle Proactive Reservoir Management in High Mobility Reservoir, Minagish Field West Kuwait
Authors: Al-Enezi Khalaf , Das Om Prakash , Aslam Muhammad , Ziyab Khaled , El-Gezeeri Taher
Published: November 2012

Advanced smart multilateral wells with extended reservoir contact from a single well location have accelerated sustained oil production and increases hydrocarbon recovery from ultra-high water mobility oil-wet Burgan reservoir in Minagish Field West Kuwait. Further the smart multilateral wells have proven to be a great tool for adequate proactive reservoir management and production management without well interventions. The Burgan reservoir has active aquifer, very high permeability sands associated with active faults and contain highly viscous reservoir fluid with downhole viscosity of more than 40cp, enhance water mobility and resulted in premature water breakthrough with increasing water cut trend within few months of production in existing horizontal wells. This has resulted into non-uniform reservoir depletion, by-passed oil regions and low oil recovery. The smart level-4 multilateral wells were successfully designed and implemented in Burgan reservoir by combining the reliable Level-4 junction along with stacked dual lateral completion having customized viscosity independent Inflow Control Device (ICD), customized two Inflow-Control Valves as well as down hole gauges, wide operating range Electrical Submersible Pump (ESP), suitable wellheads, X-MAS tree and Integrated surface panel for real time data monitoring first time in Kuwait. The improved production performance of smart multilateral wells in Burgan reservoir of Minagish Field, West Kuwait have achieved appropriate production management through flow regulations across laterals and adequate reservoir management with the combination of inflow control device as well as inflow control valves along with downhole pressure temperature gauges. Moreover the smart multilateral wells have enhanced sustained oil production, maximizes hydrocarbon recovery at lowered capital and operational expenditure resulted in improved economic performance of reservoir with significant increase in net present value (NPV). The paper covers the successful implementation of smart multilateral wells and its effectiveness in achieving the life-cycle production management as well as proactive reservoir management supported with actual well performance results. Further the paper details about the economic benefits of smart multilateral wells and its contribution in improving the economic performance of Burgan reservoir of Minagish Field, West Kuwait.
Design Challenges of Chemical EOR in High-Temperature, High Salinity Carbonates
Authors: Levitt D. , Klimenko A. , Jouenne S. , Chamerois M. , Bourrel M.
Published: November 2012

The optimization of chemical floods for a low-permeability, high-salinity, high-temperature carbonate formation presents several unique design challenges, which may be overlooked in short coreflood experiments. Low permeability formations require the optimization of polymer molecular weight distribution such that both mobility reduction and injectivity are maximized. Mitigation of emulsion issues - possibly related to high surfactant adsorption - requires the optimization of surfactant concentration and slug size. The effects of high core-scale heterogeneity must be understood and mitigated, for example, by increasing core length. These subjects are explored in the context of an ongoing flood design project. Additionally, an attempt is made to shed light on the discrepancy between available carbonate capillary desaturation curves for carbonates and the near-complete recovery reported in surfactant-polymer corefloods.
Derivation of Kinetic Rate Constant of Enzyme-Buffer Mud Cake Clean Up Systems - Laboratory Investigation and Verification in High Temperature Fractured Carbonate Reservoir
Authors: Mehtar M. A. , Kasam Y. , Al-Aleeli A. , Ghosh B. , Ghosh D. , Chaudhuri B.
Published: November 2012

Horizontal wells enable drainage from a longer wellbore which helps to allow lower drawdown rate compared to vertical wells, minimizing gas or water coning. However productivity can be seriously affected unless mud cake damage is efficiently removed from all producing intervals along the horizontal wellbore. In recent years eco-friendly and non-corrosive bioenzymes (α/β-amylase) have shown great potential in cleaning wellbores uniformly and achieving higher well productivity. However in a low pressure fractured reservoir, there is always a possibility of localized reaction and loss of the clean-up fluid, unless the reactivity of the fluid is engineered based on the given well parameters.

In this study α-amylase enzyme is modified to withstand higher thermal shock by structurally reinforcing the β-Helix layer to strengthen the catalytic centre by preferential protein hydration technique. Buffering was done to maintain different system pH and kinetic rate constant is derived through reducing sugar release measurement by DNS method using starch-xanthan gum-CaCO3 based drill-in-fluid as substrate. Though the overall reaction is extremely complex, a good correlation could be drawn between system pH and the rate of breaking mud cake into simple sugar. The kinetic rate constant index is used in final formulation of enzymatic clean up fluid for application in high temperature (110 °C) long horizontal wells drilled in carbonate formation, which allowed different soaking time due to operational constraints. The results show that there is excellent correlation between laboratory prediction and clean up efficiency in terms of well productivity.The study showed that each individual well demands a specific formula for clean-up fluid and higher than prognosed production could be achieved through custom formulation, based on well condition and operational requirement.