bluuebunny/crossref_metadata_2025 huggingface dataset:
Integration of Geoscience and Reservoir Engineering Aspects in Understanding and Developing Highly Fractured Reservoir
Authors: Shuaib M. , Hozayen M. , Al Naqbi N. , Haggag M.
Published: February 2011

This abstract presents a multi-disciplinary approach in identifying the reservoir characterization of an Upper Cretaceous fractured reservoir comprising variety of lithology, texture and facies. The field was discovered in 1965 and has been producing by natural depletion with a strong aquifer pressure support since 1983. All wells in the field are equipped with ESP. Generally, pressure support is from strong aquifer however, field experience immature water cut through fracture corridors and high permeability matrix in parts.

The reservoir is extensively fractured with high degree of heterogeneity due to diagenesis. The fracture network interpretation was the result of integrating FMI/FMS image logs, cores and seismic data. The fractures occur in the form of corridors forming fracture zones/sub-seismic faults. The fracture strikes N40E and N70E with fracture length ranging from 500 to 1000m. The reservoir thickness ranges from some 300ft in the crest to 600ft in the flank. The reservoir porosity ranges from 3% to 40 % and the permeability ranges from 0.1mD to 16 D.

Due to the reservoir heterogeneity, the dynamic data including Transient Pressure, Production Logging, and Multi-rate production tests indicated various well behaviors and performance which is linked to the reservoir properties. Some wells showed fracture dominated system and other wells showed production related to matrix behavior. In some instances fractures enhanced the well productivity while in others they cause sever water production and increased water cut. However, the high water cut in some wells was not only attributed to fractures, but also due to high matrix permeability.

The results and outcome of the integrated work helped in understanding the reservoir behaviour leading to optimization of development plan. In order to control the immature field water cut, contingency plan including ICD is considered.
Successful Application of Fiberglass Pipe in Crude Oil Pipelines in the Arabian Gulf
Authors: Rookus Kees
Published: February 2011

The Oil reservoirs in the Arabian Gulf area have been producing oil & gas for over 50 years. These reservoirs are becoming matured with the following effects: Increased water cut (i.e. increased produced water).Reservoir depletion requires water injection to maintain reservoir pressure.

Water injection and produced water handling is a major part of nearly all ongoing and planned projects in the gulf area. The produced- and injected water is highly corrosive, resulting in premature failure of normal carbon steel. As a result, Oil & Gas producers consider using materials such as stainless steel, duplex/super duplex, chrome alloys ….etc. These materials are very expensive alternatives compared to carbon steel. In addition they are subject to long lead procurement periods.

Glass-reinforced Plastics (GRP) has been considered as an alternative material to carbon steel for applications in corrosive environments. This paper describes the methodology and criteria that were applied for a successful implementation of glass reinforced epoxy (GRE) inter-field three phase crude oil trunk lines in PDO facilities, Oman.

The main objective of utilizing GRE pipes was to prevent corrosion and leaks in the pipelines. This increases the reliability of the system by preventing leaks, and thereby also reducing life cycle costs. The philosophy used for implementing GRE material in such pipeline projects is based on a correct balance between costs and safety of the installed pipe system. This approach is described in ISO 14692 titled “Petroleum and natural gas industries – Glass-reinforced plastics (GRP) piping”. Since 2000, it has been successfully applied by FPI for the supply of > 550 km of GRE pipeline in the GCC area resulting in a field hydro-tests failure rate of less then 1 per 10,000 joints. This is known to be a remarkable low value. Moreover, during this ~10 years period, no joint failures have been reported during the operation of these pipelines.
Modelling Asphaltene-Induced Formation Damage in Closed Systems
Authors: Lawal Kazeem A. , Vesovic Velisa
Published: February 2011

This paper implements a simple one-parameter semi-analytic model for asphaltene-induced reduction of porosity, pore-radius and permeability in closed systems. By treating sedimentation as the dominant deposition mechanism, dynamics of asphaltene deposition under “stagnant” conditions is provided, elucidating the dependence of damage rate on the size of asphaltene aggregates as well as rock and fluid properties. Parametric studies indicate that while the rate of formation degradation depends on rock and fluid properties, ultimate severity of impairment is primarily controlled by in-situ asphaltene content. The proposed model has been used to explain the general observation that light oil systems are more vulnerable to asphaltene damage, than the heavy oil systems. Validity of proposed model is demonstrated by comparing with available experimental datasets that include both sandstone and carbonates. In all cases, experimental results have been matched within 7% accuracy using the proposed model with a single adjustable parameter. Furthermore, thermal simulation studies conducted on a hypothetical but representative heavy oil reservoir highlight the detrimental effects of impairment on field-scale oil recovery and thermal efficiency. Both the models and results presented should be useful for studying impairments induced by asphaltene and other deposits.
Yield and Energy Optimization Initiatives at Saudi Aramco Khurais Central Processing Facility
Authors: Amminudin Kamarul A.
Published: February 2011

This paper highlights the assessments that were made to identify optimization opportunities at Saudi Aramco’s Khurais Central Processing Facilities (KhCPF). Its objective is to maximize yield and minimize energy consumption from the major facility at KhCPF. The work underscores the use of a systematic approach towards process optimization, especially in using process simulation tools. It also involves a multidisciplinary team member task force that collectively identifies opportunities, validates scenarios and formulates the recommendation plan. The present work focuses on the gas-oil separation plant (GOSP) system and its utility system, as they are linked to each other as far as energy consumption is concerned. In the GOSP system, the task force identified key operating variables that affect both yield and energy performance of the facilities. By exploiting these variables; namely, the operating pressure and temperature of the separation system within the GOSP, both yield gain and energy consumption are optimized without compromising the product specifications and plant’s stringent operability and safety aspects.

The optimization assessment demonstrates that additional crude production capacity can still be generated at the expense of lower gas and condensate yields from the facility. In addition, due to a lower amount of gas generated from the separation train, which results in a lower compression requirement, significant annual energy savings could be realized, depending on the recommended initiatives. What is more important to emphasize is that this additional yield and energy savings can be achieved at no cost, or possibly very low cost, to KhCPF. These recommendations also took into account the existing hardware capability to adapt with new operating conditions. Following this assessment, several plant performance tests are scheduled to take place to verify the proposed optimum operating conditions before gearing up for a full implementation of the initiative. It is also anticipated that when the initiative is implemented as new operating conditions, the performance is to be monitored continuously and this requires a performance monitoring tool to be in place.
Understanding Reservoir & System Uncertainties to Enable CO2 EOR
Authors: Gray J. , Reynolds T. , Pedron B. , Khakoo M. , Al Jenaibi F.
Published: February 2011

When implementing any Enhanced Oil Recovery (EOR) or tertiary recovery project it is critical to understand the key variables that influence the success of the scheme – reservoir parameters and fluid properties – and the behaviour of the existing development scheme. The additional components of miscible fluid fronts in heterogeneous carbonates, sources of miscible injectant and the systems needed to manage a miscible EOR development will generate additional uncertainty to that already present during primary and secondary recovery.

This paper describes the reservoir on which evaluation of CO2 miscible EOR has been carried out, the reasons it is a candidate for CO2 EOR and identifies the key uncertainties that will have a major impact on the behaviour of a CO2 development scheme; namely fluid distribution, reservoir structure, compositional variation and reservoir property distribution. A key element of the paper is describing how the uncertainties are recognised and managed by the modelling philosophy, given the relatively immature status of the reservoir development and the limited historical data available.

The paper describes the interpretation of incremental benefits of CO2 EOR over existing development schemes. A small component of the paper discusses options of appraising CO2 EOR further, the approach and need to pilot injection patterns and concepts of phasing development of CO2 into an existing pattern development. Uncertainty range will reduce over time and the paper describes how work emphasised the importance to recognise when this range is acceptably small to make decisions that involve larger capital investment, such as new development options involving additional wells and facilities.

Although the majority of work done in this study was on subsurface elements, this paper briefly touches on infrastructure needed for CO2 EOR and implications of the scheme on existing facilities. Also considered are the external influences that impact EOR value, such as the source of CO2, price of fluid streams entering and leaving the system, and potential for the scheme to be a CO2 storage option once EOR benefit is exhausted.

At present in Abu Dhabi, CO2 or Miscible Injectant (MI) EOR has been recognised as the EOR development of choice by a number of different studies. The fluid types and pressure/temperature regimes in Abu Dhabi reservoirs mean that miscible flooding is likely to be the most appropriate mechanism to further increase recovery factors. Using CO2 also has the benefit of demonstrating CO2 capture and likely storage at a time when the UAE is seeking to curb carbon emissions. Improving the understanding of how CO2 can play a role in Abu Dhabi reservoirs is therefore highly topical.
Carbon Capture Ready Steel Plants
Authors: Balasubramanian Mayuram S. , Afachtal Tarik
Published: February 2011

Nearly a third of the world’s energy consumption and 36% of carbon dioxide (CO2) emissions are attributable to manufacturing industries (1). The iron and steel industry accounts for about 19% of final energy use and about a 25% of direct CO2 emissions from the industry sector (1).

UAE is a major consumer of steel with per capita consumption significantly higher than that for the Middle East (over 20 times) and various upcoming infrastructure projects are expected to drive the steel requirements to even higher levels in the future (2).

The steel industry within the UAE is rapidly adding capacity to reduce the import requirements for steel products. Thus, steel mills are expected to be an important source of bulk CO2 in the future in the UAE, whether for capture and sequestration or for EOR.

The Steel making process determines the type of streams containing the emitted CO2 and the concentration of CO2 in these streams. Different technologies for steel making present different opportunities for integration of carbon capture technologies i.e Post Combustion, Pre Combustion and Oxy fuel type carbon capture technologies. Also, the type and extent of heat/power integration could influence the carbon capture potential and readiness of a steel plant to capture the CO2. The feasibility of energy recovery and carbon capture is also improved by developing a suitable equipment layout.

This paper examines the relationship and impact of steel making technology selection, equipment layout, utility integration and process integration of different carbon capture techniques to establish a concept of carbon capture ready steel mill in the future and to make the existing steel mills more carbon capture friendly.
Comparison of Traditional and Digital Rock Physics Techniques to Determine the Elastic Core Parameters in Cretaceous Formations, Abu Dhabi
Authors: Derzhi Naum , Dvorkin Jack , Diaz Elizabeth , Baldwin Chuck , Fang Qian , Sulayman Ayoola , Soroka William L. , Clark Andrew , Al Dayyani Taha , Kalam Zubair
Published: February 2011

Knowledge of the elastic properties of rock, such as Vp, Vs, and Poisson’s ratio, is required input to accurate and rigorous reservoir description. Traditionally, these values had been acquired from log data or direct measurement in a physical laboratory. Recent advances in imaging and image processing, together with improved availability of high performance computing, gave rise to digital techniques for investigating the properties of rock samples. These techniques are based on high-resolution imaging of the rock’s pore space, segmentation of the images into pores and various minerals and simulation of the physical processes controlled by the desired rock properties. These techniques form the novel discipline of digital rock physics (DRP). The goal of the current work is to validate the results of DRP measurements of elastic parameters by comparing them with the results obtained in traditional physical laboratories.

This study includes eight core plugs from a Cretaceous formation, representing four reservoir rock types. Multiple sub-samples of each core plug were taken and analyzed using the digital rock physics technique.

Our DRP computations are compared with the results of physical measurements of the elastic properties on samples from Cretaceous formations under various stress conditions. The latter measurements were conducted on regular core plugs, several cm in size, much larger than the digital rock samples used in this study. Although some of the physical data represent samples from wells different from where the digital samples used here were extracted, these physical samples cover the rock types included in the study. The elastic property values obtained in the digital rock physics laboratory closely match the results of physical measurements conducted at effective stress about 30 MPa. This validation of elastic measurements using DRP ensures quick and reliable data acquisition, at significantly lower costs.
Malaysia Deepwater Project Execution Strategy and Challenges
Authors: MdSalleh Norain Binti , Bin Sainal M Rashid
Published: February 2011

This paper discussed on the Execution and Contracting plan in Developing and Executing Malaysia’s Deepwater Project, which mostly are considered mega projects for PETRONAS. Currently there are various Deepwater Projects ongoing in Malaysia, operated by various PSC Contractor and as the Host Authority, PETRONAS, through PMU, oversees the overall development. –Many projects utilize different technology.–The scope of detail design, fabrication, procurement, installation and commissioning is complex as it is being executed by various parties.

Several key processes have been implemented in addressing the challenges faced. The processes include Interface management, Capability Development program, Schedule and Cost control. The process applied is described further in this paper.

Results or Conclusion

Best approach in handling mega projects whilst ensuring that all project’s objective is meet and PETRONAS aspiration to be the deepwater hub for the region will be discussed in the result and conclusion portion.
Rock Physics Characterization Using Acoustic Velocity Measurements On Late Cretaceous Carbonate Rocks From the Middle East
Authors: Mokhtar El Amin , Vega Sandra , Abed Hassan Ahmed , Al Baloushi Mariam Nasser
Published: February 2011

We conducted laboratory measurements of Vp (compressional waves), Vs (shear waves), porosity and permeability on forty nine dry carbonate core plug samples at ambient pressure and temperature. We also, performed an initial lithological description, based on Dunham's carbonate rock classification to fully characterize the samples. The study results were analyzed to search for potential correlations between the different rock properties and lithological characteristics. We used cross plots of porosity-permeability, Vp - porosity, Vs - porosity, Vp - permeability, Vs – permeability, and Vp-Vs, for all samples and each rock type.

The preliminary results from our analysis suggest that the acoustic velocities are highly affected by heterogeneity. The study also confirms an inverse relation between porosity and acoustic velocities, where pore size and pore type can be the main factors controlling the acoustic response at a given porosity. In addition, a general inverse tendency between permeability and acoustic velocities is found. The results also show that carbonate mudstones follow consistent trends of porosity-permeability, Vp - porosity, Vs - porosity, Vp - permeability, and Vs - permeability. This result can probably be attributed to the relativlely more uniform internal structure of carbonate mudstones compared with the other carbonate rock types. Wackestones and packestones present relationships that are less consistent and more dispersed than the ones found for mudstones for instance. The rest of the rock types display a great scatter and non apparent relationships. Finally, we find an empirical correlation between Vp and Vs that can be used to identify gas zones.

This study has a great significance in the process of a better understanding of how acoustic velocities from different types of carbonate rocks relate to each other and to their rock properties. This knowledge can potentially be used to diagnose gas zones, predict Vs values, identify different types of carbonate rocks using well log data, and improve seismic interpretation and inversion.
High Reliability Type Gas Lift Equipment
Authors: Hearn William
Published: February 2011

In today’s high cost environment, major efforts must be made to reduce cost, minimize intervention, while maintaining reliability. Production companies are faced with new issues in producing wells with Gas Lift including deep single-point high injection pressure applications while accompanied with rising intervention costs limiting work over capacity and the risks associated with inadequate completion integrity. This presentation will provide insight to some new equipment available; including Gas Lift Mandrels with external check valves that prevent wellbore fluids from entering the casing annulus during valve changes or from leaking gas lift valves improving completion integrity and eliminating the timely process of unloading. The presentation will also include Grooved Solid Body Mandrels that provides additional bypass clearance for multiple umbilical lines with improved protection and pressure ratings. Last the presentation will discuss the benefit of Positive Hydraulic Bellows Protection which enhances the operational life of a gas lift valve.
2010 and Beyond: Managing Talent in the New Age
Authors: Qutob Shereen H.
Published: February 2011

The 2009 recession has shifted the global response to our challenge of “attracting” and “retaining” talent. The average retirement age has extended by at least 5 years with the Boomer generation stretching their stay to adapt to the changes and it is a struggle to lure Generation Y and the “Millenial’s” into the workforce.

The investment in people must become a number one priority. Changes in the global conditions should never impact these investments because the “pay off” always outweighs the cost. The industry cannot talk its way out of something it behaved its way into. So now we need to “walk the talk” and really test our resolve to putting people first.

Talent management plays a critical role. The need to strategically identify, attract, develop, and retain our key talent is crucial and will be the competitive advantage in an age where ‘cost-cutting’ is the word of the day. There is a definite struggle between keeping costs down yet having the foresight to make the investments today.

The dramatic cycle we have been through has shined a new light on career development. Employees now know that they need to take the lead on their own progress. No longer are careers made of a linear “up or out” approach. The dynamics of the workforce have changed considerably and we must adjust as an industry and catch up to accommodate our diverse workforce. Careers are now made up of lattices instead of ‘vertical ladders’ so employees can make lateral or downward moves at different points in their career. Careers will now encompass a multi-faceted path that includes moves into different functions, technologies, and geographies.

The career rules that applied in the past decade no longer apply. Organizations must now become as authentic as they can and put their talent agenda at the forefront. The higher the investment in leadership development and feeding the talent pipeline the bigger the payoff for generations to come. Now is the time to energize this new dynamic workforce about working in such a fast evolving industry. Let’s start talking their “talk”. This is the ‘Facebook’, ‘Twitter’ and ‘Linkedin’ generation. The opportunities to engage this demographic are endless and we can only solve the challenge of the looming shortage and “crew change” by changing the way we “think”.

Gen Y doesn’t want to come to work and become CEO the next day, but they want to learn and be mentored. Within the next 5 years over 50% of our workforce will comprise of Gen Y and the traditionalists and boomers will be well on their way to retirement. Today we’re in oil and gas and traditional energy markets; tomorrow who knows? How can we leverage the best of both worlds and groom these leaders of tomorrow to face the ever challenging terrains? The answer will depend on what leadership seeds we have planted that will yield future leaders who are fluent across multiple disciplines and geographies.
Wettability Profile of a Thick Carbonate Reservoir by the New Rise in Core Wettability Characterization Method
Authors: Ghedan Shawket , Canbaz C. Hakan , Boyd Douglas , Corelab George Mani , Haggag Marwan
Published: February 2011

The evaluation of the reservoir wettability is fundamental to the understanding of fluid flow in porous media. Wettability has direct impact on saturation end points and the shape of capillary pressure and relative permeability curves. This will, in turn, directly affect the relative movement of the reservoir fluids and eventually affect the displacement efficiency of oil by the different injected fluids. Having reliable wettability data deems very necessary for reliable predictions of expected oil recoveries under different development options.

The Amott and the USBM tests are the most commonly used methods for quantifying reservoir wettability. Combination of the two methods is also in use. In addition to the elaborate experimental effort and time required for these methods, the USBM method does not recognize very strongly water or oil wet systems, while Amott method fails to distinguish between important degrees of strong water and oil-wetness.

This paper describes a new technique, the Rise in Core (RIC), wettability characterization method based on a modified form of the Washburn equation. It enables relatively quick, accurate measurements of wettability in terms of contact angle and not wettability index as the other methods do. The method is easy to use and requires no complex equipment. During the RIC experiments, core samples saturated with one reservoir fluid are subjected to imbibitions from a second reservoir fluid. As the imbibition process takes place, the core samples weight changes continuously due to adjustments in relative saturations of the two fluids. Monitoring the square of the core mass change with time using a high precision balance, the acquired data is analyzed with modified Washburn equation to determine the cores wettability.

For the sake of assurance, RIC wettability measurements were compared to ambient conditions modified Amott-USBM measurements for a thick limestone oil reservoir using core plug pairs from different heights above the free water level. The results compare well. The RIC technique proved to be much simpler to construct, much faster to perform and much easier to analyze and interpret than traditional methods. Moreover, the method gives the operator a chance to evaluate the uncertainty in the wettability data.
Reservoir Test Optimization in Real Time with New Wireless Telemetry System
Authors: Al-Nahdi A. A. , Abo Elsaud T. S. , Lemenager E. , Loth M. , Mabrouki F. , Acar C.
Published: February 2011

A new wireless telemetry system has been field tested in a variety of conditions in Saudi Arabia with excellent reliability. This wireless system enables bi-directional communication between the surface and downhole tools during downhole testing (Drillstem Test (DST) / tubing conveyed perforation (TCP))) operations by using an electro-magnetic signal. The wireless telemetry is used to transmit bottomhole pressure and temperature to the surface and permits control of downhole tools. This paper will describe the operating principle of the wireless system, present examples of how real-time bottom-hole data have been used to optimize the testing operations and summarize the key benefits achieved with this new technology. The real time analysis of well testing data during well flow and shut-in was effective in adjusting the test duration. The wireless telemetry eliminated the need for well intervention, which simplified the operation and eliminated the possibility of loss of data.
Applied Production Completion Using Optimum Number of Inflow Control Devices
Authors: Abdou Medhat , Kshada Ali , Shafiq Muhammad , Ogunyemi Olusegun , Chong Tee Sin , Hadjar Karim , Leung Edmund
Published: February 2011

This paper describes a case history detailing design, planning, completions, testing and production of first Inflow Control Device (ICD) horizontal well in one of field in Middle East. In this field, most of existing wells are openhole horizontal producers. A non uniform production profile across the horizontal section can result in early water and gas breakthrough. This can substantially reduce oil production, create zones of bypassed oil and lower the ultimate recovery. In case of early water breakthrough, it will also accelerate the need for artificial lift for individual wells and require increased water and gas handling capacity requirements.

The area of first row of producers located close to the water injectors are now experiencing increasing water cut in some wells causing the well to decline and die prematurely. Objective from the first ICD installation was to test the technical concept of ICD completion in managing the heel-toe effect and reduce the water cut (multiple water entries) in this well, as a first step to mitigate the down-dip and mid-dip problem. Additionally following objectives were set: reduce water cut, optimize production, extend the life of well, prove ICD technology benefits and use to field wide.

A critical aspect of the process way the modeling, prediction and optimization of both reservoir performance and completion hardware design.

After successful ICD design and installation, well was put on production and tested, following results are achieved: oil rate increased by 100%, Water cut reduced by 18% and well head pressure increased by 30%.

The appraisal and acceptance loop of the completion has been closed by having this well completed, put on production and tested. Approval of concept was achieved and the anticipated benefits were realized by actual performance of the well. Leverage knowledge from this pilot well has provided an insight into ICD capabilities and implementation and has set the stage for other fields.
Successful Well Stimulation Projects Boost Production from Iraq's South Oil Fields
Authors: Al-Hashmi Loayd , Qutob Hani , El-Halfawi Sami
Published: February 2011

As Iraq is striving to increase its oil and gas production after years of adverse conditions, efforts are focused on revitalizing existing oil wells to boost the country's production potential. Similar well stimulation projects executed in other parts of the world may seem routine, but the sheer operation conditions in Iraq make planning and control of these projects a major challenge.

The projects involved the stimulation of 180 wells in two of the oil fields (North Rumaila and West Qurna) in southern Iraq. The scope of work covered rigless perforation, stimulation, gas lifting (when required) and flowing the wells for cleanout before being put back on production. Project planning and management activities were carried out from the Dubai office. Coordinating a project of that magnitude, which involved diverse teams from different companies, requires professional project planning and coordination to enable the project to stay on track and achieve excellent results. Work is based on a clear understanding of the properties of geologic formations in the fields under consideration. Accurate analysis of the rock and reservoir fluids properties was used as the determining factor in the selection of the best suitable stimulation fluid composition and the operation technique.

The operation schedule duration was 9 months. Accurate alignment of facilities (camp and acid mixing plant), Equipment (stimulation and gas lift packages), consumables (acid, additives and wilreline) and personnel (12 different groups including third party service companies) was essential for the successful implementation of the project plan. Through good coordination and communication with various parties involved, the non-productive-time (NPT) was kept to a minimum. Detailed well-by-well review of the candidate wells was essential to select the best candidates for this campaign. Fundamental well data (well design information, formation pressures and formation fluid information) were examined and quality assured before designing the suitable stimulation package aiming for a high success rate of the treatment. The design factors included formation damage caused by fines migration, The information regarding chemical reaction between the rock and the acid was used to design the suitable composition of the pre-flush, main fluid, over flush and diverter fluid composition, Due to the presence of high-permeability streaks, the use of diverting fluid was essential to the operation success as it ensures a uniform coverage of the zone to be treated. Professional analysis of the operation results both on the job and after the job was used to improve the learning curve and obtain better results in the succeeding wells.

This paper shows how a well orchestrated field-wide stimulation campaign can be planned and executed to the highest quality and HSE standards, while managing to complete the project ahead of the completion date.
Production Logging in Horizontal Wells: Case Histories from Saudi Arabia Utilizing Different Deployment and Data Acquisition Methodologies in Open Hole and Cased Completions
Authors: Al-Belowi Ali R. , Al-Mudhi Mohammed A. , Hashem Mohamed , Wah Ong Leak , Arevalo Francisco , Rourke Marvin , El Gamal Tarek , Torne Juan
Published: February 2011

The horizontal wells drilled during the last few years are coming to a mature state in different fields and locations. This has created the requirement to evaluate the performance of the wells and determine water sources for proper reservoir management.

In horizontal wells tool deployment, multiple sensor data acquisition and the interpretation of these results is a challenge, particularly when there are long intervals of open hole completions and where fractures are often encountered. The horizontal cased completions use multiple down-hole valves and external packers to provide isolation between intervals.

This paper reviews the two primary deployment techniques of coiled tubing and tractor conveyance and highlights their advantages and limitations for each one. In the paper we propose a general guideline for their utilization.

The case histories in the paper evaluate the different sensors utilized and provide recommendations particularly for low flow rate conditions. Two interpretation methodologies are evaluated and results are compared along with the interpretation from other sensors.

The case studies examples in the paper demonstrate the value of integrating all available information and the value of different data acquisition and evaluation techniques. The conclusions highlight the operational considerations, the data interpretation and added value in the evaluation of well performance to maintain production and improve reservoir management.
RTOC Quality and Excellence Assurance for Well Delivery
Authors: Al-Marzouqi Abdulmohsen Mohamed
Published: February 2011

The objective of this paper is to discuss about ADMA-OPCO Drilling RTOC (Real Time Operation Center) and how it is developing to be capable of monitoring offshore rig operations and improve its performance. The paper will describe a lot of topics about workflow process such as pre-drilling planning and schedule of critical operations which need to be observed on real time. Also the development of real-time optimization process is been focused to be used in near future in the daily drilling activates since it could reduce the drilling cost and minimize probability of encountering problems due to working with optimized parameters. Moreover in this paper the stages to build a high technology center to provide well value assurance will be reviewed The main aim of the RTOC is to minimize the NPT (Non Productive Time) by having 24/7 monitoring services to provide an immediate response and action for any risk that may occur and this will lead to a successful management of all rig operations. Finally the review of ADMA-OPCO RTOC case histories and achievements of 2009-2010 periods will be reviewed and discussed in this paper.
Distribution of Asphaltene Deposition in the Rock Samples by Gas Injection
Authors: Okabe Hiroshi , Takahashi Satoru , Mitsuishi Hiroshi
Published: February 2011

Asphaltene related experiments for the samples from a Middle Eastern reservoir were conducted to assess potential problems in association with asphaltene precipitation caused by gas injection. The study involved three parts, (1) characterization of asphaltene precipitation and identification of problematic areas, (2) quantitative analysis of asphaltene deposition and its numerical modeling (3) field-scale simulation with the developed asphaltene model. Asphaltene phase behavior was measured to understand the relationship among pressure, temperature and asphaltene precipitation due to gas injection. Asphaltene onset pressure was monitored by Solids Detection System (SDS) to estimate Asphaltene Deposition Envelope (ADE), which was the useful measure to predict the risk of asphaltene deposition. The gas injection experiments confirmed asphaltene deposition in the core samples and the permeability reduction. The asphaltene content of the effluent from the core was reduced due to the deposition in the core and the amount of the deposition profile along the core sample was measured. It was found the heterogeneous distribution of the asphaltene deposition along the core. CO2 injection made relatively large amount of asphaltene deposition near the inlet of the core as the CO2 contacted oil at the upstream of the core and the mixing and dissolving to the oil were continued. Consequently, the permeability was reduced due to large deposition at the upstream. However, it did not severely affect on permeability when the asphaltene was equally distributed in the core. The laboratory-measured asphaltene precipitation and its effect on the permeability were modeled by the equation of state (EOS) and the lattice Boltzmann method (LBM). The model was used to understand field-scale behavior by the flow simulation model and it predicted asphaltene deposition around the wells. Asphaltene deposition profiles were different under near miscible and miscible conditions. The miscible conditions had more severe permeability damage around producers although the damage was barely observed around injectors. The permeability reduction was observed after the gas breakthrough. The study covers the laboratory measurements and the numerical modeling. It shows the detail analysis of asphaltene related experiments and modeling is important to identify the risk of asphaltene deposition induced by gas injection, especially CO2 injection.
Impacts of the Number of Perforation Clusters and Cluster Spacing on Production Performance of Horizontal Shale Gas Wells
Authors: Cheng Y.
Published: February 2011

Multi-stage hydraulic fracturing has become the key technology to complete horizontal wells in shale gas reservoirs. In each stage, multiple perforation clusters are used to create multiple transverse fractures. How to place these clusters significantly affects both the short-term and long-term production performance of horizontal shale gas wells. The author’s previous work has demonstrated that when more than two fractures are created, mechanical interaction among fractures creates strong stress concentrations around the inner fractures. As a result, the fractures between two edge fractures, i.e., sub-center and center fractures, are limited to dilate, and their widths are much less than the edge-fractures’ width.

In this paper, reservoir simulation models were constructed by quantitatively incorporating the findings of the author’s previous work to investigate the impacts of the number of perforation clusters and cluster spacing on production performance of horizontal shale gas wells. The paper illustrates that with the same cluster spacing, the scenario with more clusters has lower ultimate gas recovery because of increased number of less-effective inner fractures. Given the same lateral length of a horizontal well, although reducing cluster spacing increases the total number of fractures, smaller cluster spacing doesn’t necessarily improve well performance. An inadequate small cluster spacing can actually lead to more less-effective and ineffective fractures, and therefore lower gas rate and ultimate recovery.
Applying Innovative Production Modeling Techniques to Quantify Fracture Characteristics, Reservoir Properties, and Well Performance in Shale Gas Reservoirs
Authors: Miller Mark A. , Jenkins Creties , Rai Rakesh
Published: February 2011

In order to more accurately characterize reservoir and hydraulic fracture properties from well performance, a workflow has been developed that effectively integrates variable quality data from a variety of sources. This workflow applies analytical techniques designed specifically for shale gas wells followed by as-needed numerical modeling. The analytical techniques can be applied to multiple wells through time to: a) identify groupings of like-performing wells, b) detect wells with anomalous behaviors, c) develop hypotheses about production mechanisms, and d) choose specific wells for more detailed analysis and numerical modeling. Numerical modeling provides the functionality needed for complex mechanism forensics, performance forecasting, and completion optimization studies.

Conventional numerical models typically use finite-difference grids, but these are neither sufficiently complex nor sufficiently flexible for shale gas reservoirs. For this reason, a finite-element modeling technology has been applied that places a large number of closely-spaced nodes near hydraulic fractures, "where all the action takes place" in the early life of a well. The finite-element technique also allows complex fracture geometries to be modeled.

This workflow, incorporating analytical and numerical solutions, has been applied to multiple shale gas projects, including industry consortia in the Haynesville (US) and Montney (Canada) shales and individual operator projects in the Woodford (US), Horn River (Canada), and Marcellus (US) shales. Through the application of these techniques, fracture and reservoir properties have been characterized and uncertainty associated with forecasted well performance has been reduced. This work has profound implications for quantifying gas reserves, understanding those factors responsible for variations in well performance, and for optimizing well spacing, lateral lengths, and completion techniques.
Improving the Recovery of CO2 Injection in Sarkan Oil Field Reservoir in Iran by Selecting the Reasonable Dispersivity Coefficient for Injection Process
Authors: Kamalipour M.. , Farouq Ali S.M.. M. , Shahrabadi A.. , Jamialahmadi M.. , Nabimeybodiy J.. , Rostami A. Jannat
Published: February 2011

Evaluation and improvement of sweep efficiency are important issues of miscible displacement process. Miscibility is controlled by physical dispersion during miscible processes. It comprises of two parameters: diffusion and mechanical dispersion. Unfortunately this parameter is usually ignored during simulating the miscible processes which would be considered as an enormous source of error. Results show the existence of three regions at which each component of physical dispersion controls the miscible CO2 injection. For dispersivities between 0.123m to 0.175m the miscible process is controlled by physical dispersion mechanism while dispersivities lower than 0.123m specifies a region controlled by diffusion in the field case. The third region is the region for dispersivities greater than 0.175m and the main parameter affecting the miscible process in this region is mechanical dispersion. This study discusses the the effect of this parameter on recovery, mixing zone length and breakthrough time of injecting CO2 in a natural fracture reservoir in Iran.
Jiangsu Oilfield’s Carbon Dioxide Cyclic Stimulation Operations: Lessons Learned and Experiences Gained
Authors: Yang F.. , Deng J.. , Xue Y..
Published: February 2011

The first carbon dioxide (CO2) huff ‘n’ puff experimental project was conducted in 1997 in Jiangsu oilfield, China. This paper reviews design and performance data on 70 CO2 huff ‘n’ puff projects conducted in different wells in Jiangsu oilfield from 1997 to 2004. For the Jiangsu reservoirs with light crude oils, reversal of production damage and enhancement of oil swelling aided by gravity drainage are believed to be the most significant mechanisms contributing to increases in oil recovery. The objective of this paper is to examine important parameters, best practices and lessons learned that contributed to the success of CO2 huff ‘n’ puff operations and their use in further improvement in CO2 huff ‘n’ puff projects.
Assessment of Leakage Pathways Along a Cemented Annulus
Authors: Deremble L.. , Loizzo M.. , Huet B.. , Lecampion B.. , Quesada D..
Published: February 2011

Well integrity is one of the major concerns when assessing the containment of a geological CO2 storage. Whereas defect-free cement sheaths provide reliable barriers that prevent vertical migration or leakage of the stored CO2, significant leakage can occur if pathways appear in the cement seal: the stored fluid can flow through and alter their initial properties. A simulator has been built to numerically investigate the leakage rate of CO2 rich fluid through a pathway along a cemented annulus. Careful analysis of the physics and characteristic dimensions of the phenomena allows coupling of the flow, the mechanics of any defect and the chemical reactions that take place in the materials (fluid and cement). Results of the simulation, besides predicting the instantaneous flow rate and hydraulic conductivity of the defect, show different mechanisms of flow rates variation with time: in particular, coupling between flow along the defect and chemical reaction between cement and CO2 can lead to the deposition of minerals within the defect space. This may lead to a total plugging of the pathway – a self-healing of the cement. Based on dimensional analysis and semi-analytical solution, a criterion is defined in order to assess the long-term stability of the pathway.
Overview of the Midwest Geologic Sequestration Consortium Pilot Projects
Authors: Frailey S. M. , Finley R. J.
Published: February 2011

As part of the US DOE's Regional Carbon Sequestration Partnership program, the Midwest Geologic Sequestration Consortium has four active field demonstrations: two EOR pilots, one S/ECBM pilot, and one brine-saturated formation CO2 injection pilot.

The S/ECBM pilot injection period was seven months which ended in mid-January 2009. The pilot included four wells completed in a coal seam at 900 ft. The injection well and three monitoring wells are oriented in the face and butt cleat directions. About 100 tons of CO2 were injected at 0.50-0.75 tons/day. Results indicate the enhancement of methane gas production and sequestration of CO2 through competitive desorption. Presently, post-CO2 water injection pressure transient tests are being completed to identify changes in cleat permeability resulting from CO2 adsorption.

An immiscible (gas) CO2 EOR flood was started in May 2009 in a sandstone at 1900 ft. The injection rate was 20-25 tons/day. A water injection well was converted to a CO2 injection well. The well is centrally located between eight oil producing wells. CO2 injection ended in May 2010 with cumulative injection of about 7,200 tons. Twelve months of water injection are planned after CO2 injection. Several 100 barrels of incremental oil recovery have been measured; less than 5% of the injected CO2 has been produced.

A liquid CO2 EOR, inverted 5-spot pilot was started in September 2009 and injection continued through January 2010 until winter road restrictions were enforced. During this time 2,860 tons were injected at 25-30 tons/day. While road travel was restricted, 13,000 barrels of water were injected. CO2 injection resumed in May 2010 and is planned to continue through the summer. At the end of the first CO2 injection period, the pattern’s oil production rate increased 200% from its baseline.

The injection well of the deep saline formation test was drilled and completed in 2009. A verification well is scheduled to be drilled later in 2010. Injection is planned for 2011. The UIC permit process is near completion. This one million ton injection project will be in the Mt. Simon sandstone, the deepest sedimentary formation in the Illinois Basin. Injection rates of 1,100 tons/day are anticipated.