bluuebunny/crossref_metadata_2025 huggingface dataset:
Ensuring Well Integrity in HP/HT Wells: Brunei Case Study
Authors: Taoutaou Salim , Luangkhot-Bonnecaze Alanh , Dondale Aaron , Jain Bipin , Abdullah Nazri
Published: February 2011

Zonal isolation and long-term cement integrity in the high-pressure/high-temperature (HP/HT) environment are critical to optimizing production and minimizing future well intervention and replacement. In addition, the well stresses vary over a large amplitude during construction, testing, and production of such wells. There is, therefore, significant value in avoiding failure of the cement sheath.

In 2007, Total E&P Borneo commenced an HP/HT caMPaign in Block B offshore Brunei to drill development wells with deeper exploration sections. These HP/HT wells are the most technically challenging for well cementing in terms of preserving long-term well integrity; these wells are exposed to high temperatures exceeding 165°C, pressures exceeding 69 MPa resulting from different operations, including production. Cementing these wells using conventional cement and practices has proven not to be effective. This leads to the introduction of new technologies and newer cementing techniques to ensure long-term seal of these wells.

This study identifies first the risks associated with cement sheath failure under downhole stresses. Then it discusses the successful implementation of a solution that ensures a complete zonal isolation of these HP/HT wells, consequently avoiding unnecessary and costly well intervention.
First Successful Low Cost Abrasive Perforation with Wireless Assisted Coiled Tubing in Deviated High-Pressure/High Temperature Gas Well
Authors: Núñez-Garcia Walter , Solares J. Ricardo , Leal Jairo , Duarte Jorge , Chacón Alejandro , Heidorn Robert , Izquierdo Guillermo
Published: February 2011

A number of highly deviated gas producing wells in the southern area of the Ghawar field of Saudi Arabia were recently perforated using coiled tubing (CT) conveyed guns. However, after performing several jobs, it was found that the cost of using the tubing conveyed perforating (CT-TCP) approach was significantly higher than anticipated. Therefore, it became apparent that more cost effective options were required. The decision was then made to trial test the CT abrasive hydrajetting perforating technique.

A well with a gross pay thickness of 130 ft was then selected for the first trial, considering that the chance of achieving job objectives is higher if the selected interval to perforate and the number of slots that can be made in the formation in one run are not excessive. Thus, it was decided to create slots in 12 different sections along the wellbore. Given this constraint, it was important to achieve an optimum depth correlation, which was done by using a wireless real-time CCL tool for the first time in this type of operation in Saudi Arabia. A procedure designed to optimize implementation time and chemical volumes was prepared, and the job was successfully performed with better than expected results.

The objective of this paper is to share results, lessons learned, and solutions used to overcome problems and achieve the successful implementation of a technique offering a valid, low-cost alternative to conventional perforating in a highly deviated well. Full details of the planning and design of the job, operational procedures and data collected are also provided.
Impact of Oil Viscosity Gradient Presence on SAGD
Authors: Chen J. X. , Ito Y.
Published: February 2011

The presence of an oil viscosity gradient appears to be a real phenomenon in the field and its influence on the SAGD process has been studied by various researchers. However, there is potential to refine previous results to exploit the impact of viscosity gradients on SAGD oil recovery process performance. This paper covers our simulation study of the impact of an oil viscosity gradient presence on SAGD operation. Various SAGD operating scenarios in the reservoir with the presence of a vertical oil viscosity gradient were investigated and simulated. The conclusions are summarized as follows:

The presence of a vertical oil viscosity gradient in the reservoir had a mild effect on the SAGD oil recovery rate, while the effect on the oil recovery factor was insignificant. J-Well SAGD, in which a J-well replaces the horizontal producer in a standard SAGD well configuration, did not perform as well as SAGD with a standard well configuration (two parallel horizontal wells). These two conclusions are not in agreement with previous findings by other research groups. Observations from some SAGD field tests indicate the steam chamber could fail to reach the top of reservoirs. For those cases, gas injection could potentially help to recover the oil from the layer above the steam chamber. If that is true, the presence of an oil viscosity gradient might have some impact on SAGD performance with gas injection.

Since local steam trap control is required for J-Well SAGD operation in order to optimize performance, the challenge and feasibility of local steam trap control are also discussed in this paper. Some of the SAGD field evidence will be provided to support our simulation results.
Well Integrity and Workover Candidates for Existing Wells in the Wabamun Area CO2 Sequestration Project (WASP)
Authors: Nygaard R. , Lavoie R.
Published: February 2011

Geological storage of CO2 requires that policy makers, regulatory agencies, and industry ensure that these operations are safe for the public and that sequestered CO2 is permanently removed from the atmosphere. One possible risk identified with storing CO2 into the subsurface is the potential for leakage through existing wells penetrating the cap rock. This study evaluated the well integrity for existing wells in the Wabamun Area as part of a University of Calgary lead study which examined the feasibility of storing 20 Mt-CO2/year for 50 years within 60 km of Wabamun (WASP- Wabamun area CO2 Sequestration Project). A number of large stationary CO2 emitters are located in central Alberta with cumulative annual emissions in the order of 30 Mt CO2. A discrete approach was taken where each individual well was investigated and the need for any additional workovers were on the basis of a decision matrix developed based on current knowledge of well integrity for CO2 injection schemes. When analyzing the existing well population only 4 out of 27 wells were identified as work over candidates. This result demonstrates that well leakage from existing wells is less of a mitigation problem than was first anticipated for this area. For the existing wells only a few had production casing installed through the Nisku formation, which is a situation more prone towards leakage. The other wells had cement plugs through the cap rock with a cement type that will prevent leakage through the Calmar shale. For existing wells that do require work overs, it is recommended they be performed prior to pressurizing the reservoir area. The cost and complexity of properly abandoning these wells will be higher at higher pressures or when CO2 and possibly H2S are present.
Reserves Management: A Concerted Effort
Authors: McMahan Nathan , Munoz Efren
Published: February 2011

Traditionally reserves management has been an exclusive function for Reservoir Engineers; however in mature fields the need to involve Production, Facilities, Geology, Operations Engineers and Financial Analysts is critical. This paper presents a suggested workflow to improve the way reserves are evaluated, supported, booked and documented with a concerted effort of a multidiscipline team. This paper is focused on tight gas reservoirs and the central idea is to reduce the uncertainty that is always present when dealing with reserves.

Most of the discussion is concentrated in understanding and verifying the hyperbolic decline "b" factor to be used for production decline analysis; we normally understand the mathematical meaning, but very rarely spend the time understanding the physical meaning and the consequences of using the wrong value. Once the "b" factor is defined, the proper documentation must be filed for each reserve record and the focus becomes the economic analysis of those reserves which is critical for future development especially in a very volatile economy in which prices are fluctuating a lot.
Interpretation of Immiscible WAG Repeat Pressure Fall-Off Tests
Authors: Stenger Bruno A. , Al Kendi Salem A. , Al Ameri Ammar F. , Al Katheeri Abdulla B.
Published: February 2011

This paper reviewed the interpretation of repeat fall-off tests acquired in two vertical pattern injectors operating in a carbonate reservoir undergoing full field development. Water Alternating Gas first pattern (WAG-1) started in August 2002 with a period of continuous gas injection until 2006 when the first water cycle was initiated. In the second pattern (WAG-2) water injection was initiated in June 1998 until September 2007 when the first gas cycle started.

A few pressure fall-off tests were acquired during the monophasic injection phase mostly to verify well injectivity. After Water Alternating Gas (WAG) cycles started, pressure fall-off tests were usually acquired at the end of each three-month injection cycle with 1:1 WAG ratio. Analytical fall-off test interpretation relied on the use of the two-zone radial composite model. The apparent permeability thickness product was corrected with the Perrine formulation of multiphase mobility. Triphasic oil permeability was calculated using the modified Stone I model. Multiple fall-off test interpretations indicated that the two pattern vertical injectors behaved differently even though both being fractured. The difference in behavior was linked to different perforated intervals and reservoir properties. Gas and water injection rates were showing differences between both pattern injectors as a consequence. No major operational issue was reported during the three-year operation of both WAG patterns. During the WAG cycles, gas banks were found to be of a small inner radius and almost undetectable at the end of the subsequent water cycle. Changes in the pressure derivative slope at the end of the subsequent water injection cycle indicated most likely the creation of an effective mixing zone of injected gas and water in the reservoir.

Numerical finite-volume simulation was required to account for potential injected fluid segregation and, the multi-layered and heterogeneous nature of the reservoir. Repeat saturation logs acquired in observation wells provided critical information on the saturation distribution away from the injection wells. Enhanced vertical sweep conformance through phase mobility control in the presence of strong reservoir heterogeneity was the major expected benefit from an immiscible WAG displacement mechanism. All available observations were reviewed and integrated using a history-matched reservoir simulation sector model with boundary conditions obtained from a full-field model.
Challenges for Horizontal Well Placement Optimization in a Giant Mature Onshore Oilfield, Abu Dhabi, U.A.E.
Authors: Clark Andrew , Al Suwaidi Mohammad , Elabed Amjad , Mead Jeremy
Published: February 2011

The well planning process in ADCO (Abu Dhabi Company for Onshore Oil Operations) is usually driven by subsurface disciplines as part of a full field development plan and consists of a limited number of development iterations related to surface (natural or man-made obstacle) or subsurface (anti-collision, dog leg severity) constraints. The apparent simplicity of this development description is hiding a much more complicated reality for many of the Abu Dhabi giant oilfields that have been producing for several decades. ADCO manages one such asset and is now developing previously untapped reservoirs within an existing mature field and is facing issues such as positioning new facilities; the necessary replacement and upgrade of old surface facilities; surface and subsurface congestion; continuous appraisal activities of additional hydrocarbon-bearing reservoirs; increased HSE compliance and competing land utilization requirements from third parties. Added to this is the diversity and complexity of the professional Information Technology software currently used by the surface and subsurface disciplines, most of which are legacy systems that are not integrated. As such, the business problem of planning and drilling several hundreds of new horizontal wells becomes more critical over time.

Several initiatives have been launched at Company level in order to address these issues such as streamlining the well placement process by using a new workflow Well Approval Process; a common corporate Geographic Information System (GIS) interface, as well as the planned integration with a Drilling Real Time Operations and Control centre (RTOC) for drilling follow-up activities.

While the current process always led to well placement in line with state-of-the-art practices, the on-going process improvements are expected to decrease the current stress level on surface and subsurface asset teams and ensure a manageable load level as drilling activity is scheduled to increase three-fold in the coming two years. This paper discusses the history of the field, its geological setting, the development of surface and subsurface assets and the challenges now being faced and how the challenges are being over come to ensure continue its continued development.
Well Integrity in Heavy Oil Wells: Challenges and Solutions
Authors: Taoutaou S. , Osman T. M. , Mjthab M. , Succar N.
Published: February 2011

Unconventional resources such as Heavy oil are becoming a target of most operators. Wells subjected to steam stimulation for heavy oil recovery are exposed to extreme temperature changes that can vary from 21° C to 348°C. This temperature cycling can have a drastic effect on the set cement sheath causing it to fail with a consequent loss of the well integrity. Loss of hydraulic isolation in the cement sheath will decrease control of steam placement leading to reduced hydrocarbon recovery and potentially health, safety and environmental challenges.

Oudeh Petroleum Company (OPC) has been producing heavy oil since 2006 using the Huff and Puff technique. Complete Well Integrity has been achieved using an Advanced Cement System in more than two hundred wells exposed to steam injection temperatures up to 348°C and consequent high induced thermal stresses (Fig. 1 & 2).

This paper will discuss the methodology of the risk analysis of the cement sheath failure under steam stimulation and selection criteria for the Advanced Cement System to withstand temperature cycling. Two case histories will be presented as well as a 50 well database.
Demonstration of the Power of Inter-Disciplinary Integration to Beat Field Development Challenges in a Complex Brown Field-South Oman
Authors: Belushi F. , Busaidi R. , Mahruqi S. , Lukmanov R. , Mehdi R.
Published: February 2011

An integrated understanding of static and dynamic issues is essential to generate an appropriate life cycle FDP. This abstract will highlight the power of such integration.

First pass dynamic modeling gave very poor history match results. The model significantly under produced the historical gross volumes. Sensitivity analysis on the permeability multiplier, Kv/Kh, viscosity and relative permeability curves were utilized to improve the history match, however, the improvement was limited.

Careful investigation showed that the main reason for the poor history match was the underestimation of permeability in apparently low porosity intervals. These previously unrecognized flow units also contributed to a high vertical heterogeneity.

Further integration and analysis of various petrophysical data, combined with reservoir performance behavior, suggested that these additional flow units were conglomeratic intervals of different gravel sizes. These intervals are characterized by reduced bulk porosity because of the presence of low porosity pebbles in the otherwise highly permeable sandy matrix. Following this re-interpretation, a new realization of the conceptual depositional model, that incorporates the new litho-facies, was constructed.

The static inputs were re-visited; however, due to the lack of core data, identification of the permeability range of the new litho-facies was complicated. This forced maximum utilization of the basic static/dynamic data and analogues.

Analysis of borehole rugosity, oil saturation, reservoir performance and pressure data strengthened the adopted subsurface concept model. A recent core, taken from this reservoir, revealed the presence of conglomerates comprising hard clasts cemented by unconsolidated sands and thereby finally confirmed the interpretation.

The updated models, with minor fine-tuning in dynamic parameters, showed a step change in the history match. This outcome confirmed the presence of high permeable facies despite the low porosity reading at these intervals.

It can be concluded that the vertical heterogeneity, which is often overlooked, can cause complex issues in history match process. However, the better understanding of these features, through multidisciplinary approach, is the key to drive the right solution.

Moreover, maximum utilization of the basic data can paint a picture beyond its anticipated frame. Despite the lack of core data, compiling the subsurface data through multidisciplinary integration provides a powerful tool to mitigate subsurface uncertainties.
First Surface Driven PCP Application on Alaska’s North Slope
Authors: Young James P. , Mathews William L.
Published: February 2011

Alaska’s North Slope (ANS) contains a large resource of heavy oil above two of the largest producing fields in North America, but due to the complexity of producing heavy oil in an arctic environment, remains untapped. Development of heavy oil in the Arctic represents a significant departure from conventional oil developments on the North Slope as well as established heavy oil developments elsewhere in the world. This paper describes a cold heavy oil production with sand (CHOPS) test using a surface driven progressive cavity pump (PCP) to evaluate the resource for commercialization. Despite success using this technique in other heavy oil applications, significant design challenges remain. The test recovered significant quantities of oil and sand at minimal drawdown; however, the capacity of the well was limited by surface torque values that were significantly higher then anticipated and ultimately resulted in a rod failure after 3-weeks of production. Further analysis indicated that torque was dominated by drag forces between the continouous rod string and the oil. Followup testing using oil produced from the well was completed with specially designed test equipment to identify the source of the unexpectedly high torque and provided data to improve rod torque prediction. As a result of the work performed, the remaining three wells in the initial pilot were designed with significant upside in capacity.

Due to restrictive surface locations and permafrost, effective solids transport in deviated wellbores and its effect on equipment wear are key considerations that need to be better understood.
On SAGD in Oil Sands Reservoirs With No Cap Rock
Authors: Alturki A. , Gates I. D. , Maini B.
Published: February 2011

The ever increasing world demand for energy to satisfy the current needs and future economic growth has forced the oil and gas industry to exploit challenging energy resources. Heavy oil and oil sands are challenging due to the complexity of the reservoirs together with the high oil viscosities which are often greater than hundreds of thousands to millions of centipoise. Most steam-based recovery processes such as Cyclic Steam Stimulation (CSS) and Steam-Assisted Gravity Drainage (SAGD) require a competent cap-rock to prevent excessive steam losses and maintain good thermal efficiency and production rates. However, there exist significant amounts of oil sand resources which have little or no cap-rock and thus, at this point, these resources are considered inaccessible. This research examines the feasibility of using SAGD in oil sands reservoirs with no cap rock with detailed thermal reservoir simulation. The results of this research provide guidelines on how to implement the SAGD process in shallow oil sands reservoirs with no cap rock. This could unlock a resource that is currently considered inaccessible. The results show that vertical chamber growth can be controlled to some extent by using variable pressure operating strategies and co-injection of a non-condensable gas such as methane. In oil sands reservoirs without cap-rocks, pressure control is critical especially if there is to be minimal fluid invasion from the oil sands formation into the water zone above. However, the pressure must be sufficient to delay or prevent flow of water into the steam chamber. This study is important since in Alberta, Canada alone there are billions of barrels of shallow oil sands resources without sufficient cap rock to operate conventional high pressure steam recovery processes such as CSS and SAGD. The results of the study provide a technical basis to design feasible low pressure steam processes for such reservoirs.
A Numerical Study on the Deformation of Even Thickness PCP's Stator
Authors: Zhang Jin , Li Wei , Zhang Shicheng , Wu Tingwen , Zhang Yuguang , Zhou Wanfu , Bai Baojun
Published: February 2011

This study focuses on analyzing the deformation characteristics of the elastomer in an even thickness PCP under several simulated working conditions. A three dimensional finite element model involving one pitch length of stator is established to simulate the deformation of the elastomer. It is known that a proper magnitude of interference of the contact pair between rotor and stator is necessary to ensure a proper contact status. An oversize of interference will induce too severe strain as well as too much resistance of torque moment. Nevertheless a deficient interference can not meet the requirement to form the suitable sealed line. Normally an elaborate uniform interference over all contact pair is designed to expect a satisfied contact interaction. However, not only the magnitude of interference is changed because of several factors, such as cavity pressure, thickness of sleeve, dissolution expansion of elastomer, deformation due to temperature change, etc., but also the interference may become unbalanced over the whole contact pair.

In this paper cavity pressure coupled with Poisson’s ratio of elastomer is firstly considered to investigate the deformation rule of elastomer sleeve. After that a rotor rotating in a stator is simulated to predict the characteristic of torque moment and the stress and strain of elastomer sleeve.
Inherent Dangers in PCP Run-Life Field Data Analysis
Authors: Sheldon John , Skoczylas Paul , Alhanati Francisco
Published: February 2011

When performing statistical analyses on PCP run-life data, one can easily reach incorrect conclusions if subtle but important issues are not fully understood. This paper illustrates some of these issues using examples from analysis work conducted recently with a relatively large and complete set of data collected from several large operators. Issues examined include misinterpretation of single-variable correlation results and run-life measures. It is impractical to design and conduct lab or field experiments to investigate the effect of individual variables on PCP run-life. On the other hand, with normal field data, it can be difficult to isolate the effects of individual variables. The assumption of “all else being equal” rarely applies to field data. Additionally, different run-life measures can give different results at different times in the life of a field, even when the underlying system reliability has not changed. Awareness of these issues is essential to all companies that collect and analyze PCP failure and run-life information for the purpose of evaluating and improving PCP system performance.
Natural Fracture Detection, Characterization and Modeling Using the Event Solution Synergy Approach
Authors: Al-Omair Abdullatif A. , Elrafie Emad , Agil Mohammed , Colomar Francois-Michel
Published: February 2011

The detection, characterization, modeling and impact of natural fractures in prolific producing reservoirs are major multidisciplinary challenges. The task, from fracture detection through modeling, is conducted conventionally through limited multidisciplinary integration resulting in poor fracture realizations and understanding. Currently, there is no industry standard workflow that encompasses the wide spectrum of multi-discipline natural fracture detection techniques and modeling approaches. Meanwhile, the availability and range of well performance and formation evaluation data combined with improved reservoir characterization (static and dynamic) techniques have raised the awareness of not only the extent of natural fractures characterization and modeling but also their impact on fluid flow, history match and prediction.

This paper presents a workflow that integrates and leverages different field data types (static and dynamic) to strengthen natural fracture detection, characterization and modeling. In this approach, different data sources are combined and contrasted to derive a most likely natural fracture distribution, understanding and characterization in simulation modeling, including uncertainty range. This industry unique naturally fractured modeling workflow has been developed, adapted and enhanced through the collective experience of applying the Saudi Aramco, synergy-based "Event Solution" (Elrafie et al. 2007) integrated reservoir study approach.

This paper is supported by sanitized projects of large and mature producing reservoirs that firmly illustrate the success of this industry leading workflow and the impact of natural fractures on field production performance. Examples include; premature water breakthrough in reservoir regions and timescales that cannot be matched by matrix flow alone. Likewise, extreme oil rates that cannot be achieved through matrix permeability under measured pressure drawdown. These facts, coupled with static and geological insights are nested together to generate an integrated twenty-two components fracture detection and modeling workflow. Individually and in isolation, each data type component provides impractical and scattered fracture indications; however, the amalgamation of these varied data points narrows the uncertainty range of fracture realizations, yielding a robust and synergized fracture understanding and modeling.

This paper outlines best practices and critical factors of naturally fractured reservoir modeling and dynamic simulation. This includes a unique way of representing natural fractures in the numerical simulation model. Since there are many types of fractures, in this paper to simplify the illustration of the workflows we will target only the fracture corridors or the cluster of sub-vertical fractures that are normally extensive in their length and sometimes associated with shear faults.
Horizontal Underbalanced Drilling Technology Successfully Applied In Field AA- Libya: Case Study
Authors: Mohamed Ben Shatwan , Hani Qutob , Paco Vieira
Published: February 2011

Recently, underbalanced drilling (UBD) has been used with increasing frequency to minimize problems associated with invasive formation damage which often greatly reduces the productivity of oil and gas reservoirs. When properly designed and executed, the benefits of underbalanced drilling (UBD) are well recognized by the industry and there is increasing raise in interest in this technology. The benefits from UBD generally fall into two categories:

Cost reduction- including mitigation of conventional drilling problems as lost circulation, differential sticking, reduction in stimulation and cleanup costs, etc.

Value adding- including productivity improvement, increase in ultimate recovery, and real-time reservoir characterization while drilling.

Arabian Gulf oil Company (AGOCO), a major energy player in the Libyan oil industry, decided to pioneer the introduction of the new technology by embarking on a pilot project to drill 6 underbalanced horizontal wells in field AA. The Field is located in the Libyan Desert on the south east of Sirte basin. The reservoir consists of sandstone from the Early Cretaceous age. The field was first put on production in 1967. Since 1991 ESP pumps have been used for the production. The target reservoir, Member XX, is partly depleted oil bearing reservoir from the initial reservoir pressure of 3995 psi to about 2400 psi (5.3 ppg EMW). 3 out of the 6 well UBD campaign have been drilled so far. The first two wells identified the technology as an effective method to improve penetration and production rates. The third well built on the experience of the previous wells by emphasizing on minimizing formation damage and maximizing the production of the well. Another objective was the evaluation of production while the well is being drilled, eliminating the need for expensive post drilling production testing.
Shale Oil Potential in Saskatchewan
Authors: Schramm L. L. , Soveran D. , Schreiner B. , Kramers J. W.
Published: February 2011

With no commercial mines in operation, Canada's oil shales have not been widely recognized domestically or internationally. Nevertheless, Canada's oil shale resource has been estimated to be 15.2 × 109 bbl, an estimate that may rise with continued exploration across the country. Significant oil shale deposits have been identified in almost every Canadian province and territory, including Saskatchewan. Saskatchewan's oil shale resources are amenable to mining and surface processing but, as is the case with many of the world's deposits, environmental considerations will bolster the importance of developing new "game-changer" technologies that will reduce and/or replace the use of fresh water and dramatically reduce air emissions of CO2, SOX, and NOX. Significant R&D programs are now aimed at developing and demonstrating such new technologies for Saskatchewan's oil shale deposits, in order to make commercially viable a new source of Canadian "technology oil." This paper will provide an overview of oil shale geology, physical properties, and resources, highlighting Saskatchewan's oil shale and some of the novel recovery technologies that are being developed.
Optimize Shale Gas Field Development Using Stresses and Rock Strength Derived From 3D Seismic Data
Authors: Gray F. D. , Schmidt D. P. , Delbecq F.
Published: February 2011

Parameters of interest in hydraulic fracturing are the principal stresses, hoop stress and rock strength parameters such as Young's modulus and Poisson's ratio. Modern seismic inversion algorithms allow us to extract rock strength parameters. We show that they can be estimated between wells from seismic data. The azimuthal response of conventional and/or multicomponent seismic data is related to the stress field of the earth. By combining these methods, the magnitude of the principal stresses and the directions of the horizontal stresses may be estimated and then, hoop stress and fracture breakdown pressure can be approximated. These estimates may be used to guide field development away from existing wells.
Deploying the World’s First Commercial Dual Gradient Drilling System
Authors: Dowell J. David
Published: February 2011

Chevron is working with AGR Subsea, Pacific Drilling, GE Oil and Gas, and others to deploy the world’s first commercial Dual Gradient Drilling (DGD) System. The DGD system will be installed on a Pacific Drilling Samsung 12,000 Class rig currently being built in Korea. It is expected to begin operations in the Gulf of Mexico in 4th Qtr 2011. This paper will detail the design, fabrication, testing and preparations that are being made for that deployment.

Not only is significantly new hardware being added to the rig, but a new set of processes and concepts are being embedded in the drilling organization to take full advantage of the hardware. This has required the simultaneous development of two different, but linked, work streams: hardware and personnel. The “hardware” side of the work has concentrated on the integration of completely new equipment into the rig to make it DGD ready. This includes a subsea pump, a completely new riser, several riser “specialty” joints and all the rig modifications required to handle, run and support this new drilling system. The “people” work stream includes the development of drilling and well control procedures, well planning and the extensive personnel training needed to realize all the benefits of the technology.

This effort has impacted every facet of the Chevron deepwater drilling community. Chevron has reexamined the way rigs and drilling assets have historically been deployed. This has resulted in the development of a “Value Driven Drilling Schedule” to optimize utilization of the technology.

The DGD system could revolutionize how deepwater wells are drilled and how deepwater assets are explored and developed.
Managing the breakthrough of injected Nitrogen at a Gas Condensate Reservoir in Abu Dhabi
Authors: Abdulwahab Haytham , Belhaj Hadi
Published: February 2011

This study investigates the means of deferring the breakthrough of injected N2 and alleviating the impact of such on production rates and specifications as well as minimizing the required changes to the gas processing facilities. This aimed at assisting the ongoing efforts to transfer the Cantarell experience to Abu Dhabi, where large amounts of N2 gas will be generated and injected into a large gas condensate reservoir to partially substitute the recycling of lean gas. This will bring forward the opportunity to exploit lean gas by securing base load supplies before the start of reservoir blowdown, compared to the peak shaving approach currently practiced. Managing N2 breakthrough starts by better understanding the pattern at which N2 injection spreads into the gas accumulation. Based on the findings of initial subsurface and plant simulations carried out in 2008, N2 breakthrough in Abu Dhabi might be possibly deferred by segmenting the reservoir into a rich N2 region and lean N2 region. The approach assumes no thief zones will be faced and no channeling of N2 injected between the two regions is taking place. N2 is injected in the north region of the reservoir. The production of that region will be segregated and fed to a gas processing plant of lower NGL recovery, which essentially takes longer time to start suffering the deterioration of residue gas quality. The residue gas use can be limited to re-injection where the effect of below specification LHV would not be an issue. The rest of the reservoir feeds another gas processing plant of higher NGL recovery level from which an amount of residue gas equivalent to that of the injected N2 will be rerouted to the sales network. This scenario will significantly delay as well as downsize the requirement of a N2 rejection plant. There is technical and certainly economical advantage of deferring the installation of costly N2 rejection units. Such a requirement can be entirely eliminated if the sales gas specification can be relaxed considering blending with other gas streams of higher LHV, and in collaboration with gas customers, i.e. assessing their capability to tolerate feedstock of lower specifications. It must be noted that such school of thinking may not necessarily be eventually embraced. The chosen scenario will also depend on the final configuration, i.e, wells grouping and gas gathering, of the ongoing project.
Well Displacement Hydraulics -A Field Case Study and Simulation Investigation
Authors: Xu Zheng-gang , Maurera Jaimar , Shields Christian
Published: February 2011

Post-completion cleanup operations had left a seawater filled well that needed displacing to N2 via coiled tubing in order to achieve the desired underbalanced conditions for perforating. The unloading process is not steady state therefore dynamic simulator describing multiphase flow behaviour is essential to properly design and implement a displacement operation. To achieve a successful displacement a balance needs to be struck between CT run-in-hole speed, gas injection rate and the choice between continuous or intermittent gas injections.

This paper presents a field case study of a well displacement operation that only managed to displace half of the wellbore fluids when gas injection was critically interrupted and then after several days of using much higher nitrogen injection rates of up to 2000scf/min made no further significant progress.

The paper describes the application of numerical transient simulation to model the actual CT displacement in order to investigate the failures that occurred and gain a better understanding of how the displacement should have been performed. The predicted and measured parameters were compared to validate the numerical model. Different scenarios were simulated to optimize the displacement procedure. An effective solution to displacing the remaining half of the wellbore was first positioning the CT deep below the liquid level and then initiating gas injection. In this way, the liquid could was effectively lifted out of the well as slugs

The primary technical contribution of this paper is the application of dynamic simulation (new technique) to optimize fluid displacement using CT and N2 to lift fluids through the annulus with the added complexity of increasing CT and annular lengths with time. Furthermore, it shows the need to move away from the old "rule of thumb" steady state engineering practices.
A Mobile Multiphase Ram Pump for Onshore Oil Field Applications
Authors: Saadawi Hisham
Published: February 2011

Wells near the oil rim of one of the major oil fields in Abu Dhabi experienced a decline in wellhead flowing pressure. Several options were evaluated to produce these wells. These options included Electric Submersible Pumps (ESPs), conventional wellhead separation as well as multiphase pumping. A pilot project was implemented using a multiphase pump to produce the wells. The selected multiphase pump was of the positive displacement reciprocating type known as the RamPumpTM system.

Key challenges facing this project includes; no power source near the wellhead sites; oil rim wells have a broad range of operating conditions, high GOR wells and high H2S.

In order to allow the multiphase pump to be used for different wells, it was decided to have the pump mobile. Thus, the multiphase PumpPump unit, its driver and associated equipment were all mounted on flat bed truck.

Although multiphase pumping is now recognized as a state-of-the-art technology, this is the first time that a mobile multiphase pump was used in an oil field. This paper describes this unique application.
Waterflood: Surface Management Strategy
Authors: Pedro C. I. , Sutton J. D. , Zhumadilov A. G. , Dordoni F. , Rains D. B.
Published: February 2011

When the topic of "Waterflood" is presented for discussion, our primary expectation is that we are dealing with subsurface issues related to the efficiency of the flood: areal and vertical sweep, processing rate, pressure maintenance, etc.

In West Africa – offshore Angola, the operator came to the crude realization that elevated attention to the surface component of the water injection system was required to achieve the Asset Management objectives (reserves recovery). Twenty (20) years into the waterflood (+/− 3 billion barrels injected, and a current rate of +/− 550 mbwipd), problems with the water injection system revealed themselves as injection capability reduction and/or well tubular failures, resulting in costly workovers to reinstate water injection and to continue providing needed hydrocarbons sweep and pressure support.

With the absence of a robust surface water injection system remediation strategy, the number of well failures and/or reduction of injection were expected to increase. To remediate the situation detailed studies of the existing water injection system were performed, which included: understanding injection wells failure trends, injection water quality analysis, monitoring system evaluation, study of corrosion elements and review of existing injections wells metallurgy.

Results from these studies indicated that the main areas of concern were: ➢Degraded infrastructure➢Water injection quality out of specifications➢Failure trends – 8 to 9 years or 50 million barrels of cumulative water injection➢Severe well completion corrosion➢Poor monitoring program➢Deficient history records

To address these identified problems, a cross functional team was put together with the objective of safely and cost effectively, mitigate the reduction of water injection capability associated with failure of the injection system (pipelines, equipment and/or well failures) by: ➢Devising and executing a remedial program – Wells, infrastructure, equipment etc➢Recommending a long term strategy ■Well completion metallurgy■Water quality specifications■Chemical treating program■Monitoring program

Considerable improvements have been made to date through a business plan supportive of the Asset Management strategies and expansion of the devised water injection system management strategy to other assets within the operated concession.
Challenges in Design of Post Combustion CO2 Capture Facilities
Authors: Kumar Satish , Zarzour Othman , Gupta Anil
Published: February 2011

Abu Dhabi imports natural gas for domestic consumption since 2007 and at the same time injects natural gas in oilfields for enhanced oil recovery. Abu Dhabi presently emits significant quantity of CO2 to atmosphere due to its existing thermal power plants and other industries. An opportunity exists to inject CO2 instead of natural gas and release valuable supplies of natural gas for other uses while storing CO2 in acceptable geological formations to reduce greenhouse gas emissions.

MASDAR have plans for number of Carbon Capture & Storage (CCS) projects to capture large quantities of CO2 from flue gases, which otherwise are emitted to the atmosphere. Efficient recovery of CO2 from flue gases is not only a technical challenge but also it is the most expensive step of any post combustion CCS project. Approximately 20 MMTPA CO2 is aimed to be captured from existing and future power plants, Aluminium smelter, industrial facilities and oil & gas processing plants from 2020 onwards.

This paper presents some of the challenges faced by the design team in (a) flue gas characterization, (b) technology selection for post combustion CO2 capture, (c) provision of utilities, d) finalizing CO2 specifications and (e) assessing potential impact on the environment due to the carbon capture plant. Industry is presently flooded with claims of emerging technologies for capturing post combustion CO2. A brief overview of available technology and key issues — scale-up, high energy demand, validation of technology - is discussed.

Large capacity carbon capture plants are associated with high demand for heating and cooling requirements, which lead to engineering challenges for managing such requirements. Strategy adopted to meet these challenges is discussed and a potential solution is proposed.

Difficulties encountered in getting the design data, variability in flue gas flow and composition, flue gas treatment requirements are presented. Steps taken to characterize the flue gas composition for the design of the carbon capture plant are discussed. Results of flue gas testing and analysis are presented. Methodology adapted to identify the most promising technology for post combustion CO2 capture is described.

Site specific design challenges such as (a) flue gas characterization, (b) technology selection for post combustion CO2 capture, (c) required CO2 specifications, d) heat integration with the existing plant, e) availability of steam and cooling water f) parasitic CO2 recovery, g) unit optimization and h) options for reducing the energy demand are discussed.
Mechanics of Hydraulic Fracture Growth from a Borehole
Authors: Jeffrey R. G. , Zhang Xi
Published: February 2011

A numerical study of hydraulic fracture growth from a circular borehole under plane strain conditions is presented. The coupling of fluid flow and rock deformation plays a key role in the fracture reorientation process and in determining the curved fracture path formed. The fracture path is given as a function of both the nondimensional parameter β, which has been previously described in the literature and applies to fracture growth that is dominated by rock fracture toughness, and the recently derived nondimensional parameter χF, which applies to fracture growth that is dominated by fluid viscous dissipation. The results show that the values of β and χF determine the fracture trajectory as the fracture grows from the wellbore and eventually reorients parallel to the maximum far-field stress direction. Thus, for viscous dominated conditions that are typical of field application of hydraulic fracturing for stimulation, χF is a measure of the development of nearwellbore fracture tortuosity. A larger value of χF implies a stronger curvature and fracture tortuosity. The value of χF is reduced by increasing the viscosity and injection rate of the fluid.
Giant Field A ROS Study
Authors: Serag El Din S. , Al Hammadi Y. , Kalam M. Z.
Published: February 2011

A study was aiming to evaluate the remaining oil saturation (ROS) behind the flood front using Liquid Trapper technology and open hole logs. Four (4) wells were included in this study, two in the South and two in the North of the field. These wells were selected in areas highly flooded by peripheral water injection. The objective is to improve the description of ROS and better estimate the oil recovery efficiency from the field.

The Liquid Trapper Coring technique is used to provide more accurate oil saturation data for the reservoir model. It was used in this project in particular to evaluate the remaining oil saturations in the flooded reservoir zones.

The Liquid Trapper Coring is a technique to capture any oil that is expelled from the core (due to pressure change) by gas expansion as the core is raised to the surface. This volume of escaping oil can then be calculated over selected intervals and incorporated into the standard saturation analysis performed on the whole core sections. The oil saturation determination from core would give the expected remaining oil where as the oil captured in the trapper barrel would indicate any movable oil in the reservoir.

The inner tube of the Liquid Trapper is made of stacked modules, 1m in length and each made up of closed ‘cells’. The cells allow capturing of the expelled fluids and segregation of oil, water and gas due to gravity difference. The fluids in the cells surrounding the core are collected to be added to the volume of oil saturation in the core. The volumes were measured in the laboratory by centrifuge and were added to the saturations measured using Dean Stark method.

This case study presents the results and uncertainties of using Liquid Trapper Technology in ROS determinations behind flood front of water invaded carbonate reservoir zones. An assessment of this new technique, and its pitfalls in onshore reservoir applications is compared with conventional sponge core coring.