Coral ecosystems are very important as they provide a foundation habitat for many aquatic species. An extensive two years field study was conducted to evaluate the effectiveness of Pulse Amplitude Modulation (PAM) fluorometry in monitoring the health of sensitive ecosystems such as coral reefs along the coast of Qatar. The study demonstrated that PAM fluorometry can provide reliable and objective information on coral health in advance of visual signs of stress. The scope of this study has now been expanded to include laboratory based research.
The objectives for this research are: a) to establish a viable laboratory based coral (Acropora sp.) culture system and b) to utilize laboratory based Imaging PAM fluorometry to compile baseline data, and gain an understanding of environmental parameters that affect the health of the coral.
Laboratory studies were initiated in December 2011; Acropora samples were collected from mother colonies and the “nubbins” were cultured in pre- acclimatized laboratory aquaria. Imaging PAM fluorometry was utilized to measure photosynthetic processes that were correlated to laboratory culture conditions. A wide range of water quality parameters have been measured, including; temperature, salinity, ammonia, nitrate, nitrite, phosphate, calcium and pH.
This research showed that it is possible to successfully culture Acropora coral; the initial colonies have grown to the point that several subsequent colonies have been produced to initiate laboratory assay development. The results of the Imaging PAM also show good correlation with the data obtained using the instrument used in the field.
This study demonstrated for the first time the successful culture of Qatari Acropora in a laboratory setting. The Imaging PAM fluorometry was also used to obtain detailed visual images of photosynthesis processes. Future studies include Acroproa eco-toxicological experiments to study contaminants that could affect coral health.
Hsu, Sheng-Yuan (ExxonMobil Upstream Research) | Searles, Kevin Howard (ExxonMobil Upstream Research) | Liang, Yueming (ExxonMobil Corporation) | Wang, Lei (ExxonMobil Upstream Research) | Dale, Bruce A. (ExxonMobil Upstream Research) | Grueschow, Eric Russell (ExxonMobil Upstream Research) | Spuskanyuk, Alexander (ExxonMobil Upstream Research) | Templeton, Elizabeth (ExxonMobil Upstream Research) | Smith, Richard James (Imperial Oil Resources Ltd.) | Lemoing, Daniel R.J. (ExxonMobil Qatar)
The Cold Lake heavy oil development is located in northeast Alberta, Canada. It began commercial operation in 1985 and uses a thermal recovery process called cyclic steam stimulation (CSS). During steaming cycles, the dilation and re-compaction that occur within the reservoir cause the overburden to deform much like the motion of flexing a thick telephone book. At weak overburden layers, shear slip plane(s) can form due to excessive shear stress overcoming the interlayer cohesion. Over multiple steaming/production cycles, the cyclic flexing and associated shear slip may lead to overburden casing fatigue failures.
In this paper, a multi-scale geomechanics modeling methodology is presented to predict the onset of failure due to CSS-related ultra low cyclic fatigue (ULCF). The modeling methodology consists of: (i) converting geological data into a representative finite element model of a single or multiple CSS pads, (ii) constructing a near-well submodel that includes thermal cement and casing, and (iii) constructing a detailed casing and connection submodel to predict the ULCF life of a pipe body or connection.
To predict the ULCF life of the casing and connection, an algorithm based on the concept of cyclic void growth is incorporated into the submodel. It provides the capability to predict the number of steam cycles to failure using the concepts of demand and capacity. This enables studying the effects of alternative steaming practices on overburden shear slip and casing/connection life.
Based on the learning from the multi-scale modeling, it is found that shear displacements on a shear slip plane can be superimposed using a single-well solution. By applying steaming and production scaling functions, the shear slip can be determined at any location and time. Integration of the single-well solution with ULCF algorithm has facilitated development of a new software tool that can be used to manage CSS operations in Cold Lake.
Significant performance improvement has been achieved by successfully managing drilling vibrations through bottomhole assembly (BHA) redesign. This effort has resulted in increased footage per day and reduced tool damage. Prior literature has described improvements in operating practices to manage vibrations(1,2) as a key component of this ROP (rate of penetration) management process. In a parallel work activity, the redesign efforts have provided additional performance improvements of approximately 36% in one drilling application. Dynamic modeling of the BHA has identified the key design changes leading to these improvements. The redesigned BHA has lower calculated vibration indices than the standard BHA.
The BHA design evaluation process uses a frequency-domain lateral dynamic model in both pre-drill forecast and post-drill hindcast modes. BHA lateral vibrations are characterized such that alternative BHA configurations may be developed and compared directly with a proposed baseline assembly. In the hindcast mode, the BHA model can be operated at the recorded WOB and RPM to generate corresponding model results in time or depth, and these values can be compared to the measured performance data.
In one case study, the redesign of a BHA with downhole motor and roller reamer is described, with corresponding field data for four original BHA's and four redesigned assemblies. In a second application, model and field drilling results for two rotary steerable assemblies are compared to evaluate the predictive ability of the model in smaller hole size and with different BHA types. Finally, the utility of the model to identify preferred rotary speed "sweet spots?? is demonstrated in a motor BHA operating in larger hole.
Two prior publications describe the basic methodology that has been developed to model BHA lateral vibrations. The first paper(3) provides a general description of the model and presents case studies of four field applications of this model. The second reference(4) is a study of 13 BHA runs in the same field, for which slightly different BHA designs and operating parameters were used. The Appendix of the second paper comprises a detailed mathematical description of the basics of this frequency-domain lateral vibrations model, known as VybsTM. The present paper illustrates the application of these methods to a new set of BHA design problems in a joint study conducted by RasGas and ExxonMobil.
Briefly, the modeling process begins with an input panel that is populated with mechanical dimensions of the components of the BHA, usually up to the heavy-weight drillpipe (HWDP), with about the same level of detail as a fishing diagram. It is important that the positions of the contact point constraints are entered correctly, and that the stiffness and inertial properties of the assembly are a proper representation of the subject BHA. Then the desired operating parameters for drilling need to be provided, including the anticipated ranges of bit weight (WOB) and rotation rate (RPM).
The linear modeling process considers a dynamic perturbation about the static state. The model employs two vibration modes to compare and contrast the response of each candidate BHA design: lateral bending and twirl. In the lateral bending vibration mode, an identical reference bit side force input is applied to each design, and the magnitudes of the response at other locations along the BHA are compared. In the twirl mode, an identical mass eccentricity is applied to each model element to investigate the stability of the BHA to eccentric mass and centrifugal force effects.
Shuchart, Chris E. (ExxonMobil Upstream Research Co.) | Jackson, Shalawn (ExxonMobil Upstream Research Co.) | Mendez-Santiago, Janette (ExxonMobil) | Choi, Nancy Hyangsil (ExxonMobil Upstream Research Co.) | Montgomery, John K. (ExxonMobil Upstream Research Co.) | Khemakhem, A.S. David (RasGas Company Limited) | Sieben, Christopher John (RasGas) | Clancey, Byron Michael (RasGas Company Ltd) | Chintaluri S, Ram (RasGas Co. Ltd.) | Farah, Ali M. (ExxonMobil) | Wang, Zhihua (ExxonMobil Qatar)
Effective matrix acid stimulation is one of the keys to maximizing and maintaining long-term North Field well productivity. ExxonMobil and RasGas Company Limited (RasGas) had jointly developed an integrated methodology to optimize matrix stimulation for layered Khuff reservoirs, specifically for K1-K3 and K4 completions. The integrated methodology is a continuous process which consists of five main elements to help overcome the well and reservoir challenges, including reservoir objectives, completion strategy, stimulation design, implementation, and evaluation.1
Success of K1-K3 and K4 completions led to high expectations for K1-K4 completions required for the recent development expansion. However, the much longer K1-K4 producing interval substantially increased the challenges such that existing stimulation tools and methods were no longer sufficient to achieve the aggressive stimulation targets desired for these wells.
Initially, retrievable mechanical isolation plugs were developed and qualified for use to achieve effective stimulation using already proven methods for K4 completions and K1-K3 completions. Due to the increased operational risk associated with mechanical isolation techniques, development of alternative methods and extension of existing methods were necessary. Multiple parallel paths were taken to investigate all aspects of well stimulation, including perforating techniques, diversion, number of stimulation treatments, stimulation vessel capabilities, and well / reservoir productivity. Field trials were conducted for selected technologies, and additional data were collected prior to, during, and after the stimulation treatments. Additionally, a process and associated tools to quantitatively evaluate completion and stimulation options in terms of both initial and long-term production performance were developed. Consequently, stimulation decisions could be made based on reservoir performance metrics balanced with the risks and costs associated with each option.
To evaluate well performance and optimize the stimulation strategy for future wells, an advanced post-stimulation analysis methodology incorporating stimulation predictions, sequential flow data, flowback samples, and production logs has been developed. Results of the analyses suggest stimulation performance comparable to stimulation with plugs, at a greatly reduced completion cost and substantial risk reduction and time savings. Additionally, stimulation strategy optimizations were possible such that the number of stimulation treatments could be reduced for most wells without compromising stimulation effectiveness or predicted long-term performance.
This paper discusses the development and implementation of alternative strategies and designs to effectively stimulate K1-K4 completions without the risk associated with mechanical plugs. Two case histories will be presented to illustrate application of the enhanced methodology.
Clancey, Byron Michael (RasGas Company Ltd) | Remmert, Stephen Matthew (ExxonMobil Qatar) | Sorem, William A. (RasGas Company Limited) | Khemakhem, A.S. David (RasGas Company Limited) | Shuchart, Chris E. (ExxonMobil Upstream Research Co.)
From the start of the current phase of North Field drilling activity in 2002, RasGas Company Limited (RasGas) has continued to push the envelope in terms of both technology and operating practices in drilling and completions. Following the successful introduction of an Optimized Big Bore (OBB) well design in 20021,2,3, advancements have been made in areas of drillstring design, drilling optimization techniques, management of lost circulation events and overpressured water flows, and stimulation technology associated with increasingly longer completion intervals. This paper highlights how these advancements have enabled year-on-year improvement in drilling and completion cycle times, even though well complexity has increased over the same time period.
Postl, Dieter (ExxonMobil Upstream Research Co.) | Ellison, Timothy Kirk (ExxonMobil Upstream Research Co.) | Chang, Dar-Lon (ExxonMobil Upstream Research Co.) | Shuchart, Chris E. (Esso Norge A/S) | Mols, Arnout Laurens (RasGas Co. Ltd.) | Nor, Nazri (RasGas Company Ltd) | Al-Kharaz, Hani Abdul Redha (ExxonMobil Development Co.) | Valle, Antonio (RasGas) | Sieben, Christopher John (RasGas Co. Ltd.) | Chintaluri S, Ram (ExxonMobil Qatar) | Wang, Zhihua (RasGas) | Sanchez, Luis (ExxonMobil) | Farah, Ali M.
Individual wells and their respective completions in the North Field of Qatar are becoming increasingly important and sophisticated. Effective matrix acid stimulation of the very thick, layered carbonate reservoirs plays a key role in achieving and maintaining production targets to meet present and future demand. Completion intervals routinely traverse several layered reservoirs, commingle multiple zones, and span more than a thousand feet in length. The very long intervals give rise to large differences in hydrostatic pressure during stimulation treatments, further complicated by differential reservoir pressures and rock properties (permeability, porosity, acid reactivity) that change both vertically and areally. In addition to this reservoir complexity, multiple stimulation approaches developed for these high-rate gas wells introduced additional variables in the stimulation design. These included mechanical isolation, chemical diversion, and increased treating rates, all of which carry varying degrees of benefits, costs and risks.
Close collaboration between RasGas Company Limited (RasGas) and ExxonMobil has produced a comprehensive toolkit and methodology to effectively stimulate each well and maximize its long-term performance at substantially lower cost and reduced operational risk. The methodology provides an integrated process for quantitatively evaluating and comparing stimulation options in terms of production performance, optimizing these options in reference to physics-based performance limits, and selecting options considering cost, operational complexity, risk, and reward.
The theoretical limits discussed in this paper provide a powerful reference capability that can bracket expected performance. A key learning from the study is that stimulation designs can be implemented that allow wells to perform near their "physics limit?? at significantly reduced cost and considerably lower operational risk than previously understood.
Waters, Lisa B. (ExxonMobil) | Wesselink, Bryan (ExxonMobil) | Edwards, Brant David (ExxonMobil Qatar) | Elimov, Radoslav (ExxonMobil Development Company) | Hurst, Gary (ExxonMobil Development Company) | Jenkinson, Matthew (ExxonMobil Development Company) | Vaughn, Steve
The world's first offshore liquefied natural gas (LNG) storage and re-gasification terminal is a project by Adriatic LNG, a joint venture between affiliates of Qatar Petroleum, ExxonMobil and Edison. Located in the Northern Adriatic Sea, Italy, the terminal, a large gravity based structure (GBS) housing two 9% nickel steel LNG storage tanks and a topsides re-gasification facility, is designed to deliver 8 billion standard cubic meters of gas per year into the Italian gas grid via a 30 inch pipeline to shore. Receiving terminals are an integral part of the LNG value chain with those offshore providing access to gas markets in locations where the coastline is fully developed or inaccessible. This paper discusses key challenges and subsequent learnings gained from executing this unique, international project encompassing a vast array of technical and government interfaces, several new technologies and industry firsts.
The world's first offshore LNG receiving terminal required unique and innovative design and construction expertise, drawing skills and material from over seventeen worldwide locations in twelve countries. Undertaken by contractors new to offshore petroleum industry projects, construction of the concrete GBS at a greenfield site near Algeciras, Spain required strong Company engagement. Unique engineering and construction solutions were utilized to interface first-of-kind modularized LNG storage tanks within the GBS structure. The terminal, setting precedence for government and regulatory approvals, required multi-disciplined teams to achieve jurisdictional consensus with over twenty Italian agencies at all levels. With a pipeline route crossing sensitive wildlife habitats and nearing local tourist areas, extraordinary planning and construction execution were required to mitigate the environmental footprint. Despite numerous challenges, discussed in detail in this paper, construction of the world's first offshore LNG receiving terminal has progressed through the dedicated effort of an experienced, internationally-based project management team.
In March 2005, the operator implemented a rate of penetration (ROP) management process in Qatar's North Field. IPTC Paper 10706-PP describes the general principles behind the new work process and highlights its introduction to the operator. The ROP management process uses real time, customized surveillance technology to continuously maximize both drill bit cutter efficiency and transmission of energy from rig floor to the bit. This paper focuses on specific changes in drilling practices and their translation into substantive program acceleration and capital savings. To date, the development program has been accelerated by one year and USD 54 million has been saved while drilling 470,000 ft of hole. The process has proven to be a highly effective solution for management of drilling efficiency in a major development drilling campaign. As an indicator of program scope and effectiveness, over 440 personnel have been trained in mechanical specific energy (MSE) analysis, and 50 new field drilling records have been set by the nine rigs involved in the program. Importantly, the process has been implemented with one of the best safety records in industry (TRIR or total recordable incident rate of 0.11 per 200,000 man-hours as of September 06).
An extensive big bore gas well drilling and completions program is in progress to develop the giant North Field, offshore Qatar. Benefits of the big-bore concept, compared to the prior 7-in. monobore design, include reduced development costs by requiring fewer wells, and deferred installation of compression by providing higher flowing wellhead pressures.
This is the widest known application of a big bore design in one single field and involves a large number of wells. Many of these wells are drilled and completed to date and believed to be among the world's most prolific gas producers. These are also the first offshore wells to incorporate big bore well design for large-scale field development and feature industry advances in equipment design and manufacture. An extensive system of detailed design review, equipment performance testing, and quality programs has been implemented to meet challenging project requirements for well reliability.
The wells feature a tapered tubing design known as the "Optimized Big Bore?? (OBB). This paper discusses the challenges of planning and executing these OBB wells. It reviews the initial OBB well design, anticipated North Field drilling challenges, critical equipment specifications, and design revisions resulting from optimisation efforts over the past four years.
Discovered in 1971, the North Field of Qatar is the world's largest non-associated gas field, extending over 6,000 km2, and contains approximately 900 TCF of abnormally pressured natural gas. Development has taken place in several stages, commencing with initial production by Qatar Petroleum in 1991 to supply the domestic gas market. This was followed in the mid-to-late 1990s by RasGas Company Limited (RasGas) and other projects to provide LNG to export markets.
More recently, the growth in global LNG demand has sparked much more extensive development. RasGas is responsible for the development of a large area of the North Field, covering more than 500 Km2, to provide natural gas supply for both new LNG trains and the growing domestic gas market. The RasGas expansion plan requires a large number of wells to be drilled in the period 2002 to 2010 from several new wellhead platforms.
Production is from the massive Khuff carbonate formation, which includes several productive intervals (K1, K2, K3, and K4), situated at approximately 10,000 ft TVD. This would differ from the earlier projects of the 1990's that developed only a part of the Khuff reservoir. In total, RasGas will operate more than 90 wells producing a total of 8 Bscfd.
Well deliverability from the K1 to K4 reservoirs is very high due to both formation quality, near initial reservoir pressure, and high net pay thickness. Non-hydrocarbon gas composition varies between the four Khuff intervals within each well and also across the field.
Well designs evolved from packer / tubing completions intended to produce at 60 MMscfd in the initial Qatar Petroleum project, to high-rate 7-in. monobore wells in the first LNG projects able to deliver in excess of 100 MMscfd.1 However, it was recognized by RasGas and its major shareholders Qatar Petroleum and the former Mobil Oil (now ExxonMobil) that higher capacity well designs, capable of producing in excess of 150 MMscfd, could be suitable for the planned RasGas expansion projects. Although individual wells would be more expensive to construct, there were two significant advantages that would result in a more cost effective project. These would be:
Like most costs, air pollution control costs are subject to the law of diminishing returns where greater and greater expenditures result in less environmental improvement per unit of currency spent. Because the pool of funds available for environmental control is not limitless, a wise use of those funds is critical to achieving the greatest environmental benefit for the funds expended. Europe has chosen a process, "best available technology not entailing excessive cost" or BATNEEC, which effectively addresses this problem by balancing air pollution impacts with the cost of control.
The most simplistic approach to defining BATNEEC uses clearly defined steps:
A list of all applicable control technologies for each pollutant is identified.
Next, an assessment of the feasibiltiy and proven commercial status of each process is performed.
Once the unproven and infeasible options have been eliminated, the remaining control options are ranked by the incremental emission reduction effectiveness.
Finally, the control cost efficiency - the environmental control cost incurred divided by the average annual reduction in emissions - is compared with a predetermined threshold to determine if the control is justified.
This simple, straight forward, stepwise BATNEEC procedure as described in this paper gives a consistent, practical method of applying good engineering practice to environmental control.
Initially, most environmental laws and regulations were predicated on the "command and control" principal. In command and control regulation, the regulating governmental agency not only sets a standard of compliance, but also dictates a specific approach to achieving the required statutory or regulatory objective.
In some instances the command and control approach has resulted in cost-prohibitive emissions control strategies that discourage investment in otherwise economically viable projects. In addition, the changing environmental political climate combined with rapidly evolving environmental technology has sometimes resulted in a confusing and restricting set of legal constraints. Unnecessary requirements can result in industry spending large sums of money for little or no environmental benefit or important issues receiving less attention than they deserve because of a lack of resources. This issue is particularly acute for the exploration and production (E&P) industry and has refocused the E&P industry on the importance and validity of the cost-effectiveness criterion in air emissions control technology selection.
While the concept of placing an economic value on environmental resources is rejected by many environmental advocates, resources to control or mitigate pollution are not unlimited. No matter how much money is set aside for environmental control, there are potentially additional controls and safeguards that could be added to a project to reduce emissions or the risk of an environmental effect. Because the pool of funds available for environmental control is not limitless, a wise use of those funds is crucial to achieving the greatest environmental benefit for the funds expended.
Environmental control is subject to the law of diminishing returns where, as greater control is required, larger sums must be spent for smaller improvements in the environment. At some point the cost of incremental increases in environmental control becomes too great to be supported by project economics.