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Technology Focus Drilling management—management of the drilling process or the process of managing well-drilling operations. Much of this activity is not easily perceived by the outside viewer. Even though the final result of an operation is easily observed, what almost always goes unnoticed is the complexity of the issues involved in the planning and execution of a drilling operation and the number of topics involved in such a process. In recent years, I have been involved in several challenging deepwater-drilling operations, either as an operator or as a nonoperating partner. In all those cases, the planning phase required at least 1 year between the decision to drill on a certain location and the actual well spud-in. And that time frame was for well-established companies with most, or all, service and equipment contracts in place and all key personnel already hired. Off course, the time frame may double, or triple, if a company is initiating an operation in a new region or country where it never operated before. Well planning alone will require (as it must) several months. And this is done before you can even begin to apply for the necessary drilling permit, which in its turn may take several months to be obtained. Also, there is the need for internal reviews, budget approval (internally and with partners), and a necessary peer review, which will result in the need for additional time for implementation of associated recommended changes in the well program. Equally important is a well-prepared risk-analysis study in which risky aspects of the operation will be identified so that preventive measures can be taken to avoid or manage those risks. And then comes the most-visible part of the entire process, the drilling operation itself. Certainly, there must be good management during this phase, which includes the ability to make the necessary changes while dealing with the many aspects of the operation that may not develop exactly as initially planned. And most important, all this must be carried out within responsible and very-strict safety and environmental standards. Ideally, we want an operation to be concluded successfully without surprises or unexpected setbacks, or at least to keep those at a minimum. Careful planning certainly can help to achieve this task. As the famous Norwegian explorer Roald Amundsen once said, “Adventure is just bad planning.” Drilling Management additional reading available at OnePetro: www.onepetro.org SPE 140023 • “Integrated Prewell-Planning Process Improves Service Quality and Decreases Risk Through Cooperation Between Drilling and Geosciences” by J.M. Aldawood, Baker Hughes, et al. SPE 139995 • “Can Safety Improvement Increase Drilling Efficiency?” by S.M. Boutalbi, SPE, Weatherford, et al. SPE 136296 • “Real-Time Data Management and Information Transfer as an Effective Drilling Technique” by Steve Vogel, SPE, National Oilwell Varco, et al. SPE 140145 • “Well-Construction Hydraulics in Challenging Environments” by A.L. Martins, Petrobras, et al.
- South America > Brazil (0.40)
- North America > Canada > Alberta (0.17)
Technology Focus Certainly there is not a single JPT reader that has not already read and heard about the Macondo-well blowout in the Gulf of Mexico (GOM). Over the last few months, this accident has been present in almost every conversation about the oil industry. Many articles have been written, and many more certainly will be prepared and presented at future conferences. The subject has been present in the daily media around the world. In the SPE Drilling and Offshore Operations technical interest groups, several posts have generated heated discussions as well as a diverse array of propositions about how our industry should proceed from now on. So it seems natural that this JPT section dedicated to drilling management also should address the subject. For those of us working in the GOM area, it is more than clear by now that this accident will change the industry forever; and not only in the GOM. Members of the industry, managers and technical experts alike, are taking this occasion to reassess operational procedures, equipment safety, and training needs to find opportunities for improvement that will make our operations safer and more efficient. A proficient drilling-management process is now more important than ever. This process must permeate all phases of a project, from early planning to final execution. Risk assessment of all operations must become a routine. Last year, I wrote in this space about the importance of risk management for drilling and completion operations. I mentioned that there are many articles concerning successful projects in which risk analysis was a fundamental part of all operations. Now may be the right moment for all of us to follow those engaging examples. At the risk of being repetitive, I would like to conclude with exactly the same words that I used to close last year: “It is clear to me that drilling management is related closely to risk management. The correct assessment of all risks involved in drilling operations will provide better planning and consequently will improve operational results.” Drilling Management additional reading available at OnePetro: www.onepetro.org SPE 128288 • “Drilling Efficiency and Rate of Penetration—Definitions, Influencing Factors, Relationships, and Value” by Graham Mensa-Wilmot, SPE, Chevron, et al. SPE 128222 • “High Performance and Reliability for MPD Control System Ensured by Extensive Testing” by John-Morten Godhavn, SPE, Statoil, et al. SPE 128871 • “Real-Time Drilling-Data Analysis: Building Blocks for the Definition of a Problem-Anticipation Methodology” by R.A. Gandelman, Petrobras, et al.
- North America > United States (0.73)
- North America > Canada > Alberta (0.17)
Technology Focus Last April, I had the opportunity to attend the VI Technical Meeting on Well-Engineering Risk Analysis, at Petrobras University, Rio de Janeiro, Brazil, dedicated entirely to risk management in the area of well engineering. That 3-day meeting gave participants an excellent opportunity to exchange experiences, disseminate know-how and current procedures, and discuss problems and critical developments in the area of risk management for drilling and completion operations. I was amazed by the number of diversified works as well as the quality of the presentations, panels, and roundtables. Several topics related to drilling management were presented including risk management for well-control operations, risks involved in the implementation of new technologies, risk analysis for prediction of time and costs in deepwater drilling and completion, the effect of drilling costs on the evaluation of new exploration opportunities, and many others. It is clear to me that drilling management is related closely to risk management. The correct assessment of all risks involved in drilling operations will provide better planning and consequently will improve operational results. Our featured papers bring some examples of better-quality results obtained through superior planning. Project managers, drilling engineers, drilling supervisors, and field engineers will all benefit from careful planning. As most of us should know by now: "If you fail to plan, then you plan to fail" (Saladis and Kerzner 2009). References Saladis, F.P. and Kerzner, H. 2009. Bringing the PMBOK Guide to Life—A companion for the Practicing Project Manager, 49. Hoboken, NJ: John Wiley and Sons. Drilling Management additional reading available at OnePetro: SPE 119287 • "Probabilistic Well-Time Estimation Revisited" by A.J. Adams, SPE, Nexen Petroleum, et al. SPE 114797 • "Advanced Drilling Simulation Proves Managed-Pressure Drilling (MPD) Economical in Gasfield Developments in Western Canada" by Geir Hareland, SPE, University of Calgary, et al. SPE 120848 • "Systems Approach and Quantitative Decision Tools for Technology Selection in Environmentally Friendly Drilling" by O.-Y. Yu, SPE, Texas A&M University, et al. IPTC 12707 • "Automatic Calibration of Real-Time Computer Models in Intelligent Drilling-Control Systems—Results From a North Sea Field Trial" by H.P. Lohne, SPE, International Research Institute of Stavanger, et al.
- South America > Brazil > Rio de Janeiro > Rio de Janeiro (0.26)
- North America > United States > New Jersey > Hudson County > Hoboken (0.26)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.26)
- Europe > Norway > Rogaland > Stavanger (0.26)
Abstract Managed Pressure Drilling (MPD) is an alternative to overbalanced and underbalanced drilling in conditions where pore pressures and fracture gradients are so close to each other (depleted reservoirs, deep and ultra-deep offshore reservoirs) that it is not possible to drill significant depths without setting a casing. While MPD enables an operator to drill longer footages without setting a casing, it requires precise estimation of equivalent circulating density (ECD) during drilling and static bottomhole pressure (SBHP) during non-drilling times. General practice in the drilling industry is to use rheological and volumetric properties of drilling fluids measured at surface to estimate ECD and SBHP. Consequently, ECD and SBHP measured using MWD and LWD tools in the field do not match the theoretical calculations. This study shows the importance of introducing the effect of downhole conditions to hydraulic equations in order to estimate ECD's and SBHP's accurately. Paraffin-based synthetic drilling fluid is used for this purpose. The effect of pressure and temperature on density of fluid is determined using PVT cell experiments. An equation relating the density of the fluid to pressure and temperature is determined using linear and non-linear regression techniques. Rheological characterization of the fluid was obtained on a Fann 75 HPHT rotational viscometer. A Bingham plastic model was used to define shear stress - shear rate relation of the fluid in all pressures and temperatures. The effect of pressure and temperature on plastic viscosity and yield point are determined using linear and non-linear regression techniques, similar to the ones used in PVT analysis. Both onshore and offshore cases are investigated and the effect of incorporating downhole effects to density and rheological parameters on ECD are analyzed. Introduction As a result of the depletion of most of the known reservoirs around the globe, companies are searching for oil and gas in more challenging areas such as deep and ultra-deep offshore locations. In addition, high oil prices motivate the industry to produce the last measure of oil from mature oil fields where the pressure is depleted. The conventional overbalanced drilling technique creates a major drawback to drilling in ultra-deep and depleted reservoirs. In ultra-deep offshore locations, pore pressure and fracture pressure gradients are very close to each other, and with conventional drilling, it is hard (sometimes impossible) to drill a hole up to the target depth. In the case of depleted reservoirs, pore pressure is so low that it is not possible to drill without damaging the formation. These challenges create the need for a new technology to drill in such hostile environments. Managed Pressure Drilling allows drilling of longer intervals by drilling overbalanced while maintaining near constant bottomhole pressure, using a combination of drilling fluid density, equivalent circulating density (ECD) and casing back pressure in a closed system. While MPD will enable operators to drill longer sections and use light drilling fluids, it does require better wellbore pressure management. Only by managing the wellbore pressure, will it be possible to decide on which type of drilling fluid to use and how deep it can be used.
- North America > United States (1.00)
- North America > Canada > Alberta (0.29)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Egypt Field (0.89)
- Europe > Russia > Northwestern Federal District > Komi Republic > Timan-Pechora Basin > Pechora-Kolva Basin > Usa Field (0.89)
Abstract Carbon dioxide flooding has been recognized widely as one of the most effective enhanced oil recovery processes applicable for light to medium oil reservoirs. Moreover, the injection of CO2 into an oil reservoir is a promising technology for reducing greenhouse emissions while increasing the ultimate recovery of oil. Numerical reservoir simulation is an important and inexpensive tool for designing EOR CO2 projects and predicting optimal operational parameters. In this work, reservoir simulations performed with a compositional simulator were applied to investigate the macroscopic mechanisms of a CO2 injection process. Horizontal injectors were used to increase injectivity. Compared to traditional vertical wells, horizontal wells are more attractive to improve CO2 flooding economics by increasing injection rate, improving areal sweep and increasing CO2 storage. The effects of several important parameters on the performance of the CO2 process were studied to optimize the process. Operational parameters such as different production schemes, the injector pressure and injection rate were investigated to determine the optimal - operating conditions for simultaneous objectives of higher recovery and higher CO2 storage. The application of CO2 flooding using horizontal wells can shorten- project life, which is critical to its economics. The simulation results served as the basic input parameters for the economic analysis performed. Furthermore, net present value (NPV) and profitability index results were used to optimize the profitability of the project and to compare the CO2 application using vertical and horizontal wells. The analysis used actual design parameters, including equipment and operating costs. The evaluation emphasized the importance of reservoir characteristics, optimum design of operation parameters and economic factors in the economic feasibility of CO2 injection projects for enhanced oil recovery and sequestration. Introduction The carbon dioxide flooding process can increase oil recovery by means of swelling, evaporating and lowering oil viscosity. Many injection schemes using CO2 have been applied, including CO2 gas injection (continuously), CO2 gas slug followed by water, and others. There are some important factors to be considered during the design of CO2 flooding, including the availability and amount of CO2 to inject, the reservoir conditions, whether mobility control techniques are required and other general operating conditions. Among these factors, the knowledge of reservoir conditions is essential to the injection/production process and, thereafter, the economic success of the project. These include the reservoir temperature and pressure, reservoir permeability and porosity, fractures and faults, etc. Field tests of CO2 floods have shown that reservoir heterogeneities, such as fractures, strata discontinuities and pinch-outs, can reduce the effectiveness of the process. CO2 is a highly mobile fluid because of its low viscosity, so fingering and channeling of CO2 or bypassing of oil can affect the volumetric sweep efficiency in CO2 flooding. In this case, mobility control becomes an important issue for the improvement of CO2 applications. With the increase of productivity performance and the decrease of drilling and completion costs, horizontal wells became more cost effective. This paper compares the conventional CO2 flooding process using vertica
- North America > United States (0.94)
- North America > Canada > Alberta (0.51)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Mission Canyon Formation (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Madison Formation (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Forbisher Formation (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Charles Formation:Middale Formation (0.99)
Technology Focus We all are aware of, and have been affected by, the large swing in oil prices over the past 4 years. I have asserted the importance of evaluation and management of uncertainties when planning the development of a new field or even when revisiting options for mature fields. Higher oil prices may reduce financial risks temporarily for a certain project; however, the complex decisions involved in field development, as well as the many variables to be dealt with, will make almost every project extremely risky. Ultimately, decisions taken in earlier stages, when uncertainties abound, are among the main factors that will determine the level of success of a project. Higher prices may improve the results, eventually, of a project that otherwise would be considered a failure, but the fact is, among the various uncertainties in our business, oil price is paramount. With that in mind, we should give utmost attention in management of uncertainties existing in other factors related to field development, ranging from well drilling to reservoir characteristics. Many in our industry agree, which can be seen by new approaches and recent development of various creative and exciting risk-management tools. Our featured papers this month have some wonderful examples. On a personal note, I would like to mention that after 5 years of writing this column, initially for Subsea Completion and later for Field Development, in October 2008, I will replace Ed May as Chairperson of the JPT Editorial Committee. Ed did a fantastic job of chairing over the last 4 years, and I will do my best to follow his steps, maintaining JPT's status as the primary publication in our industry. I must thank all of you for your constant encouragement and so many thought-provoking emails. Please feel free to continuing writing to me. Thank you. Field Development Projects additional reading available at the SPE eLibrary: SPE 108891 • "Using Geomechanics To Optimize Field-Development Strategy of Deep Gas Reservoir in Saudi Arabia" by Mahbub S. Ahmed, SPE, Saudi Aramco, et al. See JPT April 2008, page 78. SPE 113831 • "The Benefits of Integrated Asset Modeling: Lesson Learned From Field Cases" by M. Rotondi, Eni, et al. SPE 113554 • "Selecting an Optimal Field-Development Strategy for the Vankor Oil Field Using an Integrated-Asset-Modeling Approach" by D.A. Antonenko, OJSC Rosneft Oil Company, et al. Additional reading available at OnePetro: OTC 19254 • "An Overview of the Roncador Field Development, a Case in Petrobras Deepwater Production" by E. Bordieri, Petrobras, et al.
- Asia > Middle East > Saudi Arabia (0.93)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean (0.26)
- Asia > Russia > Siberian Federal District > Krasnoyarsk Krai (0.26)
- Asia > Middle East > Israel > Mediterranean Sea (0.26)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (0.57)
- Government > Regional Government > South America Government > Brazil Government (0.49)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block P-36 > Roncador Field > Maastrichtian Formation (0.99)
- Asia > Russia > Siberian Federal District > Krasnoyarsk Krai > Vankorskaya Area > Vankorskoye Field (0.99)
Recently, during the Second International Oil Congress and Exhibition in Mexico, I had the opportunity to attend a roundtable discussion on "Global Trends in Deepwater Development." The event, held in Veracruz, had representatives from some of the major players in deepwater field development, and most talks and discussions focused on the challenges, concerns, problems, and rewards expected in coming years in the deepwater and ultradeepwater environments. In the Gulf of Mexico alone, it is expected that new oil reserves in excess of 45 billion bbl will be found in the near future. However, improved economic development of those reserves will be achieved only with state-of-the-art technologies in all phases of the project. Efficient field development must take into account simultaneously the constraints in well drilling, production scheme, subsea equipment, and reservoir management. Because only limited information is available in the earlier stages of the development plan, a structured way to handle the risks involved also must be implemented. Establishing a field-development strategy under very-high-uncertainty conditions appears to be the rule in most recent deepwater projects. In the round-table discussion in Veracruz, the panelists seemed to be conscious of the huge challenges ahead and, at the same time, excited and optimistic about the future development of fields that just a few years back were deemed impossible ventures. What do you think? I invite you to read the featured articles presented this month and reach your own conclusions. Enjoy. Field Development Projects additional reading available at the SPE eLibrary: SPE 101286 "Exploration Potential of Sinuous (Channel-Like) Events in Late Cretaceous of Al-Khafji Field, Middle East" by Kalyan Chakraborty, SPE, Kuwait Gulf Oil Company, et al. SPE 107387 "The Challenges of Developing a Deep Offshore Heavy-Oil Field in Campos Basin" by F.P. Figueiredo Júnior, Petrobras, et al. Available at the OTC Library: OTC 18538 "The Dalia Development Challenges and Achievements" by D. Picard, Total E&P Angola, et al.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > South America Government > Brazil Government (0.30)
Abstract Accurate estimation of pressure losses associated with fluid flow in annuli is essential to achieve better bottom hole pressure control in drilling operations. Control of formation pressures and optimization of hydraulic programs can be obtained only if the pressure losses in the circulation system are precisely known. One of the major challenges in determining actual annular pressure losses is that the non-Newtonian fluid flow in annular conduit is much more complex than pipe flow. Many investigators proposed different equivalent diameter concepts to link annular flow to well defined pipe flow. In this study, effect of using various equivalent diameter definitions together with three widely used rheological models is analyzed for different annular conditions. The study is aimed to show how pressure losses vary as rheological model and equivalent diameter definitions are coupled. The effects of the ration between inner and outer radius and the effect of flow rate on the accuracy of equivalent diameters are shown in the study as well. It is important to note that, based on the complexity of wellbore configuration, different equivalent diameter definitions might result in more accurate calculations for different parts of the system. This study provides guidelines to predict frictional losses with higher accuracy. Introduction While drilling fluid is circulated in the annulus, it exerts additional pressure on the wellbore. If frictional pressure losses in the annulus are not determined accurately, the equivalent circulating density (ECD) calculations will also be incorrect increasing the chances of having well control problems. Determination of pressure losses in annulus is harder due to the complexity of the geometry compared to regular circular geometry present in pipe flow. Depending on the clearance between wellbore (or casing inner diameter) and pipe outer diameter, and also on the flow rate required to carry cuttings effectively, flow might be in turbulent or laminar regime. Several authors analyzed the non- Newtonian flow in annular conduits and suggested either empirical or analytical solutions. However, disagreement between calculated and measured pressure losses, due to the complex nature of non-Newtonian fluids, still exists today. Fredrickson and Bird have derived an analytical expression to determine frictional pressure losses in annulus for Power Law rheological model. Their approach gives reasonable results when inner to outer radii ratios are more than 0.5. Kozicki, Chou and Tiu determined a relation between maximum velocity and pressure loss for Power Law fluids flowing in ducts of arbitrary cross-sections under laminar flow conditions. Zamora and Lord proposed a new numerical and graphical technique to determine pressure losses of non-Newtonian fluids in pipes and annuli. The model is valid for Bingham Plastic, Power Law and Yield Power Law rheological models. Langlinais, Bourgoyne and Holden compared actual annular pressure losses obtained from two wells with theoretical calculations. They found out that pressure losses are more sensitive to the definition of annular gap compared to rheological model.
- North America > United States (0.69)
- North America > Canada > Alberta (0.29)
Abstract One of the advantages of Managed Pressure Drilling (MPD) is to determine formation pressures and fracture gradients while drilling. However, in order to determine these pressures accurately, the rheological model of the drilling fluid and pressure losses accruing in annulus should be determined precisely. In addition to the pressure losses in annulus, pressure losses in pipes should be determined accurately in order to determine pump sizing requirements for a successful MPD operation. Un-weighted n-paraffin based drilling fluid system is analyzed in this study. HPHT rotational viscometer is used to determine how rheology of this invert emulsion system changes under down hole conditions. The fluids are tested in the temperature range of 40 – 280 °F and the pressure range of 500 – 12,000 psig. Three rheological models, Bingham Plastic, Power Law and Yield Power Law, widely accepted by the drilling industry, are used to determine rheological characteristics of the drilling fluid and compared with the experiments at various pressures and temperatures. It is found out that, at high shear rates (i.e. > 100 rpm) all models predict shear stresses accurately. However, at low shear rates only shear stresses calculated using Yield Power Law model agrees with the shear stresses measured by the HPHT rotational viscometer data. Pressure losses predictions in pipe and annulus are determined using rheological parameters measured under surface conditions and then compared with pressure losses calculated using Yield Power Law model at actual downhole pressure and temperature conditions. Effects of using surface based rheological parameters and different models on estimating pressure losses in pipe and annulus are shown. Introduction Basically, MPD is a system where wellbore pressure management is obtained by adjusting the pressures along the wellbore using a choke valve at the return line in the annulus. This modern drilling process is preferred over conventional over balance drilling as well as underbalanced drilling in areas where pore pressure and fracture gradients are very close (i.e. deep and ultra deep offshore drilling) or pore pressures are very low. MPD is indicated in situations where conventional drilling techniques are not feasible or non economical. While MPD provides total wellbore pressure management and may also allow real time determination of pore pressure and fracture gradient, the accurate determination of pressure losses in the annulus is essential for the success of the operation. In addition, in the planning phase of an MPD operation, pressure losses inside the drill string should be determined accurately in order to obtain required operating pressures, pump sizing etc. Usual industry practice is to either use Bingham Plastic or Power Law model to define the shear rate – shear stress relation of the drilling fluid considering surface measurements. Similarly, the density of the drilling fluid system is determined at surface and used together with surface conditions' rheological parameters to calculate estimated pressure losses in the well. This methodology will not induce significant errors while drilling shallow onshore reservoirs with water based drilling fluids. However, in deep and ultra deep offshore applications not only the downhole conditions but also the type of fluid being used is different than regular onshore drilling.
Resourceful field development can be achieved only with proper management of uncertainties inherent to any project. This situation is even more noticeable in certain deepwater offshore scenarios in which difficulties of well testing and fluid and core sampling exist. Particularly for cases in which the increasing development complexity is associated directly with uncertainties in fluid and reservoir characterization, a probabilistic analysis, instead of a deterministic one, is the natural way to proceed. In recent years, besides standard reservoir simulation, experimental-design techniques have been introduced to assess uncertainties related to reservoir properties and the project economic aspects. Experimental design is a statistical technique that allows attaining maximum information in a given process at a minimum cost. It allows screening of uncertain reservoir variables and determining which variables, as well as which interactions between them, have the largest effect on the project outcome. On the basis of this information, a more reliable uncertainty distribution can be established. During the past year, an impressive number of papers were presented at the Offshore Technology Conference and various SPE conferences having the main focus on the evaluation and management of uncertainties in field development. Other significant points mentioned in many works were the importance of team-work and the development and implementation of new technologies. Clearly, these aspects are heavily dependent on synergy among geophysicists; geologists; and reservoir, drilling, and production engineers. This month, the featured papers address many challenges found in field development. They also present actual and interesting solutions to challenges by stressing the importance of teamwork and proper management of uncertainty. I hope you enjoy them. Field Development Projects additional reading available at the SPE eLibrary: SPE 100253 "Schedule Optimization To Complement Assisted History Matching and Prediction Under Uncertainty" by H.A. Jutila, SPE, Energy Scitech Ltd., et al. IPTC 10966 "Reservoir-Screening Methodology for Horizontal Underbalanced-Drilling Candidacy" by T. van der Werken, SPE, Weatherford, et al. Available at the OTC Library: OTC 17915 "Kizomba A and B: Projects Overview," by B.D. Boles, ExxonMobil Development Co., et al. OTC 18298 "The K2 Project: A Drilling Engineer's Perspective," by J.R. Sanford, SPE, Eni Petroleum, et al.
- South America > Brazil (0.21)
- North America > Canada (0.17)