bluuebunny/crossref_metadata_2025 huggingface dataset:
Potential Economic Value-Added Model Using Formation Sampling-While-Drilling in Development Fields
Authors: Djefel M. , Tigre C. , Proett M. , Eyuboglu S. , Naupari C. , Beck G.
Published: December 2010

Formation sampling-while-drilling (FSWD) technology has recently been introduced, and this new method of obtaining formation samples is expected to reduce costs in development and appraisal wells. Formation testing on wireline (FSWL) pumpout tools have become the preferred method for obtaining formation samples in the drilling stages of a well to appraise the production potential. Although FSWD has the potential of reducing the sampling time, many factors must be considered when evaluating the economic benefit of a new technology. Now that day rates for deepwater drilling have reached $1 million, this has become one of the primary considerations.

This paper presents an economic model that can be used to evaluate the cost benefit and to make a comparison between wireline formation fluid samples acquired by the customer in a deep water field in Campos Basin, Brazil, in two scenarios (clastics and carbonates), with the simulation results obtained by the FSWD sensor.

Recent publications indicate a potential to reduce the sampling time with FSWD because of reduced invasion time. They also consider other factors, such as the permeability, porosity, and in-situ viscosity of the producing intervals, and the mud system properties that can have an equal effect on the invasion and pumpout time required to reach a sufficiently low contamination sample to evaluate the reservoir.

These factors are then used in an economic model that features operation costs for FSWL and FSWD, including the uncertainties regarding the following:

Fishing time, which is normally associated with the wireline operation Reduced pumping times associated with lower invasion, which will also reduce operational pump failures associated with extending pumping times Ability to obtain fluid samples in high angle or horizontal sections, reducing the operational time and enabling the operators to change their traditional well construction programs reducing or cancelling the need to drill a pilot well section and/or setting an intermediate casing string
Field Development Strategies for Bakken Shale Formation
Authors: Zargari S. , Mohaghegh S. D.
Published: December 2010

Bakken shale has been subjected to more attention during the last decade. Recently released reports discussing the high potential of the Bakken formation coupled with advancements in horizontal drilling, increased the interest of oil companies for investment in this field. Bakken formation is comprised of three layers. In this study upper and middle parts are the core of attention. Middle member which is believed to be the main reserve is mostly a limestone and the upper member is black shale. The upper member plays as a source and seal which has been subject to production in some parts as well.

In this study, a Top-Down Intelligent Reservoir Modeling technique has been implemented to a part of Bakken shale formation in Williston basin of North Dakota. This innovative technique utilizes a combination of conventional reservoir engineering methods, data mining and artificial intelligence to analyze the available data and to build a full field model that can be used for field development. Unlike conventional reservoir simulation techniques which require wide range of reservoir characteristics and geological data; Top-Down modeling utilizes the publicly available data (production data and well logs) in order to generate reservoir model. The model accuracy can be enhanced as more detail data becomes available. The model can be used for proposing development strategies.

The model is then used to identify remaining reserves and sweet spots that can help operators identify infill locations. Furthermore, a predictive model was generated, history matched and economical analysis for some proposed new wells is performed.
A Systematic Approach to Modeling Condensate Liquid Dropout in Britannia Reservoir
Authors: Göktas B. , Macmillan N.A. , Thrasher T.S.
Published: December 2010

Britannia field is a gas-condensate reservoir in the central North Sea, and has been producing since 1998. Condensate accumulation near the wellbore continuously impairs well productivity during the first year of production, as wellbore pressure drops below dew point, before stabilising where further well performance deterioration becomes negligible. The magnitude of the initial productivity loss averages 50-60%. Using several Britannia field well examples, this paper presents a comprehensive and systematic production data analysis approach to modeling well productivity deterioration due to condensate accumulation.

Production performance of Britannia wells is monitored by routine bottom-hole and wellhead back-pressure curves constructed using separator well test data. Permeability levels within the Britannia reservoir zones are high enough that the wells reach pseudo steady state (pss) flow within about a month. The well performance signature (shape of back-pressure curves) is characterised by performance points moving quickly to the left from the pss line, as condensate accumulates around the wellbore and reduces well deliverability. The workflow described in this paper uses the slope of the back-pressure curve of the late-time performance in order to provide estimates of kh, mechanical skin and non-Darcy flow coefficient. Effective permeability to gas (krgk) in the transient or stabilised deliverability equation is adjusted to match separator test points for estimating condensate blockage as a function of producing time. Reservoir simulation sector models are used to convert gas-relative permeability versus time relationships to gas-relative permeability versus saturation relationships. Pressure transient analysis, production data analysis type curves and the flowing material balance method are collectively utilised to fine-tune the initial estimates of kh and skin used in the deliverability equation.

Back-pressure curves are routinely used to identify wells for workover to improve well productivity, and candidates for capillary string installation or to evaluate benefits of additional field-wide compression.
Relative Permeability Hysteresis Effects in the Near-wellbore Region During Liquid Loading in Gas Wells
Authors: Zhang He , Falcone Gioia , Teodoriu Catalin
Published: December 2010

In oil and gas field operations, the dynamic interactions between reservoir and wellbore cannot be ignored, especially during transient flow in the near-wellbore region. A particular instance of transient flow in the near-wellbore region is the intermittent response of a reservoir that is typical of liquid loading in gas wells. Our previous numerical simulation study (Zhang et. al. 2009 and 2010) successfully captured the liquid backflow rates resulting from bottomhole pressure (BHP) oscillations typical of liquid loading, and emphasized their detrimental effect on gas production.

This paper presents a numerical modeling effort to investigate the relative permeability hysteresis effects in the near-wellbore region during transient flow conditions for a synthetic, low permeability gas reservoir. Firstly, the previously validated "U-shaped" pressure profile along the reservoir radius was generated with an increased BHP from a starting steady-state flowing configuration. This pressure profile can lead to reinjection of the liquid phase into the reservoir. The BHP was then let to decrease, with a corresponding temporary recovery in gas productivity. With subsequent BHP oscillations, the flow direction was allowed to switch back and forth, which could represent a typical liquid loading scenario. The Killough method was used to calculate the relative permeability hysteresis during the various imbibitions and drainage processes.

The results reveal that the hysteresis effect is negligible at a high-frequency alternation of imbibition and drainage in the near- wellbore region, and may therefore not be significant in liquid loading problems.
Use of Natural Gas as a Driving Force in a Diluent-Gas Artificial-Lift System Applied to Heavy Oils
Authors: Brito F. , García L. , Brown J.
Published: December 2010

The diluent-gas method is an artificial lift system for heavy oils (as low as 8.5 °API), where a light crude is used as diluent and it is injected into the well along with natural gas in order to reduce the viscosity of the crude oil therefore increase oil production. This method is unique in the world and has been long used in Venezuela.

Due to high maintenance costs, 20,000 US$ annually, incurred in replacing and repair diluent pumps (reciprocating pumps), which are used to inject at 900-1,000 psig the diluent (28-35°API) into the well, those pumps are considered as a critical system, basically, because of high operational pressures and oil production deferred, which is estimated in 2,500 barrels per year.

This project was based on analyzing a novel way to pump the Diluent and Gas down the well. The equipment designed is denominated Gas Displacement Pump and utilize the same gas lift (900 – 1,000 psig) as a driving force to inject the Diluent into the well. The system is made up of a vessel, a group of valves, pipes, level control systems, etc.

This novel design will allow minimizing; deferred oil production, environmental damage and maintenance costs, OPEX is reduced considerably (85%), as the Gas Displacement Pump will not have moving parts thus maintenance expenses would be low, generating this significant savings to the company. Finally, it was demonstrated that there is no slug flow formation using this new system and that the flow regime governing the system is stratified.
Challenging Complex Deltaic Reservoirs on the Orinoco Heavy-Oil Belt Aided by New-Generation Azimuthal Deep-Resistivity Tools and Advanced Real-Time Geosteering Techniques: Successful Case Study from the Eastern Venezuela Basin
Authors: Bejarano Celia , Castillo Elsy , Germain Pierre , Mendoza Hector , Manrique Carlos , Chacin Luis , Pineda Giser , Mendez Osbadis
Published: December 2010

A campaign to successfully drill and geosteer fourteen horizontal wells was performed in the Orinoco heavy-oil belt of eastern Venezuela. This campaign used the latest logging-while-drilling (LWD) azimuthal deep-resistivity tools in conjunction with specialized modeling and wellbore positioning techniques for a full geosteering service. Two simultaneous clusters (YA and SD), located in the southern part of the field, were the subject of this complete solution. The application of a full, real-time geosteering technique that combined the real-time responses of the tool and a model, measure, and optimize workflow enabled the flawless wellbore placement within a reservoir with a challenging stratigraphy and complex sedimentological environment and having notorious operational difficulties.

All of the wells were drilled in a deltaic depositional environment with average sand thickness ranging from 10 to 15 ft. Lateral facies changes, heterolitic beds, thickness variations, and pinch-outs were observed in this environment. The use of azimuthal tools made it possible to define the origin (relative to the wellbore) of these stratigraphical variations, which decreased the while-drilling uncertainty in the decision-making process. From a drilling perspective, extremely high rates of penetration (ROPs) of up to 1,000 ft/hr were achieved, which is common for these largely unconsolidated, highly permeable, heavy-oil sands. These fast operations required an efficient and reliable geosteering solution that enabled swift reaction to maintain the well path within the reservoir boundaries. Our solution proved to be very valuable, as we helped in reducing frequent sidetracking performed when drilling these deltaic units, thus minimizing NPT.

The outcome, including optimized well placement, reduced uncertainties in decision making, and improved rig-time effectiveness, were possible by operating with an integrated approach. Under this approach, geoscientists and drilling engineers from the operating company and the service company shared information on a real-time basis and worked as a multi-disciplinary team to make the best wellbore trajectory decisions.
Wellbore Strengthening – Where Field Application Meets Theory
Authors: Barrett S. , Cassanelli J. P. , Manescu G. , Vasquez G. , Growcock F.
Published: December 2010

In recent years there has been a growing awareness of the importance of Wellbore Strengthening Material (WSM) for sealing drilling-induced and natural fractures both in permeable and impermeable zones. This paper details the application of a software tool designed specifically for determining the optimum blend of WSM to drill the formations of the challenging Cashiriari field in Peru.

Several theories have been proposed to explain techniques which are in vogue for mechanically strengthening wellbores so as to control fracture propagation: Hoop Stress Enhancement ("Stress Cage") theory involves increasing the near-wellbore stress, which is usually carried out by opening fractures to tighten the wellbore and sealing the fractures immediately in that open state; "Fracture Closure Stress" theory utilizes high-fluid-loss materials to plug and tighten existing fractures; and "Fracture Propagation Resistance" theory involves isolation of the fracture tip. The design and successful utilization of a blend of WSM based on the opening and sealing of fractures suggests that these three theories are, in many respects, complementary.

Any theory explaining a particular problem is ultimately judged by its practical application. Cashiriari field, known for expected mud losses to both natural and drilling-induced fractures in primarily permeable formations, is where this wellbore strengthening application took place. The optimum blend of particulates, designed using wellbore-strengthening (WBS) software, was applied consistently on the wells drilled by the operator in the Cashiriari field in the 2009-2010 campaign. Fracture resistance was increased up to 0.8 lb/gal above the minimum horizontal stress for drilling and up to 1.68 lb/gal for running casing and cementing operations. Specialized logs showing the presence of WSM inside fractures were an important tool for optimization of the WSM blend.

WSM design software takes in account a multitude of drilling parameters and rock properties to predict the fracture width and estimate the required size distribution and concentration of the WSM particulates. Consequently, the WBS solution reduced lost circulation as a primary contributor of costly and time-consuming lost circulation incidents in the Cashiriari field. Further, it is anticipated that as the WBS approach is applied more widely, the incidence of lost circulation events will be greatly reduced.
Cuttings Injection and Monitoring Operations: Cashiriari Gas Field, Peru III
Authors: Pierce D. , Dunlap L. , Suarz C. , Zaki K. , Elfayoumi A. , Loloi M. , Abou-Sayed A. , Marinello S. , Cassanelli J. P.
Published: December 2010

Performance and environmental assurance of cuttings injection programs require monitoring and periodic analysis of injection response. Such programs provide operational oversight and the ability to respond to changes in performance, providing for optimization of operating parameters to minimize potential negative impacts. Cuttings injection was implemented on a remote pad in the Cashiriari Field, located in a nature preserve in Camisea, Peru. CI was recognized as a technically and environmentally acceptable alternative for waste management in a location with extreme environmental sensitivity. Higher than anticipated injection pressures, indicative of regional and local stress regimes, required adjustments in operating parameters and expectations. Performance was contingent on successful inhibition of reactive clays in and around the target zones. Continuous monitoring of closure pressure and other trends associated with batch injection has made performance predictions possible. Monitoring operations have allowed for performance improvement and/or minimization of potential problems. The operation injected over 212,000 bbls of cuttings on the first pad and continues to be successful on the second pad through careful management of batch attributes and adaptation to operating realities. Assurance derived from such programs provides long term operational viability and social acceptance of cuttings injection as a safe means of waste management.
Selection Methodology for Screening Evaluation of Enhanced-Oil-Recovery Methods
Authors: Trujillo M. , Mercado D. , Maya G. , Castro R. , Soto C. , Pérez H. , Gómez V. , Sandoval J.
Published: December 2010

This paper presents a methodology for the selection of the enhanced oil recovery technologies that better applies to some group of fields using screening criteria. The methodology has been integrated in a software in order to make repetitive analysis in an easier way, and has been applied for identifying the technologies whit higher technical potential of application in the Colombian Fields which have the biggest amount of oil in place (approximately 80%). The methodology incorporates oil and rock properties and the reservoir current conditions, besides the specific knowledge of the reservoir generalities and history.

In some Colombian fields, processes that use water, gas or steam have been applied; additionally, some other projects using water, gas, chemicals and air are in a design stage at this moment, however, more than 90% of the approximately 280 Colombian fields are still in primary recovery. This is one of the main reasons for having an oil average recovery factor of about 21%, and it also states the need of using methodologies that allow identifying the best investment options. The technologies considered in this analysis were: water injection, lean gas, rich gas, N2, WAG, CO2 (miscible and immiscible), polymer, surfactant – polymer, steam (cyclic and continuous) and some others such as CHOPS, VAPEX, WET VAPEX, SAGD, in situ combustion and electromagnetic heating.

The application of the methodology presented in this study allowed to identify the enhanced oil recovery technologies with higher potential for being applied in the Colombian fields with biggest amount of oil in place; it also generated a guide for the construction of every analyzed field development plan, which is presented as an example for the Cocorná heavy oil field.

The subject treated in this paper is more important for companies that own an important number of fields, and need to identify those with better characteristics for enhanced oil recovery projects in a quick and easy way; however, it is also very useful for companies that are beginning to develop any specific field.
Production Allocation in Multi-Layers Gas Producing Wells Using Temperature Measurements
Authors: Rabie Reda , Daoud Ahmed , El-Tayeb El-Sayed , Dayem Mohamed Abdel
Published: December 2010

We present a methodology of allocating gas rate and associated water to each individual layer using temperature measurements and total surface production of gas and water. This paper consists of two parts. In part one; we propose an analytical forward model for wellbore temperature response under two-phase production in a multilayer geometry, using a nodal representation of the well. This model accounts for the formation geothermal gradient, steady-state gas-water flow in the wellbore, friction loss and Joule-Thomson effect in the wellbore, contrast in the thermal and physical properties of gas and water, wellbore heat losses due to unsteady heat conduction in the earth, and the mixing of the fluid streams of contrasting temperature. The second part shows the solution technique used to allocate the gas and water rate for each layer by knowing the temperature measurements inside the wellbore and by using the previously derived forward model for temperature response along with commercial software packages used to estimate the pressure loss required by the temperature forward model.

Two synthetic cases are used to test the validity of the new developed forward model; the first one is account for a well that produces from a single layer, while the second one produces from multilayer well in which the temperature in the wellbore and production rate is known. The developed model is applied to calculate the temperature profile inside the wellbore. The calculated profile is compared with the actual profile. The results showed that the new developed model is valid and reliable.

The practical implementation of the new developed production allocation model is examined on data from two actual gas wells with temperature measurements taken from Production logging tools recorded in these wells. The results showed that the model succeeded to accurately allocate the flow rate of gas and water phase for the multilayer producing wells based only on the temperature measurements inside the well bore and the total surface rates.
Hole Enlargement in Brazilian's Pre-Salt Reservoirs: A New Technology Frontier
Authors: Silva Leonardo P. , Paixão Diogo G. , Kishi Alcides R. , Silva Adriano R.
Published: December 2010

This work intends to show how important was this hole enlargement operation in that Pre-Salt well describing its obstacles and effectivity. This operation allowed both run and cementing of the last casing of this well. Thus, it was ready for testing and oil sampling of these Pre-Salt microbial reservoirs. Furthermore, it also shows the challenger scenario we will face in this kind of operation from now on. This underreaming job occurred in the X well of Campos Basin. Our purpose was to ream 30 meters of salt, which was easily flowing and reducing wellbore, and 55 meters of the microbial carbonate reservoir. This interval was oversized from 8 ½" to 9 7/8", in order to allow a combined liner run (7 5/8" × 7") and ensure its cementation quality. A caliper run indicated a 9 7/8" bore along this entire segment. The result was a quite success confirming the effectiveness of the technique to this kind of scenario. To reach this success, 4 underreamers were used. In soft formations one tool can ream over than 500 meters. For this well the mission was accomplished, but the industry has a big challenge to design cutters blocks with longer life capable to ream extremely hard formations. At that time, these tools should be developed and ready to support the big demand we will expect in these tough scenarios, once they allow larger both tubing and open hole gravel pack screens, increasing oil production.
Computational Fluid Dynamics for Enhanced Environment Protection and Water Management
Authors: Daas M. A. , Golczynski T. S. , Agrawal M.
Published: December 2010

The increasing demand for energy contributed significantly to recent developments in offshore production and transportation of oil and gas. Offshore oil spills are major threat to environmental safety and marine life. Damage control and preparedness planning require better understanding of oil spill process, trajectory, and how Metocean and atmospheric forces influence the spatial and temporal spread of oil in seawater dramatically.

Computational fluid dynamics (CFD) has proved to be an invaluable tools to analyze in detail the dispersion of pollutants, including oil, in sea shore area. However, CFD models for large scale domains, extending several kilometers offshore and along the coast, need grids with several millions of points to accurately predict the dynamic distribution of spilled oil. For such large scale domains, over simplification of the physical model or Metocean data may result in significantly different results. A detailed Computational Fluid Dynamics (CFD) based study is established to predict the trajectory of oil film during various spill scenarios in shallow water wave profile and the influence of wavelength and amplitude as well as current velocity. A three phase (Oil, water and air) Volume of Fluid (VOF) multiphase model in ANSYS FLUENT is used to capture the free surface and the motion of oil film.

It is found that in the absence of sea current effects, buoyancy of oil droplets is dominant, and the diffusion-advection on the surface continues to progress forming thick oil slick even in the opposite direction of the wave transmission. Higher wavelength (less frequent) are associated with less extent of oil dispersion since shorter waves (more frequent) will cause relatively more violent water flow near sea surface which can transport oil droplets further up in wave direction. Furthermore, waves of smaller amplitudes cause more spread of the oil slick, especially in the direction opposite to wave direction. This is because less amplitude waves are associated with less turbulence and breaking energy, and hence less dynamic vertical dispersion of oil film in seawater.
Multilateral Well Drilling Using Imaging Logs in Mature Field Near Tampico, México
Authors: López-Solís V. M. , Velázquez-Cruz D. , Espinosa-Castañeda G.
Published: December 2010

The recovery of hydrocarbons in Mexican reservoirs is decreasing and the need to produce oil of economic form becomes a major challenge for the Petroleum Engineering. Multilateral Wells are not a new concept; however, its successful implementation has increased in the last decade as they represent an alternative to develop new wells or complement previous conventional or unconventional wells into the field.

Mexico is a major oil and gas producer and near of 90 percent of its oil production comes from Naturally Fractured Reservoirs, generally with a good thickness. These natural conditions are favorable to use production schemes based on horizontal and multilateral wells to exploit the mature fields. Further, utilization of imaging logs to know the spatial distribution of fractures in the well, allows us to define the best trajectory of horizontal branches. The primary goal of branches is intersect the greater amount of natural fractures to augment the hydrocarbons volume recovered.

The present paper described our experiences during planning and drilling a dual-horizontal-multilateral well called Sinclair 313. Horizontal branches were drilled with underbalanced technique using a potassic-nitrogenous water based drilling fluid to minimize rock-fluid interaction and avoid lost circulation problems into depleted reservoir. Likewise, logs were taken using memory systems conveyed with drill pipe; both conventional petrophysics and imaging information, and imaging logs were analyzed to redefine trajectory of horizontal branch. Last, a brief operative procedure to reach the production zone is described and main benefits and key issues are outlined.
Residual-Oil Saturation for a Very Long Unconsolidated Core, With Live Oil at Reservoir Conditions
Authors: Moreno R. B. , Bonet E. J. , Iatchuk S. , Vieira M. R. , Correa A. C.
Published: December 2010

This study aims the determination of the residual oil saturation (ROS) for a Brazilian field through a laboratory displacement test. Constant rate of water injection was performed using a long core sample prepared with reservoir rock and field live oil. The core test was vertically positioned and submitted to temperature and pressure reservoir conditions. A complete test protocol description is presented here, as well as the results discussions and comparisons with literature approaches.

The measurement of Residual Oil Saturation is of paramount importance to predict the expected recovery in a producing field and is a key factor for reservoir management. Several techniques are available for ROS-Measurement; however cost and representativeness can vary among them. Core analysis is one of the most widely used methods and this current evaluation was focused on a very high productivity offshore field, where this parameter was object of controversy.

Real cores from the field were frozen and brought to the lab, where they were sampled, placed in a core holder and submitted to an overburden pressure. Conditions before and after overburden pressure application was scanned with CT. Separator dead oil was dehydrated and recombined with a known gas composition, according to the GOR measured in the field. The sample was saturated with water, followed by injection of high viscosity mineral oil to reach representative initial water saturation for the field. Finally, the sample was submitted to the injection of the live oil reservoir till the GOR was constant at the outlet of the core. Injection tests were performed and one is detailed described here.

Extensive evaluation of the test protocol is presented and the experimental results are discussed and compared with a mathematical model. As main contributions we can mention the successful preparation method for long cores from unconsolidated rock and the novel dehydrating process which has been patented.
An Integrated Methodology for Water Management Under Operational Restrictions
Authors: Muñoz Mazo Eduin O. , da S. Gaspar Ravagnani Ana Teresa , Barreto Carlos Eduardo , Schiozer Denis José
Published: December 2010

The current concern with the increasing amounts of produced water and the wide variety of operations in which water takes place require considering strategies that, with their further development and implementation, lead to a correct management of the produced and injected water in order to increase the oilfield productivity. Thus, it is possible to determine operation conditions regarding the settings that allow optimizing the oil recovery and the economic incomes of an oil E&P development.

It is known that efficient strategies for water management can lead to an effective control of the influence of water on the project development, increasing the economic performance of oil production by means of the reduction of costs and/or the increase of revenues in the cash flow. Examples of this situation are the anticipation of the oil production, the reduction of the treated volumes of water in the field and their respective costs, besides the increase in final oil recovery.

Hence, the determination of limits for the water production and injection, the dimensioning of surface facilities and the selection of the proper options for water management shall be based on the economic parameters and production performance, since the handling of an eventual extremely high water production, or an injection not agreed with the necessities of the field and the processing capacity, can affect negatively both, the cash flow and the final oil recovery. Also, it is important to highlight that the strategy selected for water management must consider environmental actions not only to minimize the negative effects of water processes, but also because those actions can be accounted for into the cash flow and in the field operation as intangible goods.

This paper presents a brief review on the main aspects of the water management and proposes a methodology which integrates different factors involved in water management to determine the appropriate conditions for its implementation, considering technical and economic factors. The study presents as main benefit the possibility of an integrated solution in order to get a bigger performance of the processes that involve the use of water in oil field operations.
Integrated SAGD Thermal Stress Modeling
Authors: Gonzales Adolfo C. , Bajwa Faris J.
Published: December 2010

Among the multiple steam operation technologies, SAGD (Steam-Assisted Gravity Drainage) is one of the most popular techniques for the development of heavy-oil bitumen reservoirs. SAGD (horizontal-well method) operations require the implementation of parallel horizontal-well (injector and producer) single/dual completions to initially warm up the heavy-oil reservoir through early steam-circulation operations. Once the bitumen reaches low viscosity and is mobile, it becomes part of the return flow path, which is typically followed by steam injection into the reservoir to induce full production. The design of steam operations is both technically challenging and costly and depends on several aspects: those related to the reservoir itself and those associated with proper well planning. For an effective steam operation design, understanding how wellbore configuration affects heat transfer, tubulars used in well construction, thermal properties of cement and wellbore fluids, as well as steam operation parameters, like input conditions, flowrates, and duration of steam operations, are very important.

An integrated thermal/stress analysis approach was taken using a commercial thermal-simulator model and stress-analysis tool to first size and optimize steam temperatures, pressures, quality, and heat loss during a typical pre-SAGD operation and post-SAGD-associated injection and production events. Critical stress conditions of tubulars exposed to this SAGD steam loading events were then evaluated and resolved. Finally, an optimum SAGD design was delivered that fulfilled the thermal requirements while ensuring safe tubular design.

This paper details a systematic approach for analysis that includes the impact of formation, fluids, and tubular thermal properties, as well as wellbore configuration (e.g., comparison of single vs. dual completion scenarios applied to a practical scenario). In addition, this paper discusses the use of vacuum-insulated tubing, insulation material, and the use of nitrogen in well configurations as possible heat-loss mitigation solutions. The impact of steam quality, pressure, temperature, flow rate, and time affecting heat distribution downhole is realized through sensitivity analysis. The purpose of the paper is to emphasize the importance of properly defining and identifying the well-configuration components, formations, fluids, thermal properties, steam operation conditions, and the impact they have on effectively planning for heavy oil-bitumen steam SAGD well operations. The paper couples thermal SAGD design with stress analysis and illustrates how to resolve extreme compression resulting from thermal expansion on wellbore tubulars, as typical steam operations involve elevated wellbore temperatures.
A Methodology to Assess Uncertainties and Risks in Heavy Oil Projects
Authors: Ortiz Volcan J. L. , Iskandar R. A.
Published: December 2010

The commercial success of heavy oil projects highly depends on the intensive use of the right combination of technologies and competencies during the life cycle of reservoir assets in order to achieve world class recovery of hydrocarbons, with highly productive wells and flow assurance supported by a reliable production infrastructure including oil upgrading facilities in some cases. When projects are located in environmentally or socially sensitive areas other technologies are required to assure the viability and sustainability of the project.

In this paper we present a methodology to assess uncertainties and risks of heavy oil projects using Front End Loading (FEL) and Life Cycle Costing (LCC) and it is based on comparing data and information systematically during the definition phase vs. results from the execution phase of similar projects. We have applied this methodology successfully in several heavy oil projects providing an alternate approach to complex data hungry methods.

A general model and taxonomy is used to standardize activities performed in the different phases of a heavy oil asset project life cycle allowing adapting and adopting this methodology for any heavy oil field. All activities are classified based on their impact in capital expenditures (CAPEX) and operational expenditures (OPEX) using FEL to establishing the level of definition of each asset component and Life Cycle Costing for comparing different scenarios with combination of technology options. Uncertainty and risk analysis is performed for all cost driven variables by analyzing cause and effects relationships and assigning typical probabilistic distributions for key and important activities in each phase of the heavy oil asset life cycle. The standardized heavy oil asset model provides an acceptable representation of life cycle phases of asset components (natural and physical) so the associated costs can be forecasted probabilistically using data and information from projects in similar assets (analogs) and technologies.

We recommend application of this methodology as an alternative for traditional project planning especially during early phases of a heavy oil assets life cycle particularly discovery and appraisal and we provide a roadmap with hands on description of work flows and techniques so it can be applied by asset project teams who can create data bases with standardized data and information from heavy oil asset projects that can be shared to improve recovery of existing heavy oil resources at worldwide level.
Phase Implementation to Real Time Well Testing Using Fiber Optical Sensing Technology, San Alberto San Antonio Fields: Case Study – Part I
Authors: Ferraris C. G. , Gonzalez L. E.
Published: December 2010

In the 90's, after success in drilling wells deeper than 5,000 meters with high production rates between 80 to 120 MMSCFD of production, Petrobras decided to continuously measure pressure on their high productivity wells (7″ production tubing) because of the difficulty they experienced when running gauges in the production mode after the wells were completed.

Therefore, the decision was made to use permanent electronic gauges to obtain downhole pressure as it was a proven technology and optical sensing technology (fiber optics) was new to the industry. At that time, four wells in the San Antonio and San Alberto fields were completed with electronic gauges with different results….one did not work, one failed at the beginning, one failed months later, and one worked intermittently.

Petrobras' objective to have real time downhole pressure did not change, and they planned for the next workovers of their wells to use optical sensing technology instead of electronic gauges. These specifications were required on their next bid, and the four wells were assigned to Weatherford International. Since that time, this technology is working in the four wells in the San Antonio and San Alberto fields, and there have only been small problems on surface equipment connections, which were corrected promptly.

Because of this success, Petrobras decided last year to implement optical sensing technology in all of their new wells because it was the only proven technology that could support the high vibration, produced by the 7″ tubing wells, and high temperature. The decision was taken one step further to install fiber optic downhole flowmeters on the intelligent completion wells. The use of this technology, complemented with the online PanSystem™ well test analysis software, enables real time well testing.
A Unique Sand Control Screen that Enhances Productivity
Authors: Woiceshyn G. , Russell T. , Caulfield I.
Published: December 2010

Today's conventional sand control screens, such as slotted liner, wire wrap, and premium mesh (both fusion-bonded or "soft-sintered"), retain sand via arrays of single-sized gaps. Although open flow area and mechanical strength differ among such screens, the sand retention mechanism is virtually the same—2 dimensional and gap-based—and performance is sensitive to the particle size distribution (PSD), which is not always well defined or constant along a horizontal wellbore. A very different sand control screen was developed that consists of a ~6 mm thick bed of highly compressed stainless steel wool and is protected by a perforated jacket with about 40% open flow area. The wool fibers criss-cross randomly to create a wide distribution of angular (rhombohedral) pores designed to retain a wide range of PSDs without plugging. Furthermore, this unique, three dimensional filter allows more "harmless fines" to pass, especially during startup, thereby creating an enhanced permeability layer of sand against the screen.

About 1 million feet of this screen has been installed to date (mostly in producers but also in injectors) in a wide range of applications—SAGD, cyclic steam, steam drive, conventional heavy and light oil, gas, gas hydrates, and water producers/injectors—with a remarkably high success rate. Due to its high flow capacity and strength, it has become popular for pump protection and for re-completions inside failed screens. Furthermore, this screen has been successfully replacing gravel packing in certain fields due to its enhanced performance characteristics and lower cost. It has proven attractive for standalone completions in long horizontals where the PSD is either poorly defined or varies significantly from heel to toe.

This paper presents the highlights of recent laboratory testing and field experience that demonstrate the screen's wide range of application, robust characteristics, and unique ability to enhance productivity and handle a wide range of sands with one "gauge". The screen's limitations are also presented.

With today's emphasis on standalone screen (SAS) completions, cost reduction and long horizontals, a presentation of this screen's properties and recent performance is very timely. Furthermore, this screen has recently been combined with inflow control devices (ICDs) to equalize toe-to-heel flux in order to prevent/delay water/gas coning and also minimize watercut if/when water eventually migrates to the wellbore.
Turbidite Chicontepec Formation, Channel Chicontepec, Mexico: A Diagenetic and Petrophysical Study to Optimize the Completions Corralillo Area
Authors: Estrada E. , Vielma M. , Morales J. , Estrada J. , Tineo F. , Gomez G.
Published: December 2010

This work is the result of authors' experience in complex reservoirs such as the calcitic-lithic sandstones of the Chicontepec Formation, in the Chipontepec Channel Basin. These rocks, highly reactive to acids, present problems of low permeability; they are often fractured but production decline rapidly in time. The diagenesis experienced by these reservoirs is very complicated because the large amount of carbonate lithics, igneous and metamorphic components present, which can be mixed with detrital clays and dissolution of fossils (moldic porosity).

The Chicontepec Formation is a turbidite sequence deposited in shallow waters in a submarine canyon with submarine fans, benthic foraminifera, some charred plant remains, and graded and convolute cross-lamination. It is composed by alternating well cemented calcareous-clayey-sandstones, and dark gray calcareous shale. It exhibits conglomerate horizons, consisting of chert and platform limestone clasts. Petrographically it is composed by very fine grained to middle and, occasionally, course litarenite; consisting of carbonate lithic (mudstone), monocrystalline quartz, plagioclase (sericitized) and a minor lithic igneous, metamorphic, silt and shale components.

The main authigenic cements are kaolinite, chlorite, calcite, ankerite and interstratified I/S. The facies described from core samples were adjusted with microfacies obtained from thin sections where permeabilities ranging 0.1 to 400 milidarcy, and porosities between 4 to 15% and occasionally 20% could be differentiated. The described type of porosity is mainly intergranular, with some intragranular and moldic porosity.

The analysis of high technology logs, such as magnetic resonance and image logs, permitted us facies modeling by using a 3D multivariate analysis of Coates permeability, effective porosity, shale volume and volume of irreducible water to represent facies described in the analyzed core samples and to obtain an integrated Petrophysical-Geological model. The study of these diagenetic facies allowed us to predict which of the electro-facies were susceptible to high reactivity and select the best candidates for stimulation.
Marlim Field: An Optimization Study on a Mature Field
Authors: Bampi Dirceu , Costa Odair José
Published: December 2010

Giant fields contribute to a significant portion of the total hydrocarbon production in Brazil. The majority of these fields are in advanced exploitation stages. This paper describes a drainage optimization study performed on the Marlim field, a giant and mature field located in the Brazilian Campos Basin.

Two optimization steps were carried out in this paper: (1) horizontal and vertical placement of sixteen new producer wells, and (2) given the best well targets distribution obtained in the previous step, determination of which wells have the potential for future sidetracks for optimizing these well placements after the original well abandonment.

Possible targets for the original sixteen wells and the surrounding targets corresponding to possible sidetrack wells were chosen based on the inspection of post-processed maps, such as the thickness of mobile hydrocarbons at specific reservoir exploitation dates while taking into account their structural and stratigraphic characteristics. Both the well placement optimization and the best time to perform the sidetrack were obtained using a global metaheuristic optimizer based on reservoir flow simulations. These studies analyzed the most appropriate economical criteria (water-cut limit and the minimum oil rate) to abandon the original well and perform the sidetrack.

The result of the first optimization increased the cumulative oil production in 46.5 million barrels (7.4 million std m3) over the base case, which was previously obtained by a high-quality extensive trial-and-error manual process. Given that some well positions defined in the manual optimization did not change after a large number of simulation runs were performed by the optimizer, the authors could attest the quality of the previous work. The second optimization provided an increase of 15.7 million barrels (2.5 million std m3) in aggregate output relative to the first optimization, with six well candidates to sidetrack. This work concluded that the water-cut limit and minimum oil rate economic criteria had a very strong influence on the objective function as a result of the fact that the timing of well abandonments in favor of their sidetracked wells is key to anticipate oil production.

At the cost of several reservoir flow simulations, this optimization methodology was able to improve the recoverable oil volume by accelerating the oil production and, as a result, the new well locations proposal became more economically attractive.
Regreening of Arid and Semiarid Areas by Using Produced Water from Oil Production in the Development of Agroindustrial Projects of Biodiesel Production
Authors: Farfan L. E. , Brinez D. F. , Perez G. S. , Pachon R. A. , Chavarro Jorge I.
Published: December 2010

The north of Huila state has an extension of 4360 km2 with of arid and semi-arid area conditions where the main limitation for agricultural production is both water deficit and low development of the dry ecosystem soils. Two hundred oil wells which produce 125.000 BWPD are located in this area; a 72% of this water is required for being re-injected to maintain reservoir pressure, but the remaining of water cannot be spilled out due to its chemical features that can contaminate the environment, for this reason the remaining water must be also re-injected.

The strategy of re-greening of arid and semi-arid areas with the use of produced water from oil production is possible through the treatment by reverse osmosis in a scheme continuous of reactor tanks that allow the removal of salts, chlorides and dissolved metals in water, and then can be use in the irrigation of 142 hectares of Jatropha crop for the Bio-Diesel production that is a cheaper alternative than water re-injection.

With this research program ECOPETROL S.A., Huila-Tolima Operation District, supports the ONU's initiative of combating the desertification because it contributes to the recovery of arid and semi-arid areas through the development of environmentally friendly projects; also, it converts a problem for oil industry into a innovation solution that creates agricultural Jobs, news sources of renewable energy, improve of life quality of the population using technological applications in severe environmental conditions.