bluuebunny/crossref_metadata_2025 huggingface dataset:
Running 7" liner to TD using turbine technology in Gullfaks Satellites and Oseberg Fields
Authors: Corriveau Jean-Philippe , Nafikov Rustem , Bryce Toby , Prescott John
Published: June 2014

In the Norwegian sector of the North Sea west of Bergen, unstable shales, coals and paleosols in the reservoir have regularly resulted in problems when running liner. Conventional mitigations learnt from previous wells or taken from similar fields have been adapted, but running 7″ liners successfully to TD at the first attempt has continued to be a challenge and it is desired to drill longer horizontal wells through these unstable formations in order to improve the recovery factor. New mitigations are therefore considered, including a turbine power shoe that had been used successfully in other countries.

The turbine power shoe provides the ability to rotate a reamer shoe without rotating the whole string from surface, while it requires limited changes to the liner string and running parameters. It is an additional tool to cross ledges and unstable intervals. The tool has been used in four wells in Gullfaks Satellites and Oseberg fields. In all these cases, the turbine shoe was activated and the liner was run to TD. Therefore the turbine power shoe will continue to be considered as an additional mitigation for running liner at high inclination through unstable formations.
Avoid Pilot Holes, Land Wells, and Optimize Well Placement and Production with Deep Directional Resistivity Logging-While-Drilling
Authors: Dupuis C. , Mendoza-Barrón V.
Published: June 2014

Landing horizontal wells in a reservoir is a critical task, and the accuracy of the result drives the economics of a well. Except when the geological environment is largely predictable, relying on well to well correlation techniques or on pilot holes fails to mitigate important risks in landing most wells. This paper details how a different solution more effectively manages the risks of a landing operation. The deep directional resistivity (DDR) logging while drilling (LWD) tool has been in use on dozens of fields around the world. The key features of the technology that play a role in de-risking landing wells range from the tool hardware, which enables a deep depth of investigation, sensitivity to direction, and a wide frequency range, to the surface interpretation software, which provides real-time automatic multilayer inversion. Applied to a landing in a North Sea field, the DDR LWD tool was part of the solution for meeting ambitious field development targets.
Innovative ERD Well Construction for Severe Losses and Wellbore Instability Environment
Authors: Yadav Anurag , Verma Jaywant , Qureshi Ahmad Shakeel
Published: June 2014

While designing a development plan for a field that was underneath a city, major engineering and design stumbling blocks were encountered for the extended-reach drilling (ERD) prototype. There was also the risk of encountering shallow gas and high concentrations of hydrogen sulphide gas across different formations in the field. Hence, the biggest challenge for the field development plan was to develop a well construction design that would provide well integrity and at the same time allow running casings and completions to the desired depth. In addition, different hole sections were experiencing well control, loss circulation, and wellbore stability issues all at once, resulting in a loss of well integrity or total lost circulation. This was making torque and drag unmanageable, which meant inability to drill, run conventional or drillpipe conveyed wireline logs, or run casing and completion. Also, there was a high incidence of stuck pipe events due to wellbore stability issues and hole cleaning problems in a lost circulation scenario. Due to the torque and drag limitation, performing a sidetrack was not an option in the field. In this operation, an extensive offset well analysis and comprehensive risk assessment was done to put together an innovative well construction design and a customized drilling procedure that would lead to successful drilling and completion of a world-class ERD well under high-to-total loss circulation scenario. The selection criterions for technologies for the BHA and the drilling procedures were based on the specifics of designs and highlighted how a predrill geomechanics modeling, a drilling liner application, fit-for-purpose equipment selection, optimized well placement, judicious casing flotation, advanced logging-while-drilling technology application, and tailored drilling practices that not only made an undrillable well drillable but also set a new industry limit to run smart-completions.
First Sand Clean Out of a HPHT Well on the Norwegian Continental Shelf Using Rig Assisted Snubbing and Sand Cyclones
Authors: Brähler Johannes , Helland Anders Groth
Published: June 2014

The Kvitebjørn field is located in the Norwegian North Sea – production is based on gas/condensate bearing reservoir formations. The reservoir/field is classified as high pressure high temperature (HPHT). The main field development is centered on a steel jacket platform with combined production, drilling and quarters facilities (pictured).

This paper will describe the background, planning, execution and results of a rig assisted snubbing (RAS) operation conducted to clean out the production liner in Kvitebjørn well A-9 T2.

Intial production from well A-9 was significantly below expectations. At first this was attributed to complications related to a closed/stuck valve in the bottom of the completion string. A successful coiled tubing milling operation eventually removed the blockage caused by the valve but the poor production performance continued. It was concluded that wellbore fill in the production liner was blocking production and mechanical access to the reservoir section.

Planning was initiated for a wellbore fill cleanout operation and rig assisted snubbing was selected for the task. To ensure a successful operation a number of significant challenges were overcome including limitations on available experience with the type of operation, availability of qualified equipment and logistics issues related to other on-going activities on the platform. Fluid management was also a major consideration for the planning/operations team.

After an intensive planning period the operation was executed successfully in 2013 and the production liner in the well was cleaned out down to the reservoir section. Additional wireline conveyed perforating could then be performed. Despite these successful actions production from the well continues to fall below expecations and further remediation activites are being evaluated.
Experimental and Visual Simulation of Gravel Packing in Horizontal and Highly Deviated Wells
Authors: Changyin D. , Jiajia L. , Yanlong L. , Huaiwen L. , Lifei S.
Published: June 2014

The gravel packing process in horizontal or highly deviated wells involves the solid-liquid two-phase flow and the sand-bed migration under complicated conditions, in which the sand carrier fluid filtrates into the formation and the mass exchange occurs between the fluid in screen-washpipe annulus and the fluid in casing-screen annulus. One of the key problems in gravel packing is to predict the α wave sand-bed equilibrium height to simulate the gravel packing process and optimize operation parameters. In this paper, a full-scale simulation equipment for internal circulation gravel packing in horizontal wells is utilized for the study of the effects of screen offset, flow rate, and sand concentration on the α wave sand-bed equilibrium height. The comparison is made among the results using three empirical equations to calculate the equilibrium flow rate. Based on Gruesbeck model, a more accurate calculation method of the equilibrium sand-bed height is developed. Then, the mass and momentum conservation equations of the gravel and sand carrier fluid of two-phase flow in casing-screen annulus and single-phase flow in screen-washpipe annulus and the flow coupled equations of these two flow systems are established. A mathematic gravel-packing model for horizontal and highly deviated wells is thus obtained. The solution of the model can lead to the development of gravel-packing simulator software package, which can be used to visually simulate the gravel packing process. The characterization of the gravel packing process and the variation of each dynamic parameter are also analyzed.
An Innovative Workflow for Appropriate Selection of Subsurface-Surface Model Integration Scheme Based on Petroleum Production System Nature, User Needs, and Integrated Simulation Performance
Authors: Tillero E. , Rincón J. , Nuñez H.
Published: June 2014

The generation of portfolio of opportunities from hydrocarbon reservoirs requires, because of its nature defined by process, more reliable production scenarios based on better decisions making from the whole petroleum production system (reservoir-wells-surface facilities). Therefore, a truly production forecasting would be obtained if boundary conditions imposed by reservoir, well completion and surface network are considered through integration schemes that allow to emulate, as accurate as possible, operating conditions expected (flow and pressure behavior) from network–well to reservoir.

This paper introduces an innovative workflow, developed for explicit simulation of subsurface-surface models, to assist assessment of IAM schemes (Integrated Asset Modeling). This assessment was based on a qualitative algorithm focused on defining the most appropriate subsurface-to-surface integrated modeling, considering the petroleum production system nature and users needs. In addition, a comparative analysis of performance variables from integrated simulation output (computing time, material balance error, among other) was implemented by combining both reservoir-network coupling and balancing methods available in the modeler used (AVOCET™). A test model was considered for the assessment of the proposed workflow.

Results showed that better decision making is reached out for integrated petroleum production system simulation when the proposed workflow is implemented, depending on the nature of flow and pressure behavior through the system, simulation performance, and users needs (reservoir, production, or processing engineer). In addition, it is suggested that a comparative assessment can be considered to evaluate reservoir-network simulation performance if both convergence and stability of the integrated model and user expertise is on demand.

For the test model, better performance was obtained from coupling scheme at wellhead, with both the lowest computing time and material balance error percentage of fluids, followed by those from bottomhole coupling scheme. As far as reservoir-network balancing methods concern, results showed that balancing controlled by reservoir simulator presented shorter computing time as much as lower oil, water, and gas material balance error percentage, compared with the others reservoir-network balancing methods tested.
Overcoming Ultradeepwater Cementing Challenges in the Caribbean
Authors: Gupta N. , Bogaerts M. , Bellabarba M. , Mendiola A. , Salehpour A.
Published: June 2014

Ever increasing energy needs have encouraged the operators to explore newer areas in deepwater. One of the high potential areas under exploration is the Caribbean basin, which includes Trinidad and Tobago, Suriname, Guyana and French Guiana. Due to the extreme environmental impact that can result from incidents occurring offshore, well integrity is a critical element in offshore development.. Cementing plays a major role in ensuring well integrity and this paper will cover various cementing challenges that were faced in Caribbean deepwater zones. The water depth of wells in Caribbean can be as much as 2300m with seabed temperature of about 4 ºC causing complex heat transfer and requiring fluid modeling software to accurately predict the bottom hole circulating temperature (BHCT) profile. Deepwater wells in the Caribbean can also be affected by the formation of gas hydrates. Cementing in hydrates requires cement slurries with low heat of hydration (HOH). The results from several field studies were used to select an optimum slurry design to successfully cement in hydrates. The wells in this area are also characterized by low fracture gradients with a narrow window between fracture and pore pressures. The cement jobs are designed with advanced computer aided design (CAD) to accurately simulate equivalent circulating density and assist in designing fluid placement within this narrow window. Engineered lost circulation material (LCM) can be used in fluids to achieve successful cement placement. Fluid modeling software also helps in optimizing mud removal by simulating the impact of centralizer distribution, optimizing spacer properties and more. To evaluate cement placement a combination of advanced acoustic logging-while-drilling (LWD) tools and pressure analysis can be used for deeper sections while for riserless sections, visual feedback from remote operating vehicle (ROV) can be used. A case study from Trinidad and Tobago and Southern Caribbean highlights some specific solutions and lessons learned.
Natural Gas Reinjection in a Heavy Oil Field Increases Foamy Oil Recovery
Authors: Fei Sun X. , Zhang Y. , Duan X. , Li X.
Published: June 2014

Foamy oil behavior contributes significantly to the anomalously high primary recovery of heavy oils observed in the Orinoco Belt, Venezuela. Nowadays, disappearance of this phenomenon results in a rapid increase in the produced GOR and a fast decline in oil production when the reservoir pressure is below the pseudo-bubble pressure. This paper presents the results of a laboratory investigation, including pressure-volume-temperature (PVT) studies of foamy oil-natural gas mixtures and coreflood tests, for evaluating the feasibility of the natural gas injection process for enhanced heavy oil recovery with foamy oil characteristics. The study characterized the natural gas dissolution process in the foamy oil, and examined the effects on viscosity reduction and foamy oil swelling of the presence of natural gas. Coreflood tests were carried out to investigate the effects on oil recovery of injection mode (huff-n-puff, continous gas injection, and intermittent gas injection) and their different process parameters, such as reservoir pressure, injection timing, permeability and the size of the gas slug. The results indicate that significant amounts of natural gas could dissolve in the oil, which would cause oil swelling, viscosity reduction and artificial foamy oil formation. Core-flooding tests show that the natural gas huff-n-puff process could increase oil recovery 7.8% compared to the primary pressure depletion process, indicating a greater potential for recovering heavy oil. The continous and intermittent gas flood processes were not viable methods to enhance oil recovery from the heavy oil reservoirs in the Orinoco Belt, Venezuela.
A Review at the Problem of Sanding in Colombia: Evolution and Cases of Evaluation for Sand Exclusion and Management Alternatives
Authors: Jaimes M. G. , Quintero Y. A. , Martin D. P.
Published: June 2014

Sand production in oil and gas wells is a complex problem that requires an integral analysis of rock mechanics, mineralogy, granulometry, etc. that allows a risk management in order to make the best technical and economic decision.

In this study the background, strategy used in the past and in the present to tackle the problem of sanding, and Cases of evaluation of alternatives SEM (sand exclusion and management) in the recent history of the fields Casabe, Lisama, Galán, Llanito and Bonanza, located in the basin of the Middle Magdalena Valley in Colombia, are shown.

The effects of water injection and the gravel packing, in the low drainage and repression of the reservoir in the Casabe field are shown. These effects are: injected water distribution, behavior of pressure and sand cleaning jobs in packaged and unpackaged wells, production, effective injectivity and bsw before and after the gravel packings, number of wells packaged, abandoned producer wells, injectors collapsed, etc. Also mentioned are other factors that affected the low drainage and the repression of the reservoir, such as: reservoir heterogeneity, granulometry (% fines), mineralogy (migratory and swelling clays, etc.).

After Casabe field experience, the problem was approached very conservatively, limited at the drawdown control and the use of special metallurgy and sand cleaning jobs, etc. Today the problem is focusing differently, considering new technologies and an integral analysis of the reservoir. To carry out the above, the methodology SEM (Sand Exclusion and Management) was developed for the selection and technical-economic evaluation of alternatives of exclusion and/or management of sand during drilling; completion and production, which including probabilistic risk analysis.

The following case studies are presented in this article: Application of the methodology SEMEvaluation and implementation of sand exclusion and management technologies Chemical Consolidation (Laboratory)Chemical Treatment (Laboratory – Oil field)Screen Less Frac (Oil field)Artificial Lift Experiences With Sand ProductionAcoustic MonitoringGeomechanics applied to reduce risk of sanding during drilling, completion and productionDesign and Implementation of Software Tool

Finally, conclusions and recommendations obtained in this study are shown.
Challenges and Successes in Horizontal Drilling Shallow 3D Unconventional Turbidite Reservoir, Mexico
Authors: Murillo G. Gutierrez , Zapata G. Villanueva , Medina E. , Centeno J. Salguero
Published: June 2014

Aggressive plans for exploiting vast oil resources within the Chicontepec basin (Mexico-Poza Rica) are currently underway. One of the most complex deposits in the world, this basin is qualified as an unconventional turbidite reservoir, and one of its characteristics is the existence of hydrocarbon resources in shallow regions. Horizontal wells within this basin are extended three-dimensional (3D) wells in parallel arrangement, suitable for termination techniques, such as simultaneous multi-fracturing.

Commercially developing these resources requires the construction of wells that present major challenges. These challenges can be attributed to low depth, required dog leg severities close to 8°/30 m, 3D geometry necessary for construction and horizontal navigation uphill "boomerang" within the target unconsolidated sand formations (which are thin and unstable with mechanical hydraulic limitations), superficial limitation of space, the use of conventional drilling equipment, and required exhausting analysis.

The successful exploitation of these wells was achieved with thorough planning simulation, detailed engineering analysis, and the selection of appropriate tools for each operational stage. Monitoring key factors during drilling was essential to helping prevent problems with uncompacted sands and gas migration.

The use of advanced technology helped reduce deviation from the plan designed for the well and helped achieve a successful completion using a rotary steerable system (RSS), in some cases from the first casing, to prevent collapse and initiate the construction of the kickoff point (KOP).
Capturing Regional Geomechanical Knowledge for Heavy Oil Carbonate Offshore Fields in Campeche Oriente-Mexico
Authors: Gavito D. García , Carrillio Galícia L. A. , García J. C. , Cabrera A. C. , Duarte A. P.
Published: June 2014

As part of the strategic projects for reserves incorporation in the south-east Mexican Gulf, Heavy Oil-Carbonate fields have been explored in an area of about 900 km2 called "Campeche Oriente". As of today, a total of 13 extra heavy oil offshore fields have been discovered and delimited. In order to characterize this area in an early stage of its development, a conceptual model for Wellbore Stability Analysis of the new fields, in coherence with a nearby developed fields Geomechanical knowledge has been built. As a first approach to evaluate the regional coherence on the geomechanical modeling parameters, an existing and calibrated model previously built in an offset development field was applied to the exploratory fields in Campeche Oriente basin, focusing in design and drilling optimization purposes. As a result of this analysis, nearby field modeling parameters showed good correlation in an area of 900 km2, covering the exploration fields. It has been possible to identify two main sectors (East and West) with differences in shallow sediments velocities leading to slight variation of the normal compaction trend. Based on these regional results, it has been possible to identify the fields that fall on each sector allowing, on a first stage of well design, the application of a fit for purpose geomechanical model, adjusted for each sector in order to reproduce geological conditions and operative events of the area. This analysis focusing on the operational experience, well logs/reservoir characterization information and lessons learned from an offset field has been an excellent starting point for the Front End Loading of the development wells to be drilled in the area, allowing to better understand, from a conceptual perspective, the expected behavior of the planned wells and design cost effectively according to it on a critical environment involving overpressure zones, depleted carbonate reservoirs and heavy oil.
IPR in Naturally Fractured Gas Condensate Reservoirs
Authors: Qasem Fuad , Gharbi Ridha , Baroon Bodoor
Published: June 2014

Predicting the performance of individual oil wells is of great importance to petroleum engineering for continuous production optimization in the field. This study proposes a new Inflow Performance Relationships (IPR) for naturally fractured gas condensate reservoirs. Existing IPR models are commonly used for conventional solution gas drive reservoirs. The purpose will be to generate inflow performance relationships (well flowing pressure vs. flow rate) for naturally fractured condensate reservoirs as a function of the average reservoir pressure and fractured reservoir parameters including storage capacity (fracture storativity) and inter porosity flow parameter (interporosity flow coefficient). A dual porosity/dual permeability compositional equation of state simulator is used in this study. A regression program is used to fit the IPR curves and to obtain the corresponding equations. As a result, rational functions have been developed for the IPR curves for gas and oil phases. These correlations are functions of pressure drawdown and reservoir depletion. Additional correlations for predicting future maximum gas and oil rates were developed. The behavior of the future gas rate shows linear relationships between average reservoir pressure ratio and the maximum gas rate ratio. However, a highly non-linear behavior was observed for the oil phase. Additionally, fluid representing extreme types of condensates were also considered. Condensates with high fraction of light composition shows a hump and three distinct regions with different slopes in future maximum rate curves. In the other case where the composition of the condensate contains heavy components has shown nonlinear curves.
Miscible WAG-CO2 Light Oil Recovery from Low Temperature and High Pressure Heterogeneous Reservoir
Authors: Ligero Eliana L. , Schiozer Denis J.
Published: June 2014

Brazilian pre-salt oils should contain a variable concentration of dissolved CO2, which is produced in the gas phase. A sustainable production of these oils requires a destination for the produced gas. As offshore fields have limitations associated to gas manipulation, storage and exportation, miscible CO2 flooding is an Enhanced Oil Recovery (EOR) method with great potential to be employed in pre-salt reservoirs. In fact, miscible CO2 injection in highly heterogeneous reservoirs should increase the oil production. As CO2 flooding is related to high gas mobility, an alternative EOR method is water-alternating- gas injection (WAG). The WAG with CO2 (WAG-CO2) is advantageous in this scenario due to the sea water available apart from enabling the control of gas mobility. In addition, using CO2 as an injection fluid is a viable solution for the GHG problem. Before implementation of WAG injection in a field, the prediction of the oil production through reservoir simulation is recommended. Simplified Black-Oil modeling is not appropriate to simulate a reservoir with light oil and miscible CO2 injection. The rigorous simulation of WAG injection requires a compositional model. Also, hysteresis of relative permeability should be implemented in the simulation model to consider the cyclic hysteresis of the three-phase relative permeability. The case studied has analogous characteristics of pre-salt reservoirs such as light oil with 8% molar of CO2 and initial reservoir conditions of low temperature and high pressure. The phase behavior of the oil and CO2 mixture is represented by an Equation of State that contemplates the swelling resulting from the CO2 dissolution in the oil. As hysteresis modeling requires some uncertain experimental parameters, a sensitivity analysis is carried out to determine the influence on oil recovery. The importance of using the reservoir simulation as a tool to predict the oil recovery before implementing WAG injection in practice is evidenced. It also demonstrated that the sensitivity analysis of the required uncertain parameters to consider the hysteresis is a viable approach to give the pessimistic and optimistic scenarios of light oil recovery prediction under WAG injection.
Solid Expandable Systems Brings New Life to Aging Venezuelan Field and Optimizes Production
Authors: Perez Reina , Romman Randy , Ciliberto Alejandro , Granados Cesar
Published: June 2014

In the early 1970's, drilling started in the Northeast of Venezuela on a series of extended depth wells averaging 16, 000' in measured depth. The field currently produces both crude oil and natural gas of approximately 2, 000 barrels of oil equivalent per day. The subject wells in this paper were drilled in the early 1980's to the same approximate depths. Initially, production remained steady for many years, but mechanical problems discovered in the early 2000's led to re-entry and re-completion of some wells. The plan for re-entry in one particular well began with the use of conventional technologies, re-entering through 9–5/8 casing, running and cementing a 7 in. liner and drilling with best practices to the production zone where a planned 4–1/2 in. production liner would be placed at total depth. While drilling below the 7 in. liner, the operator encountered issues with lost circulation, followed by differential sticking, which led to three sidetrack operations over the next few years. After review, the operator decided on solid expandable technology that would allow isolation of the problem zone into two different hole sections, without downsizing the well. The Solid Expandable liner isolated the unstable zone, while still yielding enough pass through ID to allow for optimally sized drill ahead and the running of a production liner into the reservoir. By covering the unstable zone with the Solid Expandable liner, the operator was able to lower the mud weight before drilling into the production zone, avoiding lost circulation, differential sticking and other associated drilling hazards.
A Simplified Computer Model for Determination of Cuttings Concentration and Wellbore Cleaning
Authors: Gasbarri S. , Wills V.
Published: June 2014

Plugging of cuttings in the wellbore is a common problem during drilling processes. Some authors have analyzed settling or slip velocity of particles in a liquid both analytically and experimentally. The concentration of cuttings throughout the well has been also analyzed. It has been proven that numerical models have the potential to help predict the performance of the cuttings concentration for solving this problem.

A computer model for determining the cuttings concentration for the different processes applied during wellbore drilling is presented. It is a useful tool for the drilling engineer to predict and analyze the drilled cuttings transport to assure efficient wellbore cleaning during operations. The model is based on central difference, and non-Newtonian power low fluids can be used. The effect of the cuttings interaction for different concentration in the settling velocity was determined experimentally. The model was designed to allow the user to calculate the cuttings bed formation, determine whether the bed remains stationary or build ups and analyze the position of the cuttings bed formed and the height of the cuttings bed layer.

Using a typical case study, the wellbore cuttings concentration and the height of the cutting bed are shown for the different processes; i.e. during hole-cleaning and shut down. The effect of operating parameters, wellbore geometry, non-Newtonian fluid parameters and cutting characteristics was analyzed. This computer model is a helpful tool to predict stuck problems and speed up wellbore cleaning processes.
Inflow Performance Relationship Equation for Solution Gas-Drive Reservoirs under Gravity Segregation
Authors: Padilla-Sixto R. , Camacho-Velázquez R.
Published: June 2014

Based on synthetic results obtained by Padilla and Camacho for the fluid flow of gas and oil in reservoirs producing by solution gas-drive (SGD) and gravity drainage (GS), in this paper the behavior of the oil mobility function in partially and fully penetrated wells is studied; also its influence on the development of a practical IPR equation is analyzed.

It is concluded that the Fetkovich's straight line approximation with an ordinate to the origin equal to zero is valid only when the production comes from the middle of the production thickness with and without gravitational effects. Also, changes of the gas saturation with depth due to the influence of gravity drainage and also the measurement position causes that the ordinate of the mobility function, λ(p) = ap+b, be different from zero; however, this linear approximation is reasonable at long producing times during the boundary dominated flow period around the wellbore. For partially penetrated wells this consideration is not entirely appropriate.

Considering the above results, a productivity coefficient (ϑ) defined as the ratio of oil to the total productivity index is defined. A quadratic IPR equation valid for any position of the production interval is derived. The quadratic flow efficiency definition given by Camacho and Raghavan is considered. A table of normalized reference equations for different productivity coefficient values is presented, where the classic equations of Vogel, Fetkovich and constant productivity index are particular cases. Finally normalized cubic correlations for totally and partially penetrated wells also are obtained. The equations were proved with information of real field cases of saturated naturally fractured reservoirs (NFR's) of Mexico.
A New Engineering Approach for Gas Anchor Applications for Extra Heavy Crude Oil –Study Case at PetroPiar in the Orinoco Belt
Authors: Díaz Sierra J. , Moreno Mendoza O. , Rivas Johnson S. , Arredondo M.
Published: June 2014

Wells with high gas/oil ratio (GOR) using progressing cavity pumping (PCP) or rod pumping (RP) typically have a high gas/liquid ratio at the pump intake. For those wells, the use of a downhole gas separator is crucially important to remove as much free gas as possible from the stream reaching the pump. This makes possible to increase pumping volumetric efficiency under reasonable speed conditions and thereby improve well productivity.

In applications of PCP is well known that pump performance degradation occurs when handling high fractions of free gas (GVF). Gas blockage, lack of lubricity, reduced heat dissipation, elastomeric swelling, etc., are some of the different problems that occur to the pump before it tear down.

Typically the design of downhole gas separator for light or medium crude oil uses separation efficiency values based on empirical trials and settling velocity criteria in biphasic streams. This approach has enabled the industry to mainly develop concentric configurations based on vertical positioning.

In the Huyapari field, at least 43% of the wells have free gas at bottomhole conditions in the range of 70–90%. This represents a great opportunity to develop reliable gas separation technologies, looking to improve pump efficiency and run life.

This article describes a pilot-scale study of two high GOR wells to evaluate the performance of a "cross flow" downhole gas separator designed for heavy oil production in horizontal wells. This low cost equipment has no moving parts; its configuration is robust, easy to build and simple to be ran in the bottomhole assembly (BHA) at slanted positions.

Free gas and liquid separation theory is briefly reviewed to show the most adverse conditions for gas separation present in extraheavy crude oil at field conditions.

Production results before and after application showed an increase in the annulus gas rate from 48% up to a range between 55 and 75%. This has promoted improvement in pump efficiency, greater differential pressure in the tubing column and a production increase in the well operating at a lower PCP speed.
Experimental Inter-stage Study of an Electrical Submersible Pump Handling Viscous Fluid in Multiphase Conditions
Authors: Ibarra Javier , Valderrama Alberto , Gonzalez Juan , Carios Enrique
Published: June 2014

Electrical Submersible Pumps (ESP) are turbo machines that deliver energy to fluids using several stages comprised by one impeller and one diffuser. ESP performance is affected by viscosity variations and changes in the value of gas void fraction of the fluids that are pumped. For any centrifugal pump, as the viscosity of the fluid increases, the required brake horsepower increases as well; whereas, head capacity and efficiency decrease. Additionally, gas void fraction presented in multiphase pumping condition may affect negatively the head capacity of ESP systems. This research had as main goal to evaluate, in a fit for purpose test rig, a 513-series, 35-stage, mixed-flow-stage pump under two-phase flow conditions. Pressure and temperature changes at several stages through the pump were recorded. As a fluid, it was selected a multiphase mixture with air and ISO 320 mineral oil. The experimental matrix included tests with range of gas void fraction from 0% to 17%, 50 psig as pump intake pressure and 50 Hz of operating frequency. A better performance of downstream stages, located in the upper section of the ESP, was reported. A considerable rise of fluid temperature throughout the pump's stages was particularly reported in a range from medium to low flow rates. Furthermore, it was corroborated the unstable pumping region, where surging phenomenon occurred. The study was operational constrained by health security and environment restrictions – specifically the impossibility of using real heavy crude oil and gas as pumping fluid. The resulting information will allow better understandings of the ESP performance focused on multiphase pump condition where viscous fluids are present.
First Hole Enlargement From 8 ½ to 9 ½ Inches With Point the Bit Rotary Steerable System and Hole Opener in a High-Inclination Well in Ecuador: Session 32: Recent Advances in Drilling Technologies
Authors: Sanchez Jose Luis , Carrizo Hector , Camacho Gustavo
Published: June 2014

Palo Azul field in Ecuador has always presented challenges for drilling high-inclination wells. The main issue is the natural tendency of the Napo formation to drop inclination even when using fulcrum or push-the-bit bottom hole assemblies (BHAs) designed to build inclination. Napo formation is composed of many intercalations of sandstone, limestone and unstable shale.

With the introduction of a Point-the-Bit rotary steerable system (RSS), a successful drilling campaign was developed. The capacity of this RSS to build inclination in 8 ½-in-hole sections independently of the type of formation drilled was the technical solution to build inclination while drilling through the formation that historically causes a drop in inclination. However, short trips to the 9⅝-in casing shoe and trips to surface have been very difficult, with several problems such as packing off, tight hole and back-reaming.

Several times the 7-in-liner did not reach the bottom of the hole, requiring an extra trip to condition the well for a new attempt to run the liner.

The use of a hole opener to enlarge the hole from 8-½ to 9-½ inches while drilling with a point-the-bit RSS was the best technical solution to finish the hole section in a single run, avoiding extra trips to surface and ensuring a clean 7-in-liner run.

The point-the-bit RSS and hole-opener run performed in this study was the first successfully run in a high-inclination well (51° to 68°) in Ecuador, generating an average dogleg severity of 5°/100 ft.

This technical solution is allowing the operator to plan more high-inclination or horizontal wells to optimize Palo Azul field production.

The synergy between the Directional Drilling Company and the hole opener provider to simulate and execute the run described above with an integrated BHA was the key to success in implementing this technological solution for the client.
Geoengineering Data Integration at Petrobras Production Engineering
Authors: Schonmann M. V. , da Silva J. B. , Oliveira A. G.
Published: June 2014

The O&G industry has been realizing that the implementation of Data and Information Governance (DIG) has a significant impact on their business initiatives in all levels of the company, such as the strategic, the tactical and the operational ones. The DIG has the aim to guide the company to manage its data assets through the implementation of rules, policies, procedures, roles and responsibilities. In essence, the DIG is a multidisciplinary function led by the company business areas. Its success depends on the clear definition of the technologies, processes and people aligned with the Information Technology (IT) strategy.

The Petrobras Production Engineering is implementing governance model which focus on the data integration that subsidizes the work processes in the geoengineering disciplines. In the geoengineering workflow, the geophysicists work with great volumes of data to do the best reservoirs' characterization. From the results produced by them, the geologists, sum to geophysical studies, data and information from the research labs, from the Petrophysics and from the Geomechanics, among others, to construct the reservoirs static structure. The engineers receive the geological studies and work with them generating dynamics flow studies of reservoirs within the various probabilistic scenarios for the estimation of the O&G reserves production as well as to subsidize economic analysis. Each area of study manages their data universe and the results are supposed to work both ways, moving and flowing in a coordinated and integrated manner amongst the disciplines.

The goal of this article is to present the strategy used in the implementation of a DIG model, describing a methodology and the achieved results. This methodology was supported by the IT and Production Corporate management which defined a strategy for conducting diagnosis in all Production Engineering business units' areas involved. With these results it was possible to identify opportunities for improvement and the definition of the best place to start was prioritized. It was clear the necessity to have a data and information management group working in all the business units and the adoption of new technological solutions used by the company and the industry supported by the IT.
Reduced Order Modeling In Reservoir Simulation Using the Bilinear Approximation Techniques
Authors: Ghasemi Mohammadreza , Ibrahim Ashraf , Gildin Eduardo
Published: June 2014

Despite great advances in reservoir simulation capabilities with the introduction of high-performance computing (HPC) platforms and enhanced solvers, high fidelity grid-based simulation still remains a challenging task. This task is especially demanding for fine-resolved geological reservoirs with multiphase and multicomponents and in production optimization and uncertainty quantification frameworks where several calls of the large scale simulation model need to be performed. Model order reduction techniques have been applied in porous media flow modeling in order to obtain fast simulation surrogates to alleviate the high computational cost associated with these simulations. The difficulty of applying model reduction techniques to porous media flow arises from the nonlinearity of the system. In order to overcome the issue of nonlinearity, we introduce the bilinear form of the dynamical system which in many cases produces a satisfying approximation of the system. The bilinear approximation is a simple form of the parent system and it is linear in the input and linear in the state but it not linear in both jointly. The bilinear form is computed using truncated multidimensional Taylor's expansion of the system terms. Examples are presented to illustrate this recent approach for the case of single phase flow modeling, and comparisons are made with the case of linearized models and the full nonlinear models. In addition, we present methods to reduce the complexity of the bilinear system of equations and results are presented that compare linear model reduction (balanced truncation) and nonlinear model reductions, such as POD techniques.
Catalytic Effect of Metallic Additives on In-Situ Combustion of Two Brazilian Medium and Heavy Oils
Authors: Strazzi Alfonso , Trevisan Osvair Vidal
Published: June 2014

Increasing the final recovery factor from mature fields is a major challenge to meet the growing energy demand in the coming years. The in-situ combustion, an important thermal enhanced oil recovery method, has experienced an increasing interest as an alternative solution to this challenge.

In-situ combustion is the process of injecting oxygen into oil reservoirs where a portion of oil is burned and heat is in-situ generated. As consequence the oil viscosity decreases resulting in larger oil recovery factor. The propensity of the reservoir oil to form fuel is a major constraint limiting the applicability of the in-situ combustion. In lighter oil reservoirs insufficient fuel may be deposited resulting in a combustion front that cannot be self-sustained. Contrariwise, in heavier oil reservoirs excessive fuel may be deposited leading to high air injection. Metallic salts are known to play an important role as a catalyst and thereby affect the amount of fuel formed.

This paper describes an experimental study with eight combustion tube runs to evaluate the effects of metallic additives in the combustion of two Brazilian medium and heavy oils. The oils are 12.8° and 27.2° API, respectively from an onshore field in Espírito Santos Basin and an offshore field in Santos Basin. The metallic additives are iron nitrate and zinc nitrate.

Results for the heavy oil show that a self-sustained front combustion can be obtained only with the presence of clay, due to its catalytic effect. The addition of iron nitrate increased the fuel concentration while increasing the air requirement and reducing the combustion front velocity. The addition of zinc nitrate also increased the fuel concentration and increased the air requirement and reduced the combustion front velocity. Interesting results were observed for the medium oil: a self-sustained combustion was not achieved only with the presence of clay, but stable and sustained combustions were observed with the addition of iron and zinc nitrates.

Iron and zinc salts are metallic additives with potential to expand the range of candidate reservoirs for in-situ combustion. Further studies are necessary to evaluate potential additives to act as fuel reducing agent.
In-Situ Stress Constrain: A Geomechanics Study To Evaluate the Influence of the Structural Geology
Authors: Haddad J. , Ramos J. , Aldana M.
Published: June 2014

The in situ stresses constraint is one of the most difficult parameter in a geomechanics model. Most of them are simple models in which is not involved the influence of geological discontinuities such as complex fault system, bedding plane, folds and joints. Recent studies have pointed out that these can significantly impact on the in situ stress states, leading to changes in magnitudes and rotations of stress tensor along formation sections. However, taking into account the structural geology and projecting the stress state underground, its uncertainty can be reduced. It results in an improvement during the well construction design to obtain a safer operational fluid density window, optimum well trajectories and an effective borehole stability analysis.

This paper presents an integrated methodology to interpolate the magnitude of the stresses and their orientation, including the effect of structural geology. A case of study from Eastern Basin Venezuela, SJ Field, was analyzed. First, a review of the structural geology model was done to identify its origin and the fault history. Then, a geomechanics 1D model with the pore pressure calculation, rock mechanics properties and in situ stress estimations was developed to be integrated with a kinematic analysis in which the structural restoration was defined. Besides, dynamic analysis using a numerical simulation with finite element in a 2D structural section was performed.

The results confirmed that stress state changed not only in orientation, but also in magnitude near to the Anaco Thrust. As a main consequence, the boreholes located next to this structural element experiment variations in depth from normal to strike-slip regime.
Drawdown Management: A Technical and Economic Alternative for Sand Control in Wells: A Colombian Field Application
Authors: Jaimes M. G. , Quintero Y. A. , Contreras G. Y.
Published: June 2014

One of the most common problems during the hydrocarbon production is sand production. Efficient control of the sand production without causing formation damage will depend on the knowledge that we have of the reservoir and also of the designs and estimates that we make during the drilling, completion and production. Sand production causes many problems ranging from collapses in casing, failures of subsurface equipment and surface facilities and accumulation in downhole generating continuous interventions, up to the point of making unproductive wells, thus putting in risk the future interventions of the wells and the capacity thereof in the long term.

In the oil industry there is a diverse range of technologies to control and / or exclusion of sand in open hole and / or case hole that can be mechanicals or chemicals, but the selection must be done carefully, taking into account granulometric and mineralogical criteria for proper selection, because although that we choose the best alternative technique and do a good sand control, the solution may not be optimal from the economic standpoint.

A good decision making process considers other alternatives for sand control, such as handling the drawdown pressure, which in some cases proves to be a technical and economic alternative, especially when the critical drawdown pressure (CDP) presents values over 40% of the reservoir pressure.

A geomechanics evaluation establishes the predictive model of sand production, which allows us to determine the critical drawdown Pressure. From density logs, Vsh, sonic logs, etc. and correlations, the compressive strength (UCS), cohesion, angle of internal friction and mechanical properties of the rock (Young modulus, Poisson's ratio, etc.) are determined. With a geomechanical model (previously selected and evaluated with field and laboratory data), the pressure gradient and the mechanical properties of the rock, the predictive model of sand production is established.

This study was conducted in the fields: Lisama, Galán, Llanito, Yarigui, Cantagallo and Bonanza in Colombia. This article presents the case study in the well Lisama 166, where the drawdown management became a technical and economic alternative for sand control.

Finally, conclusions and recommendations obtained in this study are shown.