Electric Submersible Pumping is one of the predominant lift methods used in Barua-Motatán field of Tomoporo district, Venezuela. Each year the increasing number of ESP failures has become in a crucial issue for the Venezuelan oil company (Petróleos de Venezuela - PDVSA) due to the adversely effecting on lifting costs, rig utility and production. A dual ESP (dESP) completion in which the second pump is used as a backup is proposed in this study as an alternative for optimizing production, increasing ESP run life, reducing unscheduled deferments and minimizing ESP related well services and associated costs.
A critical techno - economics analysis of different proposal from local ESP vendors showed that the suitable option due to space restrictions (casing 7-5/8 in.) is a pod type completion in which primary and backup ESPs are in serial. A risk assessment confirmed the feasibility of the application of dESP in Tomoporo district. The Net Present Value (NPV) of using the new scheme completion proposed is always greater that the conventional single ESP scheme. The high initial capital expenditure incurred from the use of the technology is offset by the significant increase in the profit margin related to the decrease in operational cost and steady production. The most important and unexpected achievement was that probabilities of having negative NPV are reduced considerably with dESP as could be confirmed by risk analysis. Finally, dESP application simplifies drilling scheduling which enhances the planning of well interventions.
The El Cordon Field is located in the prolific San Jorge Basin in Argentina. The El Cordon Field has produced from multiple fluvial volcano-clastic sandstones of Cretaceous age for more than 50 years. Production is primarily from the Cañadon Seco and Caleta Olivia members of the Cañadon Seco formation, and to a lesser degree from the Mina El Carmen formation. The field is characterized by a complex sedimentary environment and mineralogy which affects the quality of the reservoir and makes reservoir characterization and development of exploitation strategies difficult. The field is considered to be in a mature stage of development with over 630 wells under primary production and water injection projects on-going in selected areas of the field.
A Visualization Process Approach was developed in 2007 to identify scenarios to improve recovery and add economic value to the field. After a quick-look reservoir characterization, five scenarios were evaluated for maximizing reserves recovery. Historical and statistical data was analyzed to evaluate various development scenarios and the associated reserves. The various cases evaluated included: 1) a base case; 2) reactivation of existing wells; 3) drilling of wells at normal spacing; 4) infill drilling; and 5) water injection. Application of all cases indicates a potential increase of the field recovery factor from 9.4% to 14.2%. A technical screening for polymer injection feasibility was also analyzed. A second "Conceptualization?? phase would include a detailed reservoir characterization study to help reduce uncertainty and support the definition and implementation of the best scenario for further field exploitation.
Steam injection projects consume considerable amounts of energy to generate steam. Understanding where the heat goes at various times and places during the process provides the means to improve the performance of a project. Enhancements can be achieved integrating an energy balance analysis from the steam generator through the injection network, the reservoir, the producing network and the journey of the produced fluids to the separator.
This investigation presents a workflow to analyze the integration of surface and reservoir systems for a Steam Assisted Gravity Drainage (SAGD) project, to properly estimate energy transfers in the various components of the system thus providing information to improve project planning and enhance both the oil recovery and the economics of the project.
The elements considered in the systems were: boiler, heat exchanger, steam trap, steam injection and well networks, reservoir heat usage, heat losses to the over- and under-burden, production wells and surface networks. Parameters such as completion schemes, artificial lift and boiler-wellhead distances were also analyzed.
Results show that surface-reservoir integration, using reservoir and network simulators, is a powerful tool to estimate heat losses in steam injection projects, helping to understand and successfully optimize their performance. The integration allowed the detection of steam quality variations at injection wells at various times during the process as a function of injectivity changes. Adequately insulated production wells under certain circumstances could produce under natural flow for some FAJA types of reservoirs. However, artificial lift methods had to be incorporated into other completion schemes to compensate for high heat losses and their correspondent increased oil viscosities that imposed higher pressure drawdowns in the production and surface gathering networks.
The SAGD processes analyzed were energy efficient in spite of retaining in the reservoir less than a third of the energy from the steam. In all the scenarios, oil production was considerably greater than the fuel consumed to generate steam.
The paper shows how the analysis of steam injection processes integrating surface, well and subsurface mechanisms allows the identification of critical components of heat losses to optimize the design and operations to maximize oil recovery and reduce energy consumption.
Pinheiro Galvao, Edney Rafael Viana (Universidade Federal do Rio Grande do Norte) | Rodrigues, Marcos (UFRN) | Barillas, Jennys Lourdes Meneses (U. Federal Rio Grande do Norte) | Dutra, Tarcilio (Federal University of Rio Grande do Norte) | da Mata, Wilson (U. Federal Rio Grande do Norte)
The process can be understood as a combination of a thermal method (steam injection) with a miscible method (solvent injection), promoting, thus, reduction of interfacial tensions and oil viscosity. When co-injected with steam, the vaporized solvent condenses in the cooler regions of the reservoir and mixes with oil, creating a zone of low viscosity between steam and heavy oil. Mobility of the displaced fluid is then improved, resulting in an increase of oil recovery and oil rates. To better understand this improved oil recovery method, a numerical study of the process was done contemplating the effects of some operational parameters (distance between wells, steam injection rate, solvent type and injected solvent volume) on cumulative oil produced and oil rates. Simulations were performed in STARS (CMG, 2007.11).
Semi synthetic model was used in this study and some reservoir data were obtained similar to those found in Brazilian Potiguar Basin. The method presented good performance for heavy oil reservoirs with approximately 200 m depth, porosity between 20% and 30%, vertical/horizontal permeabilities ratio of 10% and thickness around 30 m.
It was found that injected solvent volumes increased oil recovery and oil rates. Further, the majority of the injected solvent was produced and can be recycled. For applications of optimized model with oil viscosities of 300 cP, 1000 cP and 3000 cP, the most important oil recovery was obtained for the lightest one (300 cP), while for 1000 cP and 3000 cP, the final recovery was practically the same.
The high initial productions achieved by models that use solvent as an advanced recovery method have normally a significant impact on the operation economics, because early production suggests that fluids injection (steam and solvent) can be interrupted earlier. On environmental point of view, solvent injection can provide a reduction of energy and also a reduction in water consumptions for steam generation, having diminished Green House Gases (GHG) emissions. Also it is important to emphasize that the higher oil rates presented by these models can generate an earlier financial return and, by consequence, a project with a good economical viability.
In the absence of profile modification, water injected into the reservoir will go into the high-permeability zones and will bypass the oil-saturated, low-permeability zones. This paper presents the laboratory evaluation of a water-soluble relative permeability modifier (RPM), a hydrophobically modified polymer that was developed initially for water control in production wells. By injecting the RPM within the high-permeability zones, injected water will be diverted into low-permeability zones to improve the sweep efficiency of the waterflooding project.
The polymer functions by adsorption onto rock surfaces and effectively reduces water flow with little or no damage to hydrocarbon flow. The treatments are extremely easy to mix and pump and require no postjob shut-in time. This RPM was evaluated in 5-ft and 10-ft sandpacks to investigate the following parameters: (a) depth of penetration, (b) diversion properties (c) injection rate, and (d) polymer concentration. High-permeability (~2000-1500 mD) and low-permeability (~250-150 mD) sandpacks were evaluated as porous media. Based on this laboratory evaluation, this RPM can effectively penetrate through a 10-ft sandpack providing permeability reduction to water throughout the length of the porous media. In addition, excellent diverting properties were observed while bullheading the treatment in sandpacks in parallel with significant permeability contrast.
Redeveloping old oil fields can yield great results. This paper summarizes the progress made in redeveloping Colombia's oldest field, La Cira-Infantas. It is located in Middle Magdalena River Valley near the city Barrancabermeja. The field was discovered in 1918, and it has produced nearly 750 million barrels of oil from an estimated OOIP of 3.9 billion barrels of oil within the shallow Miocene and Oligocene age sands that comprise the producing zones. Oil gravities range from 16 to 28 degrees API.
This field had neared an economic limit, but partners Ecopetrol and Oxy decided to implement a waterflood redevelopment project in 2005. The waterflood redevelopment is proceeding well. Redevelopment involves over 1,500 wells being drilled or worked over in order to increase recovery factor by about 8% from the C sands. The redevelopment has involved reconfiguration of old waterflood areas and waterflood expansion into new areas. In addition to the proper reservoir conditions, redevelopment success is due to an understanding of historical performance, the integration of two companies, management of community issues, a build up of rig resources, and the installation of additional facilities.
From September 2005 to January 2009, the production has increased from about 5,000 to 22,000 BOPD. The recent redevelopment has performed similar to expectations built upon evaluations of past development. After upcoming development, the field's production is anticipated to reach around 40,000 BOPD. The Operator's knowledge with a partner's expertise in redevelopment has been a powerful combination. The type of approach being used for the redevelopment may be insightful for other old fields. Potential analogies are not limited to Colombia.
This project has developed a new procedure and a unique statistical and semi-analytical model to predict oil recovery at any water/oil ratio (WOR) and ultimate oil recovery for mature reservoirs under water injection. The new approach uses fractional flow, and multiple linear regressions. We have studied the linear portion of the commonly used plot of log WOR vs. recovery factor (RF) determining the boundaries of that straight-line zone (SLZ) in terms of initial and final RF and/or initial and final WOR numerically using mathematics rules. We also determined slopes and intercepts of this line as functions of commonly used rock and fluid properties values, such as relative permeability curves end-points, connate water saturations (Swc), residual oil saturations (Sor), mobility ratios (M) and Dykstra-Parsons coefficients (VDP). Characterizing this line helps us to determine the performance of a waterflood in terms of RF and pore volumes injected (PVI). We correlated the results from homogeneous and heterogeneous reservoirs by using a correction in terms of the VDP and mobility ratios. We validated the model using reservoir simulation and field cases. Limitations and assumptions are those derived from the application of the simplified fractional flow equation, including that no dip angle, no capillary pressure, and no gravity effects were considered. The model was tested and validated for waterfloods with relatively small initial gas saturation (Sg < 0.2). At higher gas saturations waterflooding process must be applied with extreme care to avoid displacing oil into the gas cap zone and reducing the remaining oil saturation (ROS).
When wellbore micro-tortuosity in Neuquina Basin wells in Argentina made logging information unreliable or difficult to acquire, a collaborative process was initiated between personnel from drilling engineering and from the bit application design group. This collaboration resulted in a custom PDC bit solution that reduced vibration and improved overall wellbore quality without sacrificing steerability or penetration rate.
In the El Trapial field, drilling practices over the course of more than 800 wells have progressed from use of roller cones bits to rotary drilling using PDC bits. Additional improvements were realized with the addition of mud motors that achieved better rates of penetration. The use of various bit types to finely-tuned design configurations have now resulted in record rates of penetration (ROPs).
As the performance improved, additional directional targets have been incorporated into the operation, making the wells slightly more complex, but still manageable. However, increased wellbore tortuosity has made the acquisition of logging data difficult and the acquired data questionable. Specifically, the reservoir department expressed concern about the accuracy of the acquired data, and consequently some calculations of saturations (Sw) were questioned.
This paper describes the process used to determine the bit design parameters needed to optimize performance and to improve the wellbore quality in these wells. The process required gathering, compiling, and processing extensive data on all aspects of drilling. The anticipation of improved performance was based on a review of previous bit design features, historical developments in bit design, dull condition studies, studies of penetration rate vs. drilling parameters, formation statistics and field feedback, directional survey data, specific energy studies, and reported performances improvements. This paper also describes the collaborative design process, the resulting changes in bit design, and the performance results.
The oil and gas industry has long recognized the inadequacy of existing theories to predict the behavior and outcome of some hydraulic fracturing treatments. Data sets compiled over the last two decades are incompatible with the conventional picture of a single planar hydraulic fracture. Multiple fracturing can occur in the near-wellbore region or far field, and the path of multiple fractures can be divergent, such that they grow out of each other's influence zone, as in the case of dendritic geometry, or narrow, as in the parallel geometry. Analytical, semi-analytical and numerical models have been developed for a well intersecting infinite conductivity vertical fracture. A hydraulically induced fracture is usually represented by a thin vertical plane that extends a finite distance from the well. The fracture is created by tensile stresses, and it exists in a single plane and grows in an orderly and predictable manner, in a pattern that can be defined as balanced. This model is not incorrect, but it is not representative of all hydraulic fracturing scenarios.
This study presents an analytical model to analyze the transient flow due to near wellbore multiple fractures in homogenous and naturally fractured reservoirs. The model considers arbitrary angles between the fractures. This study also uses a numerical model to calibrate and validate the analytical model. TDS technique is also used to analyze the linear and pseudo-radial flow regimes in order to find fracture length, fracture conductivity and several conventional reservoir parameters, e.g. permeability, wellbore storage and skin factor.
Multiple fractures create more surface area in direct communication with the wellbore. As a consequence greater volume of fluid can be produced from the wellbore per unit time. While fracture treatments continue to be designed using the best tools and techniques available, geometry estimates from fracture models have been difficult to verify. Pressure transient analysis is one of the fracture diagnostic techniques available to fill this knowledge gap, improving our understanding of hydraulic fracture behavior. It is an excellent calibration tool because it lets us evaluate the effective length of the fracture, which is the better length to use in history matching. Also, regardless of the application, identifying and understanding fracture complexities can lead to improved treatment designs, better completion strategies, and the potential for significant economic rewards through improved well performance and/or reduced completion cost.
Deepwater fields are one of the largest growth segments of the industry. The technologies that enable this growth economically are those that provide improvements in operational reliability, flexibility, and cost, and which mitigated risks. With offshore rig rates often hitting $500K US per day, special considerations must be taken into account when specifying or designing an upper deepwater completion at depths greater than 1,000 ft (305 m). When selecting a completion scenario, an accurate assessment of risk versus reward must be analyzed in order to design a cost-effective, yet flexible completion. In this paper, the authors outline the proper methodologies in selecting existing technology for each completion approach in subsea and dry tree applications.
Design methodologies for deepwater completions vary when compared to conventional type completions. The basis of design in a conventional type completion includes: 1) a production packer to isolate pressure and fluids from the producing zone and manage production tubing movement and loads; 2) a surface-controlled subsurface safety valve (SCSSV), whose objective is to isolate the tubing and well head from well fluids in an emergency or planned shutdown; and 3) flow control equipment, such as landing nipples, chemical injection nipples, and sliding sleeves. Deepwater subsea or dry tree completions have similar basic requirements as that of conventional completions. However, critical to deepwater are the completion design, planning, quality assurance and quality control, reliability, execution/deployment, and longevity of the completion.
Drivers for completion methodologies in subsea and dry tree applications will be discussed. Issues such as tubing space-out, packer-setting methods, SCSSV operating parameters, sub-mudline tubing and packoff hangers will be reviewed. Temporary well suspension methods will also be discussed where applicable and different completion options will be outlined for each case.
History and Classification
The demand to replace reserves is pushing operators to drill deeper reservoirs in deeper water. Some of the challenges of producing hydrocarbon in this type of environment are to identify viable prospects, and efficiently drill and complete these wells. These challenges are driving the industry to develop technologies that will address this high-cost environment. So what is considered deepwater? US Mineral and Management Service (MMS) considers water more than 1,000 ft (305 m) to be deepwater. In the industry, some operators consider ultradeep water as more than 5,000 ft (1524 m).
Deepwater oil and gas production is increasing rapidly and output is expected to more than double by 2010. From 3 MMb/d in 2005, deepwater oil production will grow to over 6.7 MMb/d in 2010, while deepwater gas production will increase from 60 to 108 bcm (1-1.9 MMbbl equivalent) over the same period. To put this in context, deepwater oil production currently accounts for 10% of the total offshore oil production; however over the next 10 years, its total share relative to shallow water output will rapidly grow and account for an estimated 25% of offshore production by 2015.
The most identifiable deepwater markets are Africa, Gulf of Mexico, and Brazil, which account for 80%-90% of current deepwater production. Latin American counties (Mexico and Colombia) and Asia (Indonesia and India) are upcoming markets that are pursuing development in water depths in excess of 1,000 ft (305 m).