bluuebunny/crossref_metadata_2025 huggingface dataset:
When Water Means Oil: Block 16 Case History
Authors: Feria C. Correa , Pazmin R. Gomez
Published: May 2009

In heavy oil reservoirs with strong water drive, oil production with high water rates is expected. Block 16, located in the Ecuadorian rainforest, is not an exception.

Currently Block 16 has an average oil production of 50,000 bopd (15° API mixture) with 940,000 bwpd. As the oil production rate declines, produced water increases and adjustments on the water handling systems must be made in order to ensure a safe and efficient process.

The purpose of this paper is to present an overview of the challenges that implies the water handling management on such a sensitive and changing environment, placing a particular focus on the modeling and simulation techniques employed to optimize the injection system.

In order to predict and improve the disposal water management, an integrated water handling model for the southern area of the block was built; this model includes all pumping stages (booster, medium and high pressure), an extensive pipeline network and the 21 water disposal wells. The model helps to identify bottlenecks, overloaded equipment and the best equipment repositioning strategy to improve energy consumption.

Once the model was ready, several simulations were ran, and they were useful to identify that the main issues to increase the water handling capacity were not about surface equipment, but the disposal wells' capacity. This helped to redefine the water handling investment strategy, pointing towards to improve wells' disposal capacity rather than investing on surface equipment upgrades.

As the main conclusion, the study lead to identify the need of a scientific approach to characterize the water handling processes taking into account all the systems involved, rather than the single well to well traditional analysis.
Swabbing Test Interpretation Using Nonlinear Regression in San Jorge Gulf Basin
Authors: Naranjo Euver , Bravo José , Díaz Eugenio , Caldera José
Published: May 2009

In the San Jorge Basin in Southern Argentina swabbing test is the conventional testing technique used by YPF to evaluate production potential on those reservoirs that do not flow naturally to surface. During the well completion phase, a swabbing device is lowered subsequently to individually test each reservoir layer. These wells, which produce from multilayer formations, are later completed for commingled production. Accordingly, the swabbing test represents the only opportunity to measure dynamic properties for every individual layer.

So far pressure transient analysis of such test has been limited to the use of conventional interpretation methods applied to the Infinite Acting Radial Flow portion, on those tests where such flow regime is observed. This can happen if a bottomhole shut in valve is used or if the shut-in period is given long enough time for the bottom hole pressure to reach conditions close to initial reservoir pressure. Unfortunately, both practices substantially increase the completion cost, which strongly affects well economics. As a result of this economic limitation, neither of such practices are applied on a routine basis so most of the time transient pressure interpretation is not performed.

In an attempt to get value from routine swabbing tests, where Infinite Acting Radial Flow condition is not observed, a different methodology of test interpretation has been introduced. Through the computation of the instantaneous flow rate from the pressure trend increase during the swabbing period, it is possible to use nonlinear numerical regression to make an estimation of the reservoir permeability even if Infinite Acting Radial Flow is not present.

With this innovative approach YPF is, for the first time, constructing representative production models for each well, improving reserve estimations and production forecasts.

A correlation between dynamic permeability from nonlinear regression and permeability from Nuclear Magnetic Resonance Tool has also been constructed in order to reevaluate production response in old wells.
Simulation Study of Steamflooding with Horizontal Producers Using PEBI Grids
Authors: Gonzalez K. , Bashbush J. L. , Rincon A.
Published: May 2009

Steamflood with conventional vertical wells results in poor vertical sweep efficiency and steam breakthroughs when it is applied to heavy oil reservoirs. The use of horizontal producers provides a larger contact area with the reservoir resulting in a better drainage and therefore enhancing the well productivities by improving the steam sweep efficiency.

This study explores and compares the efficiencies of steamflooding in an improved version of an inverted 7-spot pattern with a vertical injector in the center and horizontal producers versus vertical producers in a representative numerical geological model from the Orinoco Oil Belt.

The simulation of the complex displacement processes1 combined with the well configuration results in challenging computational issues. As a result of the mechanisms involved in steamflooding, including oil viscosity reduction, steam condensation into hot water, large mobility ratio differences in the displacement processes, etc., the Grid Orientation Effects (GOE) could be significant. A grid selection process was performed to reduce grid orientation effects comparing the steam displacement in a Cartesian grid versus those from an unstructured Perpendicular Bi-sector (PEBI) grid.

Once the grid was established, sensitivity analyses were carried out to define the optimal design parameters to improve sweep efficiency and reduce recovery times. The parameters analyzed were: (1) placement of the horizontal producers within the vertical reservoir pay, (2) placement of the toe and heel of the horizontal producers, and a sensitivity analysis to (3) bottom hole flowing pressure, and (4) steam injection rates.

Reservoir conditions were also studied to explore the effects of: (1) pay thickness, (2) variation of horizontal permeability, (3) permeability anisotropy generated from geostochastic distributions, (4) and previous cold production, in the overall process performance.

The use of PEBI grids allowed to model in a more accurate way complex thermal-compositional displacement processes involving horizontal wells not aligned with the orthogonal Cartesian axes, and demonstrated that steamflooding using horizontal producers offers the potential to improve conventional schemes achieving higher oil recoveries from heavy oil reservoirs.
Energy Balance in Steam Injection Projects: Integrating Surface-Reservoir Systems
Authors: Valbuena E. , Bashbush J. L. , Rincon A.
Published: May 2009

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.
Evaluation of the Effect of Oil Viscosity on the Disproportionate Permeability Reduction of a Polymeric Gel Used for Controlling Excess Water Production
Authors: Prado M. , Reyna M. , Rauseo O. , Ferreira I.
Published: May 2009

The property by which polymeric gels reduce water permeability in larger proportion than oil permeability is known as disproportionate permeability reduction (DPR). This phenomenon is believed to be the result of preferential blockage of water pore channels combined with the exclusive capacity of oil to deform the gel. This property represents an opportunity to successfully control water production, regardless the cause of the excess water inflow or the type of well completion. For this reason, many investigations intended to understand and improve DPR have been carried out.

The relationship between DPR and parameters such as rock permeability, wettability and flow rate has been widely described. Nevertheless, no efforts have been made yet to evaluate the influence of oil viscosity. Considering the importance of heavy oil production for Venezuelan oil industry, as well as the growing impact of excess water production in these reservoirs, an experimental study was carried out to evaluate how DPR is affected by oil viscosity.

Four coreflood experiments were carried out in high-permeability Berea cores to measure oil and water permeability before and after gel placement. In the first three tests, DPR was determined using oil with viscosities of 1.8; 67 and 140 cp. The last test consisted on sequentially measure the permeability of each of the oils when flowing through the same fully gel-saturated Berea core.

Experimental results indicate that DPR improves as oil viscosity increases because 1) oil viscosity affects gel placement favouring selective plugging of water channels; and 2) the more viscous the oil, the larger the deformation of the gel, thus the easier for the oil to open a channel through it. According to this, a large potential of controlling excess water production in viscous oil reservoirs through gel technology application was established.
Guando Field: Underpressured-Field Development, Part II
Authors: Valbuena Amaris O. H. , Moreno J. M. Montoya , Martinez B. Duran , Rovira D. L.
Published: May 2009

SPE paper 94569 (2005) presented the generalities, characterization and initial development plan of the Guando field, an extremely underpressured, sandstone, partially naturally fractured reservoir. This paper will present global results of the initial development program and the bases which guided to implement a reduced spacing project based on decreasing wells distance from 250 to 145 meters. Results of this new development stage are presented and discussed.

This project increased field reserves in 15% and accelerated the production, allowing a 15% recovery factor in just seven years since the field exploitation started and nine years from its discovery and only with a total injected water of 0.25 volumes of its original oil in place.
Optimization in Completion Wells With a Packerless, Multistage Fracture-Stimulation Method Using CT Perforating and Annular-Path Pumping in Argentina
Authors: Bonapace J. , Kovalenko F. , Canini L. , Sorenson F.
Published: May 2009

This paper documents pinpoint fracturing (PPF) in Argentina. The implementation of this method has resulted in 193 fractures in 22 wells since October 2006.

The PPF method creates perforations by pumping abrasive slurry down the coiled tubing (CT) through a jetting nozzle, while the main treatment is then pumped down the annulus around the CT. Isolation between fracture treatments is accomplished using sand plugs (preferred method) or composite bridge plugs.

This technique has allowed greater selectivity in the stimulation of the areas to be treated; it has also allowed a more aggressive fracture treatment in terms of percent pad and the final proppant concentration because the CT is at the location in case of screen out. In gas fields, it offers the advantage of completing the well without killing it.

Different reservoirs with varying depths, temperature, types of fluid, and petrophysical conditions in the basins Golfo San Jorge and Neuquina were stimulated with different fracture fluids, proppant types, and frac gradients.

The Neuquina basin required fracturing without using a workover rig in oil and gas fields near the community, while significantly diminishing the working times with a reduction in environmental impact and noise generated during the completion. However, the main goal was the reduction of completion times in each well performed in the different basins of Argentina.
Multiple Fractures Transient Response
Authors: Restrepo D. P. , Tiab D.
Published: May 2009

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.
Improvement of Drilling Operations on Horizontal Wells at the Orinoco Heavy Oil Belt, Venezuela
Authors: Andérico Luis , Larreal Ender , Ruiz Martín , Muñoz Nilson
Published: May 2009

Stuck pipe incidents and excessive torque and drag have been common problems encountered while drilling horizontal wells in the Orinoco Oil Belt which contains Venezuela's largest heavy oil reserves concentration. These incidents have been attributed mainly to high levels of friction between the drillstring and the heavy oil sands. To help prevent sticking, a common practice has been to add 10 to 20 vol% of diesel to the water-based fluid when drilling the horizontal sections. Open hole displacement of mud by diesel had also has been used to free stuck pipe. However, many of these incidents have resulted in the loss of the bottomhole assembly and the need to perform sidetrack operations.

Typically, engineered fluid solutions have been required to solve friction issues related to horizontal sections and tortuous well geometries. Additionally, a hydrocarbon-free and non-damaging lubricant option has been necessary to help prevent excessive torque and drag when drilling 2D and 3D well trajectories with a water-based fluid.

Recently, a viscoelastic drilling fluid comprised of a blend of special synthetic oils and surfactants has helped reduce the coefficient of friction in water-based mud by as much as 50% without adversely affecting the rheological properties, as well as dissolving bitumen and preventing emulsification of the heavy oil and sand. After the lubricant treatment, torque and drag values experienced while drilling highly deviated sections through unconsolidated sands at instantaneous penetration rates of up to 1,300 ft/hr have decreased from 18,000 to 12,000 lbf-ft. Also, because no stuck pipe incidents occurred and clean-up trips weren't required, considerable rig time was saved.

This paper discusses key aspects of the performance of the water-based, hydrocarbon-free, non-damaging lubricant used in drilling the Orinoco Oil Belt horizontal and multilateral wells, as well as the factors that enabled PDVSA to achieve project targets in a safe and timely manner and to minimize any detrimental environmental impact.
Critical Oil Rates in Naturally Fractured Reservoirs to Minimize Gas and Water Coning: Case History of a Mexican Carbonate Reservoir
Authors: Hidalgo O. J. , Brito L. E. , Garrido R. , Munoz J. , Paz F. , Flamenco F. , Aguilera R.
Published: May 2009

This study extends Birks (1963) coning method by defining various options for calculation of the critical oil rate in naturally fractured reservoirs through an explicit use of the radial pressure gradient in the fracture, ∂P/∂R. The study aims at minimizing gas and water coning, and introduces methodologies for estimating fixed and variable radius of drainage, as well as an iterative procedure for calculating the critical oil rate and the drainage radius within the fracture.

The methodology has been used with good practical results, allowing optimization of oil production, in various naturally fractured carbonate reservoirs in the southeast of Mexico.

Determining a critical or maximum efficient oil rate in naturally fractured reservoirs is very important in those cases where oil productivity can decrease significantly due to increases in water/oil and/or gas/oil ratios. Imposing a critical oil rate is also related to the capacity of fluids handling in surface installations and reservoir management when gas and/or water injection projects are being conducted in the reservoir.

It is concluded that the methodology, which is not developed with the idea of replacing detailed coning simulation studies, can be used quickly, easily and with a good level of certainty in naturally fractured reservoirs.
Macrokinetics of Matrix Gas Release and its Influence on Coalbed Methane Flow and Production
Authors: Fathi E. , Akkutlu I. Yucel
Published: May 2009

In coalbeds and shales, gas transport and storage are important for accurate prediction of production rates and for the consideration of subsurface greenhouse gas sequestration. They involve coupled fluid phenomena in porous medium including viscous flow, diffusive transport and adsorption. Standard approach to describe gas-matrix interactions is deterministic and neglects the effects of local spatial heterogeneities in porosity and material content of the matrix. In this work, adopting weak-noise and mean-field approximations and using a statistical approach in spectral domain, matrix heterogeneity effects are investigated in the presence of non-equilibrium adsorption with random partition coefficient. It is found that the local heterogeneities can generate non-trivial transport and kinetics effects which retard gas release from the matrix and influence the ultimate gas recovery adversely. Macro-transport shows 1/ [1 + NPe / (1+ NPe)] dependence on the Péclet number, and persists at the diffusive ultra-low permeability limit. Macro-kinetics is directly related to Thiele modulus by the following expression: NTh / (1+2 NPe). It leads to trapping of gas in the adsorbed phase during its release from the matrix and to an adsorption threshold during the gas uptake by the matrix. Both effects are proportional to the initially available adsorbed gas amount and become more pronounced with the increasing variance of the porosity field. Consequently, a new upscaled deterministic gas mass balance is proposed for practical purposes. Numerical results are presented showing free and adsorbed gas distributions and fractional gas sorption curves for unipore coal matrix exhibiting Gaussian porosity distribution. The work is a unique approach for our further understanding of the coalbeds and gas shales, and it is important for the development of sound numerical gas production and sequestration models.
New Fracturing Fluid for High Temperature Reservoirs
Authors: Abad C. , Mirakyan A. , Parris M. , Chen Y. , Mueller F.
Published: May 2009

The extent of crosslinking a polymeric fracturing gel can significantly contribute to the success or failure of a hydraulic fracturing treatment. In certain cases, excessive crosslinking while the fluid is in the tubulars can result in friction pressures that are too high, and may prohibit the treatment from achieving the design goals. With titanium (Ti) or zirconium (Zr) crosslinked gels, which are known to be prone to irreversible shear degradation, early crosslinking in the tubulars can substantially reduce the final gel strength, even to the degree that near wellbore proppant transport is compromised, and the treatment may screenout. On the other hand, a Ti or Zr crosslinked gel which crosslinks substantially after exiting the perforations may not have sufficient proppant transport capability to complete the treatment successfully.

Varying treatment conditions such as mixwater composition and temperature, tubular shear rate and transit time, and reservoir temperature pose difficult challenges to routinely achieving the optimal crosslinking state. Conditions such as offshore wellbore temperature profiles and viscous heating in smaller diameter tubing can further complicate the task. Various chemical means have been employed to tune the crosslinking temperature for specific treating conditions. These methods involve addition of chemicals to control the crosslinking kinetics, such as pH buffers, crosslinker concentration, and competing ligands to temporarily bind the metal crosslinker. Blended crosslinkers containing a single Group 4 (Ti, Zr) metal with different organic ligands with different binding strengths have been employed to achieve crosslinking at two temperature ranges so that early viscosity for proppant transport can be developed. Mixed metal crosslinkers, such as aluminum and Zr have also been formulated for this same purpose.

This paper examines the disadvantages of these strategies, and describes the development and deployment of a high-temperature fracturing fluid system that has shown to overcome those issues.
Laboratory Evaluation of RPM for Profile Modification in Injection Wells
Authors: Vasquez Julio , Eoff Larry , Dalrymple Dwyann
Published: May 2009

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.
Application of a Design Customization Process Provides Immediate Solution to Microtortuosity Issues in Known Field
Authors: Sieyra J. , Lundin S. , Medina G. , Cortina C.
Published: May 2009

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.
Integrated Production Model With Stochastic Simulation to Define Teotleco Exploitation Plan
Authors: Czwienzek F. B. , Perez J. Barreto , Salve J. G. , Martinez Ramirez I. , Gerardo M. V. , Aguilar R. H.
Published: May 2009

PEMEX Exploration & Production, with the technical support of Landmark Halliburton Mexico, implemented front-end-loading (FEL) methodology to define the optimum exploitation plan for the Teotleco oil field. FEL methodology, a relatively new approach in upstream project evaluation, considers the generation of multiple scenarios and analyzes the uncertainty and risk associated with each scenario.

A decision matrix was used to generate the scenarios in which several exploitation options were considered. One scenario was the current base case. Traditionally, base cases have been documented in a deterministic way using mathematical models, supported by exponential decline curves, for calculating production forecasts without considering the effects of individual wells and surface facilities. At the present time, however, there is commercial software that considers not only reservoir and well conditions but also considers surface operational conditions for production forecasts. This software leads to more realistic results.

Integrated Production Models(IPM) are very useful tools for calculating production forecasts and for optimizing field development. These models only provide a single possible solution each time they are run; but, now, deterministic models can be coupled with stochastic simulation programs to obtain probabilistic results.

Stochastic models require that uncertainties associated with each variable in the value chain (reservoir, drilling, productivity, facilities, economic evaluation, safety and environmental protection) be identified, characterized, and included in a new model, the Fully Integrated and Stochastic Asset Model (FISAM).

This paper shows the workflow to integrate reservoir (material balance), well (nodal analysis), and surface facilities conditions (pipelines and separation conditions), with an economics model (key performance indicators) using a stochastic simulator. The results of this workflow — which consist of production profiles, economic evaluation, and risk analysis — enable managers to improve project decisions.

The Teotleco FISAM model evaluated 15 exploitation scenarios. Review of the Net Present Value (NPV) and the associated risks in the value chain identified and then prioritized those scenarios that challenged the current base case. The flexibility and versatility offered by this approach for evaluating multiple scenarios facilitated the preparation of new updated PEMEX E&P exploitation plans. In these plans, which include new fields such as the Teotleco Field, the level of existing uncertainty will be recharacterized using new information generated as fields are exploited.
High-Temperature Water Control With an Organically Crosslinked Polymer-Case Histories From Mexico
Authors: Mercado M. , Acuna J. C. , Najera D. , Caballero C. , Soriano E. Duverney
Published: May 2009

One of the major challenges faced in southern Mexico is water management. Producing zones are often considered for abandonment even when the intervals still retain large volumes of recoverable hydrocarbons. For many years, conformance-polymer systems have been successfully applied to control undesired water production from hydrocarbon wells. However, currently available polymers present a number of limitations for high-temperature wells (>250°F) in terms of providing longer gelation times and acceptable thermal stability. In most of the wells in Mexico, bottomhole temperatures are above 300°F with depths around 15,000 ft. This paper presents the successful field implementation of an organically crosslinked polymer (OCP) for high-temperature applications in areas of southern Mexico that are producing hydrocarbons from naturally fractured carbonates. These treatments were performed by bullheading through the producing tubing without the need to pull the tubing out of the well.

The OCP system is based on a copolymer of acrylamide and t-butyl acrylate (PAtBA) crosslinked with polyethyleneimine (PEI). To date, about 300 jobs have been performed with the OCP system around the world to address conformance problems such as: water coning/cresting, high-permeability streaks, gravel-pack isolation, fracture shut off, and/or casing-leak repair. More than 150 of these jobs have been performed in Mexico alone. Originally, the OCP system had a limited working temperature range of 100 to 250°F. The upper-placement temperature of the system was ~250°F because above this, temperature-pumping times were too short. A recently developed polyamino-acid retarder has allowed reasonable placement times up to 350°F without the need for cooling down the formation to obtain enough pumping time. The retarder is not detrimental to the thermal stability of the system.
Study of Gas Injection Effects on Rock and Fluid of a Gas Condensate Reservoir during Underground Gas Storage Process
Authors: Moradi B.
Published: May 2009

Underground gas storage (UGS) is a common activity in countries with major transport and distribution gas pipeline infrastructures, which allows to efficiently resolving demand seasonality problems. Natural gas injection and storage in depleted gas condensate reservoirs is a common challenge in downstream petroleum industrial jobs. Generally the gas condensate depletion process take places partially, hence the injected light natural gas into the proportionally heavier condensates lead to remarkable changes in gas relative permeability and condensate saturation. These variations affect gas production directly.

In this work, UGS was studied on a gas reservoir through compositional simulator. The oil field under study is a gas condensate reservoir located in central Iran. A synthetic model of the gas condensate reservoir was generated which investigates the effect of natural gas injection and production upon variations in gas relative permeability and condensate saturation within near and far away areas of the wellbore. Before natural gas injection and production cycles begin to implement, storage able gas volume and base gas in place volume are calculated through volumetric and material balance methods to determine the optimum pressure for the first injection.

It was found that both condensate saturation and gas relative permeability were sensitive to injection rate. The results on gas relative permeability suggest that gas productivity curtailed by condensate drop out can be somewhat restored by increasing injection and production cycles.

Injection of higher volumes of gas in the first cycle prevents condensate from forming and increases gas productivity index.
Drilling Cost Reduction Through Use of Torque Controlling Features on Steerable Drill Bits Within Latin America
Authors: Barton S. , Garcia A. , Pogliano P. , Silva A. , Pelligra M.
Published: May 2009

Toolface Control is widely regarded as one of the greatest challenges when drilling directionally with a Fixed Cutter (FC) drill bit on a Steerable Motor assembly. Toolface offset is proportional to the torque generated by the bit, and by nature, FC bits generate high levels of torque. If large changes in downhole torque are produced while drilling, this will cause rotation of the drill string, and loss of toolface orientation. This results in inefficient drilling and increases risk of bit and downhole tool damage.

This paper examines the effect of varied components of a FC drill bit to determine the key design requirements to deliver a smooth torque response and improved directional performance. This includes review of the results from comprehensive laboratory testing to determine the effectiveness of a number of varied, removable Torque Controlling Components (TCC). These, in combination with specific cutting structure layouts, combine to provide predictable torque response while optimized for high rates of penetration. In addition, unique gauge geometry is disclosed that was engineered to reduce drag and deliver improved borehole quality. This gauge design produces less torque when sliding and beneficial gauge pad interaction with the borehole when in rotating mode.

Field performance studies from within Latin America clearly demonstrate that matching TCC, an optimized cutting structure, and gauge geometry to a steerable assembly delivers smooth torque response and improved directional control. Benefits with regard to improved stability are also discussed.

Successful application has resulted in significant time and cost savings to the operator, demonstrating that Stability and Steerability does not have to result in loss of penetration rate.
Analytical Simulation of the Injection/Production System of La Cira East and North Areas Using CGM Method
Authors: Gomez Vicente , Gomez Adriana , Duran Javier
Published: May 2009

Ecopetrol and OXY signed in september 2005 a commercial and technical agreement to increase the oil and gas production in La Cira - Infantas, a mature oilfield located in the Magdalena Middle Valley basin in Colombia, which was discovered in 1918.

The East and North areas of La Cira - Infantas field had in 2006, 107 producers and 21 injectors active wells and has been waterflooded since 1957. This paper illustrate the methodology used and the results obtained in the estimation of the areal and vertical efficiencies of the waterflooding process using the analytical method of Craig, Geffen and Morsen applied by the use of a software developed by Ecopetrol S.A called ASIA (Advanced System for Injection Analysis).

Available information analysis, databases generation, pattern definition, and history matching were the main considerations applied to implement the methodology which let us to identify non irrupted sands, non swept zones, water losses, existing pattern real status and real performance of the waterflood process in the selected area.

Analytical simulation results showed that the system had serious problems related to lack of hydraulic connectivity between producers and injectors sands and water that had been pumped out of interest zones which were related to zones near to a faulty area. Calculations obtained using the ASIA software, showed that only 233 millions of barrels had been effectively injected in the area, it does mean that nearly 38% of the injected water had been lost.

After this evaluation, Ecopetrol and OXY began an aggressive program of activation of producing wells and injectors and configuring new patterns of injection, a strategy that has led to increase the production of the area in about 3000 bopd.

The application of this methodology using the ASIA software will help in designing and surveillance of waterflooding process in other Colombia fields. Prior knowledge of waterflooding conditions will help in defining better strategies and conditions for the process.
Experimental Design: Three Contrasting Projects
Authors: Murtha J. A. , Osorio R. , Perez H. H. , Kramer D. L. , Skinner R. J. , Williams C. A.
Published: May 2009

The objective of Experimental Design (ED) is to develop one or more proxy equations to represent a reservoir simulator model and then use that equation for Monte Carlo (MC) simulation. A proxy equation is generally a quadratic

(1) Y = a 0 + a 1 X 1 + a 2 X 2 + … + a n X n + b 1 X 1 2 + b 2 X 2 2 + … + b n X n 2 + c 1 X 1 X 2 + c 2 X 1 X 3 + …

which sometimes reduces to linear with no Xi2 or XiXj terms. Here Y represents a reservoir simulator output of major interest such as expected ultimate recovery (EUR) oil or gas. The Xis are initialization parameters for the simulator. These variables are inherently uncertain, such as gas-water contact, pore volume or its components, permeabilities, or trapped gas saturation. The ultimate deliverables of ED are a probability distribution for Y and a sensitivity chart ranking the Xis. The obvious advantage of a proxy equation is that it can be executed in microseconds while the simulator requires hours or even days. The shortcoming is that a proxy equation cannot completely represent the complexities of the simulator. We propose to contrast and compare three recent Colombian ED studies, ranging from an exploration project to a mature field; from two parameters to 10; from 13 years of production history to a single well test; both linear and quadratic proxy equations, and a variety of choices for Y.

Each project offered new challenges and required some departure from a traditional workflow. These mini case studies illustrate the breadth of ED and some pitfalls we encountered. Aside from the simulator and Excel, the only software packages used were generic Monte Carlo and statistical packages.

Any ED project begins by identifying uncertain initialization parameters and ends with a proxy equation and its Monte Carlo simulation. What happens in between, however, depends on the particular situation. The nature of the key output(s), the number of variables, the complexity of the reservoir simulator, the challenge of any history match, and the quality of the results can vary considerably from one project to another. With a methodology relatively new to our industry, sharing the strengths and weaknesses of the process can be valuable.
Laboratory Investigation of E-Beam Heavy Oil Upgrading
Authors: Yang D. , Kim J. , Silva P. C. F. , Barrufet M. A. , Moreira R. , Sosa J. M.
Published: May 2009

Electron beam (E-Beam) heavy oil upgrading, which uses unique features of electron beam irradiation, can be a solution to minimize the critical problem of upgrading heavy oil. Enormous amounts of heavy oil reserves exist in the world, but the lack of cost-effective technologies hinders the development of heavy oil reserves. One of the critical problems of heavy oil or bitumen is that it takes large amounts of thermal energy and expensive catalysts to upgrade. E-Beam processing will allow lowering the thermal energy and sharply reduce the investment in catalysts. The design can be simpler and will contribute to lowering the production and transportation cost of heavy oil and bitumen.
Enhanced Rocker Tool used to Restore the Permeability of Formations: Case Studies
Authors: Almeida J. B. N. , Suzart J. W. P. , Paiva M. D. M. , Santos J. A. C. M. , Santos F. H. M. , Barbosa V. P.
Published: May 2009

The northeastern region of Brazil is the largest onshore oil producer in the country. However, regional oil production is still much less than offshore production in other Brazilian basins. Therefore, customized low-cost technologies are routinely employed locally to deal with issues, such as perforation plugging, scaling, and sediments production, for example. Heavy oil produced in this area builds up paraffin and asphaltene deposits over time, further decreasing productivity of the fields. This paper discusses applying a true fluidic oscillator (TFO), an enhanced rocker tool (ERT) that synergistically combines fluidic, acoustic, and chemical effects, to enhance the action of a fluid treatment on the formation. Usually, this tool is used in conjunction with coiled tubing (CT) equipment. Because the operator considered a CT operation too expensive for the needs of this region, the tool was run into the well with a regular work string as a lower-cost alternative. Three similar wells in the Potiguar Basin were selected and treated with diesel and butyl glycol through the TFO with significant improvement in estimated permeability and oil production (an increase of 20% to 240%) after treatment. Overall, the tool enhanced the treatment effectiveness by amplifying the contact area between fluids and formation. This demonstrated the applicability of this cost-effective solution for stimulation of low-productivity wells.
Completion Robustness as a Production Management Tool: Case History in a Mature Offshore Field
Authors: Rodrigues V. F. , Catarina A. , Medeiros R. , Quitar L. D. , Chilelli C. F.
Published: May 2009

There is an ever present demand for increasing or maintaining the oil and gas production, on a production unit basis. Thus, it is very important to have a method to define the maximum safe production rate from the completion point of view. In recent years some oil companies introduced sophisticated integrated asset models for production optimization which include well quality assessment and surveillance. This approach allows a quasi-real time production optimization.

This paper introduces the concept of completion robustness, related to the maximum safe production rate, and applies it in a low level of well surveillance floating production unit. Some relevant aspects of the production unit regarding the wells are: subsea completions, a broad range of sand exclusion systems, and most of the wells are on stream for seven years. The paper presents the completion robustness concept, the general method to apply it, and the procedures developed for the specific case study, in which the connectivity between the formation and the well through the sand exclusion system plays an important role.

The main product attained is a list ranking the wells in terms of completion robustness. Based on this list the asset team can decide which wells may support a production increase, which wells must be kept in the current status, and which wells need an intervention or a rate reduction. The main conclusions achieved are: the completion robustness concept is a rational approach to define maximum safe production rate per well from the completion point of view; the method and procedures developed, although suitable for production units with high level of reservoir and well key parameters surveillance, can also be applied to low level of surveillance ones; the use of the completion robustness by the production operations teams have the potential to increase the production output and the wells longevity.
Unique Bi-Center Technology Delivers in Demanding Directional Applications
Authors: Barton S. , Garcia A. , Luther C. , Rodriguez L. A. , Castillo R. , Perez L.
Published: May 2009

Hole-opening on directional motor assemblies has always been problematic. This is due to the fact that mainstream string hole opening tools cannot be used due to lack of rotation during periods of sliding. As such, use of bi-center hole opening bits have increased in an attempt to drill and open the hole in one run with a directional motor. This paper documents the development of a unique bi-center design to provide not only reliable hole opening, but also high and consistent dogleg response on a motor assembly.

The project is focused on a drilling program within the Uracoa field in Eastern Venezuela (Figure 1). This application called for a build from vertical to horizontal, with maximum dogleg severity (DLS) requirement of 10.2deg/100ft. This had not been attempted in the past with bi-center bits, relying instead on conventional 8 ½" PDC bits. However, the operator had hole problems that made running 7" casing difficult in this section. To get the casing to bottom, a number of wiper trips were required to condition the hole.

In order to reduce the non-productive time, a bi-center and directional motor were selected by Petrodelta / PDVSA to eliminate the additional wiper trips required with the conventional fixed cutter (FC) bits: The 8 3/8 x 9 ½?? bi-center would effectively drill a larger hole size. The unique design selected features a mid-reamer section. This double profile design is considerably more stable than prior technology, delivering improved borehole quality and enhanced directional performance.

The initial application was extremely successful. The elimination of the wiper trips and hole problems considerably reduced drilling time for the section, and the casing took notably less time to run. This amounted to $960K savings compared to the field average and $1.69 million compared to the previous well drilled. In addition, the required DLS was achieved while increasing ROP by 58% compared to the field average.

The latest bi-center technology, in conjunction with Steerable motors, can deliver the required DLS and enlarged hole in demanding directional applications. This has proven to be an extremely cost-effective drilling system, saving nearly 10 days compared to the field offset.