bluuebunny/crossref_metadata_2025 huggingface dataset:
Well-Reservoir Coupling on the Numerical Simulation of Horizontal Wells in Gas Reservoirs
Authors: de Souza G. , Pires A. P. , de Abreu E.
Published: June 2014

Wellbore flow and its coupling with porous media has been an active field of research, mainly because wellbore hydraulics (especially in complex geometry wells, like horizontal or multilateral) plays an important role in the pressure and production profiles. An inherent difficulty is associated to the multiscale nature of the flow problem: the cell hosting the well is generally much larger than wellbore radius. As a consequence, average pressure in a cell is not a good approximation of the well pressure. Moreover, at the interface between well and reservoir there is a change in flow pattern, from porous media to pipe flow. In this work a well-reservoir coupling technique is developed and applied to the numerical simulation of horizontal wells in gas reservoirs. This model considers wellbore hydraulics and storage.

We consider the 3D single-phase isothermal flow of a compressible fluid in porous media and 1D single-phase isothermal flow of a compressible fluid in the wellbore. In both regions, mass conservation, momentum balance and real gas equation of state are the governing equations. Conservative forms are used for continuity and momentum. Flow continuity and pressure equilibrium are considered at the interface between well and reservoir. The nonlinear partial differential equations can be rewritten to allow the coupling of the pressure field between the porous media (reservoir) and the free media (well) by means of an implicit formulation for the finite difference method presented. A hybrid grid technique was applied to improve the description of the flow close to the wellbore. In addition, pressure in reservoir and wellbore are solved simultaneously, while velocities in wellbore are updated at every iterative step. An iterative method to solve numerically the resulting linear system for the primitive variable pressure was developed and it includes the wellbore/reservoir coupling into a finite difference numerical model.

This methodology is useful for the analysis of transient pressure and velocity behavior in both reservoir and wellbore including the change in flow pattern from porous media to pipe flow. Effects of permeability, gas specific gravity, formation damage and grid refinement are considered in different sensitivity analysis for several well-reservoir systems. Results for pressure and pressure derivative followed the expected behavior of the reservoir model chosen, both in early and long times. Effects of friction, convection and compressibility in wellbore hydraulics were successfully included in the numerical approach.
Downhole Testing Tools in Extreme Environments
Authors: Marcancola F. , Pontes T. , Adriano M.
Published: June 2014

Hydrocarbon exploration and production has ventured into deeper, more corrosive environments, requiring continual technology changes to address the challenges presented by the new environments into which the oil field has moved. Testing technology has had to redefine the operating envelopes for its tools in order to meet the new requirements. Not only high-pressure and high-temperature tools have been needed, but more debris-tolerant tools have been needed as well.

This paper discusses the application of downhole testing tools in formation evaluation jobs in extremely hostile environments; these include testing in such conditions as: Ultra-deep waterExtreme high-pressureExtreme high-temperatureDebris presence.

Ultra-deep-water wells are those that have at least 10,000 feet of water depth, and HP/HT well environments include those with bottomhole pressures above 10,000 psi and bottomhole temperatures above 300°F. When environments have bottomhole pressures above 15,000 psi and temperatures above 350°F, the wells are considered as extreme HP/HT.

Many testing operations have been severely challenged by these scenarios, as downhole tools available for standard projects only were capable of functioning efficiently to approximately 350°F and up to 10,000 psi of pressure. Now, special tools are available for conditions with temperatures of up to 450°F and 30,000 psi of hydrostatic pressure with maximum 15,000 psi of differential pressure. In addition, a new generation of more debris-tolerant tools is available.

The improved tools have enabled high-quality well testing to be performed safely, and when the tools are used in wells where solids problems are not anticipated, and unexpected debris does occur, they can avoid the unexpected rig time previously required to clean the well, further enhancing economic efficiency. Debris-tolerant tools also have allowed fracturing and acid operations to be performed with a test string, and with the same string, the well can be opened to a well-testing operation without compromising the functioning of the downhole tools.

Subsea equipment also has required adaptation to harsh environments. A major engineering/service company has now developed new subsea safety-tree equipment to be placed inside the BOP stack; with this new equipment, the fracturing operation and the drill-stem testing can be performed in the same trip, since the safety valve system has the capability to maintain integrity when functioning in heavy proppant, high pressure, and high pump-rate conditions. This capability saves time and adds economic value as well as increased safety features to the jobs.

This paper will discuss the innovations to testing technology as well as how formation evaluation jobs now can be performed satisfactorily in extremely hostile wells using the improved technologies. Best practice information that has now been gained concerning testing in extreme environments will also be presented.
Modifying the Zeta Potential of Formation Fines Utilizing Chemical Treatment: An Alternative to Sand Control to Increase Productivity: A Colombian Field Application
Authors: Jaimes M. G. , Valencia D. , Bahamon J. I. , Mendoza A. , Medina C.
Published: June 2014

Sand production in oil and gas wells is a complex problem that requires a multidisciplinary analysis to arrive at an optimal solution of the problem and thus increases the productivity of oil fields with problems of production of sand.

Many operators choose as first alternative, the exclusion of sand, avoiding doing a risk management, which ultimately provides lower index of productivity and in many cases convert the wells with sand problems in unproductive wells. Therefore always be a better option the sand management and take as a last option the sand exclusion, obviously framed within a technical and economic evaluation of alternatives.

In most cases when we refer to a chemical treatment for sand control, it tends to confuse with chemical consolidation treatments, however a different option, is the application of chemical treatments to modify the zeta potential of the formation fines that has been very successful.

Modifying The zeta potential to optimum range, provides a strengthened attraction between the particles to optimally align proppant type, sand particles, fines, etc., allowing the formation of conglomerates of proppant, sand, fines, etc., improving conductivity and control of fines migration.

This study focused on the evaluation in the laboratory of chemical treatment (compatibility, zeta potential and rock-fluid testing, etc.), mineralogical and granulometric analysis of sand and fines produced by wells with sanding problems, selection of wells and treatment zones, quantification of costs associated with sanding problems, technical and economic evaluation of the application of treatments in candidate wells, etc.

This paper presents the results of the laboratory evaluation of chemical treatment (satisfactory results in compatibility and modification of the zeta potential, permeability returns of over 80%, etc.) and implementation in the well Bonanza 39, located in the Basin of the Middle Magdalena Valley in Colombia, where dropped dramatically the frequency of interventions by sanding problems. Before chemical treatment, the well had a monthly intervention and after nine months of the treatment, has not required intervention, allowing increase productivity of the well.

Finally, the main findings, conclusions and recommendations obtained in this study are shown.
Design and Implementation of Software Tool to Select and Evaluate Sand Exclusion and Management Alternatives, During the Stages of Drilling, Completion and Production: A Colombian Field Application
Authors: Jaimes M. G. , Quintero Y. A. , Martin D. P. , Puentes M. S.
Published: June 2014

Sand production in oil and gas wells is a complex problem that requires a multidisciplinary analysis and the use of new methodologies and technologies to be solved, which often requires a combination of several of them to arrive at an optimal solution of the problem and thus increase the productivity of oil fields.

This comprehensive strategy must start from the drilling, continue in the completion and extends to the production stage. To implement this strategy, a methodology that includes the integration of field and laboratory data and is complemented by an assessment Geomechanics was developed.

In the industry there is no software that would make a comprehensive evaluation and analysis described in the previous methodology, therefore it is designed a tool for this purpose, which allows to automate and streamline the decision-making process (developing optimal workflows to reduce evaluation times per well to 50%) and create a friendly graphic environment for the user.

The tool includes the following modules: Production, completion and perforation. The Production module includes: selection of wells and quantification of costs associated with interventions by sanding problems, diagnostic charts for root cause analysis of the problem of sand production, characterization graphs of intervals with sand production (mineralogy and grain size), selection of alternatives for management and / or exclusion of sand, production modeling, technical and economic evaluation of selected alternatives, etc.. The completion and drilling module includes: Evaluation of tables of well logs and identification of sensitive areas to the sanding beginning from them, predictive modeling of sand production, conventional perforating optimal design, underbalance optimal, oriented perforating, etc.

As a case study, the application of software tools to assess the problem of sanding in the Lisama 166 Well in Colombia, is shown, in which the frequency of interventions was reduced in more than 100% and was increased the productivity, with recommendations implemented.

Finally, conclusions and recommendations obtained in this study are shown.
A Quantitative Approach to Analyze Fracture Area Loss in Shale Gas Reservoirs
Authors: Lawal H. , Abolo N. , Jackson G. , Sahai V. , Flores C. P.
Published: June 2014

Since the emergence of the shale gas multi-stage fracture stimulation era, many shale gas operators strive to contact as much reservoir volume from a single well as possible. In the process of optimizing production, completion practices tend to affect already producing wells. Altering the production of an existing well via the stimulation of an offset well, commonly referred to as a frac hit, has been a growing concern. The main driving force in producing any tight formation is the lumped parameter of fracture area and square root of reservoir permeability, Af√k. Often times during the producing life of a well, there is an apparent decrease or increase in the lumped parameter due to frac hits or refracs (a second fracturing or hydraulic stimulation at a later point in time of the same well), respectively. Previous work shows rate transient analysis as an option to evaluate the impact of frac hits or refracs on a well'sproductivity; however, a quantitative analysis will require a more detailed study that combines rate transient analysis with numerical modeling to tackle more complicated issues.

In this paper, we propose a performance based methodology to quantify the amount of area lost (frac hit) or gained (refrac) using analytical approaches that can subsequently be verified using numerical modeling to truly understand the change in stimulated area after the occurrence of a frac hit or a refrac. Several frac hit cases were examined in various shale gas plays such as the Haynesville and the Marcellus. The data from the field cases were used to quantify the impact of a frac hit. The stochastic modeling from rate transient analysis of future performance for the well was compared to the numerical solution. This approach is also valid for refracs to quantify the amount of area created based on well's performance and also pre-design stimulation techniques to study the area created during the refrac.

The approach will help operators to quickly compute the risk of performing refracs and selecting better spacing to control the occurrence of frac hits by quantifying the economical outcome. In addition, the approach might help to minimize the amount of time used in modeling, if required, by creating reasonable ranges for certain reservoir parameters. Lastly, the knowledge gained from this study will help to correlate the extent of potential fracture damage to reservoir properties (e.g. matrix permeability) and optimize future stimulation techniques prior to the stimulation job.
Successful Application of Water Injection to Increase Oil Recovery in Boscán Field
Authors: Méndez Alirio , Chacín Breidy , Balram Suman , Smith Bruce
Published: June 2014

Boscán field has an estimated 35 billion barrels of original oil in place (OOIP) of 10.5º API gravity asphaltic oil with a current production of just over 100, 000 BOPD. The current cumulative recovery factor is only approximately 5% OOIP after more than 70 years of production. Water flooding in such a heavy oil field was previously considered ineffective by the oil industry. However, water injection for pressure maintenance (WIPM) was successfully implemented in Boscán using a unique pattern configuration coupled with improved lifting capacity to take advantage of increased reservoir pressure.

A four-pattern inverted seven-spot pilot and a combination of pattern configuration and line drive arrangement pilots were implemented in the central portion of the field. The WIPM pilot performance data indicated local reservoir pressure increase with incremental secondary oil recovery. Based on the experience in the different pilot pattern configurations and ongoing reservoir modeling, the WIPM projects are being expanded with a pseudo 1-3-1 inverted 7-spot pattern configuration. In essence, an additional row of producers is being placed in-between pattern rows.

Successfully executing Water Injection Pressure Maintenance Projects within the Boscan field has already resulted in more than 75 million barrels of cumulative oil from secondary recovery with another 270 million barrels of oil in estimated recovey to the Economic Limit. Current Boscan production from WIPM areas is approximately 46, 000 BOPD, about 45 percent of the total field production. Future WIPM project expansions are planned in the East and Central areas of the field in the short and mid term in a 1-3-1 line drive configuration for which reservoir simulation forecasts were validated using existing production and analog forecasts, identifying an additional opportunity to recover 52 MMBO by 2026 (14 & 38 MMBO respectively) and 189 MMBO to the economic limit (59 & 130 MMBO respectively).

This paper demonstrates how the Boscan WIPM projects have successfully increased oil production and recovery in a mature heavy oil field by applying lessons learned, best practices and optimal reservoir simulation modeling.
An Environmentally Friendly Method to Control Halite Scale Deposition: Proven Case Histories from Latin America
Authors: Martinez R. , Parker W. L. , Hernandez E. , Misino C. , Ramírez I. E.
Published: June 2014

Various types of scaling are common causes of flow reduction associated with oil and gas production. Halite scaling is the most severe and often needs chemical treatments and physical intervention to put a well back in production. Producing wells with halite deposition often become uneconomic due to the severity of scaling and the short term between physical interventions.

This paper describes a physical, nonchemical, and environmental friendly method of controlling salt scale deposits to reduce nonproductive time required for maintenance on clogged production tubular. The proposed method proved cost efficient in allowing the production to flow without interruptions. By injecting a modulated electric signal on the tubular, the discussed method enhanced production by avoiding daily workover production interventions.

It was observed that this new method eliminated the need for daily interventions on the producing well and needed only a regular weekly visit to assess its working parameters. Based on the results from dozens of cases in Latin America, this method is proven to be efficient on controlling halite scale deposition. This method has been previously used on controlling carbonates and sulfates scales, but this is the first time worldwide it has been used to control halite scale on a producing well.

This paper will present the results from Mexico, where this environmentally friendly method proved very effective in controlling halite scale on wells where chemical and water injection had not provided a satisfactory solution. Prior to this treatment, production was severely impaired by tubular clogging with scale, and worsened by the amount of time spent on workover. The paper will present how this new method solved these issues with minimum impact to the client's installation.
Dynamic Model of Risk Assessment for Mature Fields
Authors: Cervantes Bravo R.J. , Huerta V.A.
Published: June 2014

Risk assessment is one of the crucial tasks to accurately account for estimating and booking technical recoverable volumes, as well as, valuating a petroleum asset. Usually these processes are affected by project maturity or non-technical issues, and usually embrace uncertainty due to lack of information and different criteria adopted by company and/or evaluators.

It is believed that deterministic cash flow methods are suitable and accurate to assess a project portfolio in mature oilfields. However, even in the very well known fields with strict surveillance plans, there is still uncertainty associated to volumes of recoverable hydrocarbons, oil & gas prices, capital investment estimations, government-take share among others input variables of economic models.

It is proposed a new approach for mature fields which includes a probabilistic model of reserves estimation (either applied for volumetric calculations or performance-data-based dynamic methods), an scenario matrix to account for the risk expressed in expectation curves, an estimation of the “pseudo-limiting” risk and value terms, and a decision tree to define a hierarchy of portfolio. Furthermore, it is proposed a methodology of life-cycle assessment and surveillance of reserves estimation by integrating of the “pseudo-limiting” risk and the ratio expected value to capital investment.

The application of this methodology in a mature oilfield, the Peruvian Block IX, show that proposed infill drilling campaign would require a better royalty share for the company (40% additional to the current rate), while the implementation of a pilot Water flooding project would need an improve by 50% in current royalty share.
First Production Results from Pimienta Oil Source Rock Reservoir, a Promising Shale: Case History from Burgos Basin, Mexico
Authors: Araujo O. , Garza D. , Garcia D. , Ortiz J. Ramon , Bailon L. , Valenzuela A.
Published: June 2014

Currently, three unconventional wells have been drilled and three are nearing completion that have been targeted in the Upper Jurassic Pimienta. This source rock formation is a candidate to be Mexico's first shale and could become the most productive shale zone in the country. There are several reasons for this success, which are discussed in this paper.

The primary subject well discussed was targeted in the oil window. Several horizontal completion techniques can be applied when stimulating these wells in northern Mexico; the plug and perforate (plug-and-perf) method is most commonly used at this time. During initial planning, this well was also going to use the plug-and-perf with conventional perforating and stages isolated using pump-down wireline plugs.

However, the particular well discussed here was instead completed by fracturing all the different stages using coiled tubing (CT)hydrajet perforating using a 2-in outside diameter (OD) string. This process employs jet dynamics principles and anew jetting tool design, creating clean, non-damaged perforation tunnels that help reduce fracture initiation pressure compared to conventional perforating. This process creates the most effective wellbore-to-reservoir connection possible, and then creates zonal isolation between stages using sand plugs.

After flowback, this well is considered the best shale producer in northern Mexico with gas and light oil production and has created new opportunities for drilling targeting the Upper Jurassic Pimienta shale, particularly in the oil window in the Burgos basin.

This is the first oil source rock reservoir horizontal well ever completed through the entire lateral section in conjunction with CT in Mexico.
New Drilling Campaign and New Technologies after 10 Years Without Drilling improve Performance in La Ceiba field
Authors: Tinoco Jose , Celis Criss , Lopez Luis , Rodriguez Ernesto , Coronel Gustavo , Lopez Jose , Bits Smith
Published: June 2014

The history of La Ceiba field began 10 years ago when six exploration wells were drilled to assess the potential of this field. The wells were drilled with several incidents of stuck pipe and the resulting necessary side-tracks to reach the final depth. Until last year no further attempt had been made to drill in this field.

With little information available from the exploration wells concerning drilling practices, the drilling campaign began with the goal of improving the previous performance, making the drilling of the complete wells faster and safer than in the previous drilling.

An engineering process was begun to find the best drilling solution for the field, starting with proven technologies such as positive displacement motors (PDM) and drill bits used in similar fields; however, this methods alone were not sufficient to meet the challenges of the field.

New technologies were used for the different challenges and applications through coordinated work between the drilling engineering departments of the different parties involved in this field and using all the information available in the drill bit selection database, including logs and stability data for the tools selected to drill each phase of the wells.

With evolution of the learning curve, drilling progressed from initial drilling involving 12 runs with time-consuming trips to surface to change either the drill bit or PDM, to drilling the same interval in 5 runs with the time on bottom increasing compare to previous experiences due to the introduction of tools more suitable to the environment requirements a rotary steerable systems (RSS) in combination with a specially designed drill bit.

Problems commonly faced in the upper sections were, the trajectory was not strictly followed, were solved with the introduction of the RSS in this section; use of the tool saved 10 days of rig time and set a bench mark for the field and similar wells in western Venezuela.

The development of this field shows that by solving the issues related to the well depth, temperature and constraints well design for these wells in western Venezuela, it will be possible to reach the oil reserves, at the same time decreasing the time spent in the drilling process.
Integrated Analysis To Identify and Prevent Formation Damage Caused by Completion Brines: A Colombian Field Application
Authors: Jaimes M. G. , Castillo R. D. , Villar A. , Escobar M. A. , Dorado R. , Acevedo N. P.
Published: June 2014

After workover jobs, many oil-producing wells have reduced their production, which is caused by formation damage created by using inadequate completion brine. The damage mechanism may be: 1) Block in the face of the formation, produced by the tendency to form emulsions between the oil of the well and the completion brine, 2) Production of inorganic scale in the porous medium during the contact of the formation water with the completion brine, 3) blockage by suspended solids present in the completion brines, 4) Increased bacterial activity in the wellbore vicinity, 5) rock-fluid incompatibility due to sensitivity of the formation minerals to the completion brine, caused by high ion exchange, causing swelling of clays and reduction of the permeability, 6) increase of the water relative permeability.

Given the above, this paper focuses on integrated analysis for selecting appropriate completion brines, based on an analysis of laboratory and production. Laboratory analysis includes: 1) Evaluation of fluid-fluid interactions, 2) physical- chemical analysis of produced water, 3) definition of Scale tendency of produced water and the mixture with control brine at the wellhead and at reservoir conditions through a simulation software, 4) filtration of the base fluid of the control brine and analysis SEM of solid waste found, 5) microbiological analysis of the base water of the completion brine, 6) compatibility brine-rock through test of core -flooding, 7) determination of critical salinity, The production analysis includes a diagnostic diagram with an assessment of the production history, fluid levels, events, extraction conditions, etc.

The integrated analysis was applied in 12 wells in the fields A, and G in Colombia, to determine the root cause of production losses, after workover. The Economic evaluation showed loss of productivity, quantified in more than one million dollars per well.

This paper presents the results of the evaluation in the wells G-11 and A-21, along with the conclusions and recommendations.
Physicochemical Evaluation of Formation Fluids and Stimulation Effluents In Situ: A Way To Ensure the Success of the Jobs
Authors: Jaimes M. G. , Villar A. , Escobar M. A. , Prada T. A.
Published: June 2014

The assurance and optimization of stimulation jobs has become very important due to the need to increase profitability in the crude oil production and ensure, as far as possible, the success of operations.

The chemical stimulation jobs consist in removal of formation damage and, in this regard, different types of fluids are designed in order to act on specific types of damage. However some oil wells commonly have several types of damage at the same time so, in the design phase it must be assured that each phase of the stimulation is carried out without interfering with the others. Otherwise there can be a number of undesirable consequences product of incompatibilities between stimulation fluids and reservoir fluids. Effluent characterization "in situ", during the stimulation jobs contain valuable information for directing the operation steps in order to prevent interaction of incompatible fluids and ensure the beginning and end of each treatment stage.

This article contains the results of chemical stimulation carried out in the well Sucumbios-5, where physicochemical evaluation of formation fluids and the effluents of stimulation treatments allowed a proper diagnosis on the development of each of the series of stimulation treatments evaluated.

Finally, the main findings and conclusions of the this study are shown.
Economic Evaluation of Steam and Solvent Injection for Heavy-Oil Recovery
Authors: Galvão E. R. , Rodrigues M. A. , Dutra T. V. , da Mata W.
Published: June 2014

In the last years, an alternative more and more used by the oil industry to increase the efficiency of Steamflooding has been the addition of solvents. In this work, a numerical study was done to analyze the influence of some operational parameters (steam injection rate, injected solvent volume and solvent type) on oil recovery. Simulations were performed in STARS, a CMG program. Using Contour Plots, it was possible to analyze the interactions between the operational parameters and to obtain the "optimum" regions for work. Comparisons between the models also were performed using several plots, such as fraction of oil recovered versus production time and fraction of oil recovered versus pore volume injected (PVI). To try to reduce the solvent volume required, were studied some cases of solvent injection interruption. To calculate the Net Present Value (NPV), were considered the sale price of the oil produced, the steam generation cost, the oil production cost and the purchase price of the solvents.

The applicability of the method was investigated in a heavy oil reservoir with properties similar to those found in Brazilian Potiguar Basin (200 m depth, porosity of 30%, vertical/horizontal permeabilities ratio of 10% and thickness around 35 m).

It was found that the solvents addition to the injected steam not only anticipated the arrival of the heated oil bank to the producer well, but also increased the oil recovery. Lower cold water equivalent volumes were required to achieve the same oil recoveries of the models that injected only steam. Furthermore, much of the injected solvent was produced with the oil from the reservoir, what contributed to the method economic viability in terms of NPV.

A significant fraction of the hydrocarbon reserves in the world is formed by heavy oils. The high initial productions achieved by models that use solvents have generally a significant impact on the operation economics. 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 emissions.
Static 3D Modeling at Boscàn Field: Overview of Data Integration and Model Construction Techniques
Authors: Shannon C. , Radecker K. , Waite M. W. , Munoz J. , Leon O. , Valera N. , Paz R. , Perez G. , Pina A.
Published: June 2014

A 12-million cell (150m × 150m × 1m), 3D geocellular model covering the Boscán field has been constructed. This presentation describes the results of this full-field reservoir model construction that has integrated core, well, seismic, pressure, and performance data.

In 2007, new 3D seismic was acquired over the south area of the field. The seismic was reprocessed with pre-existing 3D to enhance mapping of structural and stratigraphic features and provide better spatial control, improving on previous interpretations made with only well data and 2D seismic lines.

The re-processed 3D was used to re-evaluate horizon and fault mapping over the field. Using coherence-based methods, a study of regional tectonics for the area, and well correlation and performance data, we imaged a structural volume and different fault patterns originating from the main field-bounding Boscán fault. Though many of the faults do not have significant vertical offset, they appear to have pronounced effect on fluid movement and compartmentalization.

Electrofacies modeling tying core to logs was used to define trends and spatial probability of reservoir and rock properties across the field. In addition, seismic attribute data was qualitatively used to help guide reservoir variability between wells and define potential depositional features within a tidally-influenced fluvial-deltaic system.

Multi-point statistics (MPS) was applied to allow use of field-scale regional trends and shapes that mimic depositional features to ensure that spatial probability derived from seismic and well data could be honored. Multiple scenarios have been generated that capture the uncertainties in reservoir connectivity and associated distribution of rock quality parameters across the model area. Cells were populated with two-component lithofacies, volume of shale (VSH), effective porosity (PHIE), effective water saturation (SWE), and permeability (PERM) using a Petrophysical model developed from an extensive database of 1000+ wells.

The full field 3D geocellular model has been downscaled to several workable smaller sector models to help address specific past performance and future dynamic behavior. Production history matching and numerical fluid flow simulation is currently underway. The focus of the history matches, in part, is to shed light on fault compartmentalization, reservoir connectivity and quality distribution, and fluid movement associated with an encroaching aquifer and water injection for pressure maintenance through time.
Conceptual Study and Experimental Protocol for the Selection and Evaluation of Matrix Stimulation Treatments with Biocides, Focused on H2S and Corrosion Control in Producer Wells of Fields Undergoing Secondary Recovery
Authors: Jaimes M. G. , Villar A. , Escobar M. A. , Acevedo N. P.
Published: June 2014

One of the major problems in mature fields undergoing secondary recovery is the contamination with sulfate reducing bacterias (SRB) of the injection water system (fresh and/or production) and/or of the reservoir (natural or by drilling fluids, completion, stimulation, etc.), which causes formation damage and microbiological induced corrosion (MIC) in the injection-production system.

The problems mentioned above are present in various fields of the state oil company, Ecopetrol S.A, in Colombia and the situation is becoming more critical, not only because the decrease in productivity (formation damage, failure of the subsurface equipment and facilities of the Injection-Production system, etc.), but mainly because the risk of human mortalities (maintenance jobs, nearby houses, etc.).

In some producing wells, H2S concentrations have exceeded the lethal limits of 20 ppm and there are cases of producing wells with levels above 1000 ppm. Based on the above, a conceptual study was developed and an experimental protocol for the selection and evaluation of matrix stimulation treatments with biocides, focused on H2S and corrosion control in Producer Wells of Fields Undergoing Secondary Recovery as part of the comprehensive strategy to implement in the injection-reservoir-production system of the Cira - Infantas field in Colombia. This study included the following stages: State of the art to define main Bactericides-sporicidal.State of the art to define matrix stimulation treatments to H2S and corrosion control, removal of biomass (biofilm) and iron sulfide, etc. in producers wells.Deactivation of bactericides and sporicides with gases and minerals of the formation (H2S, Clay, etc.) and the environmental Impact.Alternatives Assessment Matrix.Formation damage by growth of sulfate-reducing bacteria.Experimental protocol and results of selection and evaluation of biocides and stimulation treatments.

Finally, the main findings, conclusions and recommendations obtained in this study are shown.
3D Seismic Interpretation Techniques for Detecting Oilfield Exploration Locations
Authors: Carrasco J. , Garcia R.
Published: June 2014

New automated volumetric seismic interpretation techniques have been developed to help reduce cycle times for exploration and reservoir characterization. At the end of the last century, the introduction of seismic interpretation methodologies assisted by computer systems facilitated the development of classical criteria and geological methods for defining the shape of hydrocarbon reservoirs. This latest development allows for the definition of the structural dimensions of the reservoir to be determined without requiring the interpretation of the horizons in seismic sections. This automation of seismic interpretation does not replace the specialist's experience but contributes to the conceptualization of the reservoir structure in less time.

These techniques are designed to determine the volume of the reservoir structure by using seismic geobodies, which define the area and thickness of the reservoir structure. The geobodies are extracted from a window of seismic amplitudes with dynamic ranges using an opacity filter to capture the strongest seismic reflectors, which can be negative or positive, depending on the sedimentary environment. Formation tops from wells are used to correlate the multi-Z components of the geobodies.

The interpretation of the fault system is accomplished by using structural and seismic attributes (including similarity, semblance, maximum curvature, and amplitude volumes) that highlight the lateral differences of the seismic trace properties (amplitude, frequency, and phase). These discontinuities can conform to alignments that reveal fault planes and fracture patterns. The combination of structural seismic attributes with the original seismic cube (no filter and no gain) provides elements that define the main reservoir structural alignments. The interpretation of faults defined by structural patterns is performed without rescaling so as not to lose the three-dimensional (3D) perspective of the fault plane.

Velocity model calibration is important for performing the time-depth conversion of seismic interpretation elements (horizon, fault planes, and seismic volumes). The calculations of the probable seismic attribute hydrocarbon indicators in the petroleum system analysis allow potential areas of hydrocarbon entrapment to be identified by structural and stratigraphic contacts.

This methodology has been successfully applied in a conventional reservoir in Mexico's southern region.
Evaluation of Completion With Method Unconventional Pilot in the Field Motatan
Authors: Barrios J. L , Diaz G. , Rosales L.
Published: June 2014

In the field Motatán 55% of active wells are producing with Gas Lift, 35% occur with BES and the rest with mechanical pumping, but in recent years the compressor plants worked poorly due to the obsolescence of such. The application of conventional mechanical pump is low, because the well is deep and this restricts the settlement of the pump. This has motivated evaluate alternatives leading to a decrease deferred production wells.

This is the case study of the well MOT-67 block located in the largest reserve of crude Motatán area, specifically in western Venezuela. The last three teams Pumping electrosumergible not last more than 3 months since, had binding by the presence of carbonates and asphaltenes, the anomalies were observed in the teardown conducted surface pumps. It is well to note that this brings with BES 920 bbpd system with 32% AyS.

The team integrated of Engineers Reservoir and Optimization analyzed other artificial lift methods that may be feasible for MOT-67 well, including: gas lift and mechanical pumping. During the analysis it was determined to go with the option of gas injection is not have sufficient volume to ensure the reliability of the LAG, in our simulation the well required a minimum consumption of 1.5 MMPCNPD, and conventional mechanical pumping system that could handle generate a maximum load of 50,000 Lbs, this would limit production under this method, due to the setting depth of the pump (9000 feet), and that the unit would work surface to the maximum limit, risking the collapse of the structure, fatigue and wear of the spokes.

Due to the above stated relative to the change in method of artificial lift MOT-67 well, the next question is formulated, Is it possible to combine the Mechanical Pump System with gas lift?

Respective designs were conducted to evaluate the method of mechanical pumping + LAG with special simulators for each production method, proving beneficial.
Effect of Extending the Radial Superposition Function to Other Flow Regimes
Authors: Escobar Freddy Humberto , Alzate Hernan Dario , Moreno-Collazos Leonardo
Published: June 2014

Nowadays, the oil industry is focusing its effort and interest on gas shale reservoirs. Gas shale wells are normally tested by recording the flow rate values under constant pressure conditions. Therefore, time superposition is required in order to conduct transient-rate analysis which normally uses the radial solution of the constant-rate diffusivity equation. This superposition function is also applied indiscriminately to other flow regimes without considering the possibility of an existing error. The literature only reports a case where this situation is dealt with. However, the analysis is performed using curve-decline matching.

This study presents the analysis of the effects generated by extending the superposition time function generated with the constant-rate radial solution of the diffusivity equation to other well-known flow regimes. The work consists of performing simulations for the following scenarios: variable rate under constant well-flowing pressure, uncontrolled changes in flow rate, isochronal uncontrolled changes in flow rate, isochronal increasingly changes in flow rate and isochronal decreasingly changes in flow rate. Superposition time functions were generated for each scenario to compare each flow regime (linear, bilinear, elliptical, spherical and pseudosteady state) superposition function to the radial flow superposition function.

In general terms, it was found that the generated effects of using the radial time superposition function are negligible. Even, good values of the average reservoir pressure with the radial flow superposition function were obtained. However, it was noted a notorious deviation of the linear and bilinear flow regime tendencies for hydraulically-fractured wells. This leads to erroneous estimation of the fracture parameters.
Optimization of Multiphase Pumping Stations Based on Reliability Analysis and Monitoring of Process Conditions at Huyapari Field - PetroPiar, Orinoco Belt
Authors: Mendoza O. Moreno , Johnson S. Rivas , Sierra J. Díaz , Gil J.
Published: June 2014

The Huyapari field currently produces 160,000 BPD of 8.5 ° API extra heavy oil in cold production method. Blending naphtha of up to 60° API to obtain finally diluted crude of about 15.2° API.

Twin-screw multiphase pumps (MPP) are responsible for transporting the fluids from the well pads to the "Centro Operacional Bare" (COB), where the produced fluids are treated. The production is in charge of 21 pumps geographically distributed in 10 multiphase pumping stations, strategically located in the field.

In order to keep surface pressures controlled as low as possible and therefore contribute to achieve production commitments and business plan in the JV PetroPiar, an integral monitoring methodology has been designed. This work helps to evaluate and provide real-time recommendations for reaching optimum operating conditions contributing to maximize daily production as well as identifying opportunities for reliability improvements.

This monitoring program is linked to a reliability study conducted on a quarterly basis, which contributes to the execution of the work plans of the departments supporting the operation, with focus on reducing Lost Production Opportunity (LPO) with grater effectiveness.

The continuous evaluation and optimization of the performance of the MPP stations in real time according to operational changes (surface pressure, diluent injection rates, diluent quality, water cuts, and gas production rates, among others) allow for improving the reliability of this equipment and help to meet the production plan, which is currently over 96%.

This work also describes the results from the failure analysis conducted in the last three years to identify the main factors affecting the LPO. Additionally, the methodology to continue with the operational performance of each MPP station and its influence in the production system of the whole field is included.

The results of this work have shown a reduction of the LPO from 244 BPD in 2012 to 100 BPD in 2013 (annual average, reduction of 59 %). Other benefits are represented in the more effective contribution to the management of the resources for the equipment maintenance. The identification of opportunities for improvement based on root cause analysis has allowed for influencing on all the departments involved for accurate decision making with regards to the surface facilities operation in the field.
Development of a Fully Coupled Two-phase Flow Based Capacitance Resistance Model CRM
Authors: Cao Fei , Luo Haishan , Lake Larry W.
Published: June 2014

The capacitance resistance model (CRM) has become a popular complement to real time reservoir analysis and improved oil recovery in water and CO2 floods. However, the current CRM model is based on a material balance of the total fluid and only the pressure propagation equation is considered. Saturation changes are also important, especially when the water cut is small. To overcome this limitation, this paper proposes a coupled CRM model based on two-phase flow by incorporating an oil material balance and fractional flow theories.

In the coupled CRM model, we construct material balances on both total fluid and oil. Pressure and saturation equations are updated at each time step to account for changes of total mobility. By semi-analytically coupling the pressure and saturation in a producer-based control volume and using constrained multivariate nonlinear regression, the new coupled model can quantify the inter-well connection as well as the oil saturation. As a result, the coupled CRM model can be applied to the whole time frame of water and gas floods, not limited to late time (large water cut) cases as was the current CRM model.

This new CRM model is validated in heterogeneous synthetic fields using a conventional reservoir simulator. Case studies show that the saturation profile from the coupled CRM model matches very well with the simulation results. The connectivities obtained from the coupled CRM model correspond well with the field geology and the time constant for each producer is also changing reasonably with the total mobility. Validation of both total production and oil production rates showed that relative errors are very small. With estimated parameters from a waterflood, the model found an optimal injection strategy to maximize the field total oil production.

By incorporating the saturation variations to model two-phase flow, the coupled CRM model successfully overcomes the limitation of the previous version. It is able to extend the CRM model from mature water floods to immature water floods, which makes the CRM model more adaptable to different field cases. The coupled CRM model also improves the quality of the prediction of the oil rate significantly, especially for immature water floods. This work can lead to a more informed workflow of optimizing injection scheme, and serve the goal of improving ultimate oil recovery.