bluuebunny/crossref_metadata_2025 huggingface dataset:
Using Openhole Horizontal Completion Technology to More Efficiently Complete Vertical Wells
Authors: Seale R. , Athans J.
Published: December 2007

Horizontal completion technology has progressed dramatically over the last six years, with the latest technical barriers being eclipsed with open hole technology. These completions have allowed multiple zones to be fractured while mechanically isolating each zone. The efficiencies and benefits of utilizing open hole horizontal completion technology has been well documented. From the enhanced production witnessed using open hole completion with mechanical isolation, to the operational benefits of multiple fracturing operations being pumped in one continuous operation equating to time savings, more efficient fracs, faster cleanup and less safety hazards. Conventional methods of cementing a liner in place, perforating, fracturing and repeating the process for the number of stages required can be very time consuming with the added expense of removing the frac plugs with coiled tubing (CT) after the operations have been completed.

The enabling technology that has been used successfully over the last six years for multi-stage fracturing in open hole horizontal wells has been successfully applied to vertical wells. This paper will detail the benefits of using open hole multi-stage fracturing technology with mechanical isolation in vertical wells. In some aspects this may seem a simple transition, however, there are many operational considerations that must be evaluated in many vertical applications that might otherwise not be factored into a horizontal completion. These operational considerations will be thoroughly outlined, including case histories where this technology has been successfully applied.
Optimizing Producing Wells with Solid Expandable Tubular Technology
Authors: Perez-Roca Eduardo
Published: December 2007

A practical field restoration and rejuvenation project requires an economically efficient and technically astute plan. Using existing infrastructure allows operators to build a sound value proposition by capitalizing on previous investments. Enabling technology, such as solid expandable tubulars, makes the proposition even more attractive by further minimizing project costs. Solid expandable tubulars provide a technology that offers variable solutions without sacrificing hole size or compromising budgets.

Solid expandable tubulars have built a legacy as a viable and practical workover technology, based on over 660 installations. As acceptance and use of expandable systems increases, so do the application venues where they can be used to facilitate well remediation. Expandable systems repair and/or reinforce existing casing while minimizing loss of hole size, which enables use of the same completion. The systems have also provided the impetus for operations that result in compelling returns on production enhancement projects for old and new wells and fields.

This paper will explain how solid expandable tubular systems are used to repair and remediate wells that developed casing integrity problems and wells that experienced flow-constrained problems. Case histories will be used to illustrate how the technology was used to mitigate production problems and retain or improve value. In addition, this paper will discuss the economic implications of using this revolutionary technology.
Fluid Distribution Model for Structurally Complex Reservoirs in El Carito-Mulata and Santa Bárbara Fields, Venezuela
Authors: Carpio G. , Rodríguez F. , Khan K. , Contreras A. , Campos L. , Idrogo C. , Labastidas E.
Published: December 2007

El Carito-Mulata and Santa Bárbara fields are located in Eastern Venezuela in the Maturín sub basin and cover almost 300 km2. The asymmetrical anticline of the reservoirs is the result of different tectonic regimes alternating compressive and extensive periods from the late Cretaceous to the Middle Miocene. The fields are producing 240,000 STB/D and their OOIP is estimated to be around 6.5 MMMSTB. The variation of the vertical fluid distribution is predominant. There is a light oil (condensate) at the top of the structure, black oil at the base and free water at different levels in the reservoirs. This vertical fluid distribution is not well represented in the dynamic simulation model, which increases the uncertainty on any prediction or elaboration of the production plan.

The main objectives of this study are the determination of the original fluid contacts and the construction of a fluid model, which takes into account the free water presented in the reservoirs. This model can also define the vertical and lateral extension of the oil fields, indispensable for the reserves estimation.

The integration of the different kinds of static and dynamic information of 149 wells was necessary in order to obtain a well-supported fluid distribution model.

The analysis of the large number of data allowed defining the geometry of the Tar mat (asphaltene content > 20%), which is folded/faulted according to the structure and considered as a sealed layer in reservoir conditions, with thicknesses ranging between 300 and 500 feet. The irregular Tar mat surface limits the reservoirs and controls the free water levels in the fields. This new fluid distribution model was included at the numerical simulation model matching all the wells information about water or type of oil that has been produced or tested.
Quantitative Mechanism for Permeability Reduction by Small Water Saturation in Tight Gas Sandstones
Authors: Motealleh Siyavash , Bryant Steven L.
Published: December 2007

In tight gas sandstone the productivity of a well is sometimes quite different from that of a nearby well. Several mechanisms for this observation have been advanced. Of interest in this paper is the possibility that a small change in water saturation can change the gas phase permeability significantly in rocks with small porosity and very small permeability.

We quantify the effect of small saturations of the wetting phase on nonwetting phase relative permeability by modeling the geometry of the wetting phase. We also show how a porosity-reducing process relevant in tight gas sandstones magnifies this effect. The basis for these observations is a model of the grain-scale geometry of low-porosity sandstones. The model is built from a dense random packing of spheres modified geometrically to simulate quartz overgrowth cementation. To compute phase geometry and permeability we use a physically representative network model extracted from the model rock. At small saturations (at or near the drainage endpoint) the wetting phase exists largely in the form of pendular rings held at grain contacts. Pore throats correspond to the constriction between groups of three grains, each pair of which can be in contact. Thus the existence of these pendular rings decreases the void area available for flowing non-wetting phase. Because the hydraulic conductance of the throat varies with the square of the void area, the effect on permeability is disproportionate to the volume occupied by the rings.

Convention holds that connate water has little effect on oil or gas permeability because it occupies the smaller pores. Comparing predictions for unconsolidated model rocks with those for cemented model rocks allows one to reconcile this view with the sensitivity reported in the field and the laboratory.
Stimulation of Bypassed Pay Zones in Existing Wellbores
Authors: Moreno J. W. , Engler T. W.
Published: December 2007

A significant portion of the U.S. gas resources is located in low-permeability, bypassed pay zones, within multilayered sandstone-shale sequences. Acquiring these resources leads to operational and design difficulties in stimulation, particularly if the target zone is bounded above and below by existing producing zones. The objective of this work was to evaluate the impact of adjacent, existing producing zones on the stimulation design and hence production performance of the bypassed payzone.

To investigate this problem, a 3D planar, hydraulic fracture propagation model was constructed and superimposed on a 3D flow model. The physical model was comprised of three layers, the top and bottom representing previously stimulated and producing layers, and the middle layer the target or bypassed layer. The impact of lithology, fracture length and total stress variations over time on the fracture conductivity, fracture efficiency and average reservoir pressure were investigated.

Evidence of pressure depletion of the target layer was observed due to production of the upper and lower layers. The degree of depletion is dependent on the fracture length and lithology of all of the layers. That is, the ability to propagate a fracture in the target layer was a strong function of the shale content and to a lesser extent, on the hydraulic fracture length of the bounding layers. Increased shale content in the target as well as the bounding layers resulted in a decrease in fracture conductivity of the target layer. However, an increase in fracture length did not necessarily result in a decrease in fracture conductivity of the target layer.

The study includes examples of stimulating the Menefee formation in the San Juan basin.
Improved Permeability Prediction Relations for Low-Permeability Sands
Authors: Florence F. A. , Rushing J. A. , Newsham K. E. , Blasingame T. A.
Published: December 2007

This work addresses the problem of estimating Klinkenberg-corrected permeability from single-point, steady-state measurements on samples from low permeability sands. The "original" problem of predicting the corrected or "liquid equivalent" permeability (i.e., referred to as the Klinkenberg-corrected permeability) has been under investigation since the early 1940s — in particular, using the application of "gas slippage" theory to petrophysics by Klinkenberg.1

In the first part of our work, the applicability of the Jones-Owens4 and Sampath-Keighin5 correlations for estimating the Klinkenberg-corrected (absolute) permeability from singlepoint, steady-state measurements is investigated. We also provide an update to these correlations using modern petrophysical data.

In the second part of our work, we propose and validate a new "microflow" model for the evaluation of an equivalent liquid permeability from gas flow measurements. This work is based on a more detailed application of similar concepts employed by Klinkenberg. In fact, we can obtain the Klinkenberg result as an approximate form of our result. Our theoretical "microflow" result is given as a rational polynomial in terms of the Knudsen number (the ratio of the mean free path of the gas molecules to the characteristic flow length (typically the radius of the capillary)).

The following contributions are derived from this work:

Validation and extension of the correlations proposed by Jones-Owens and Sampath-Keighin for low permeability samples. Development and validation of a new "microflow" model which correctly represents gas flow in low permeability core samples. This model is also applied as a correlation for prediction of the equivalent liquid permeability in much the same fashion as the Klinkenberg model, although our new model is substantially more theoretical (and robust) as compared to the Klinkenberg correction model.
Unconventional Gas Recovery and Subsurface Water Mapping: A Relationship of Untapped Potential
Authors: Montgomery J. , Rollins Paul
Published: December 2007

Processes of unconventional gas recovery frequently have to deal with water issues. For the purposes of protecting both productivity and the environment, well operators must monitor the relationship between their extraction activity and the surrounding groundwater network. This is especially true in the case of hydraulic fracturing, when new fractures may facilitate communication with the local aqueous system. Well operators therefore have a vested interest in more effective methods for determining the size, shape, and flow patterns of subsurface water features.

This paper introduces a new water imaging technology and considers its implications for unconventional gas recovery. The technology uses Controlled Source-Frequency Domain Magnetics (CS-FDM) to map and model underground water features. Its rapid and minimally invasive procedure has now been effectively implemented in a variety of ground-water projects. The results of those projects suggest that it possesses significant potential value for the natural gas industry. This paper will serve as the beginning of an overdue conversation about its merits and possibilities in that field.

One of the most relevant applications of this technology has come in the area of improved oil recovery. By applying the technology's water-mapping capabilities to oil reservoirs that have been flooded with water or steam, field operators have been able to quickly and accurately characterize the features of those reservoirs and thus develop more effective stimulation strategies. At this stage in the technology's development, it is time to ask whether it can serve a similar function in unconventional gas production. That is, can a tight-gas feature or coal bed which has been filled with fracturing fluid, take advantage of CS-FDM's capacity for reservoir characterization? The answer to that question could have major implications for production well placement, facilitating increased output and minimizing environmental impact, and also for evaluating hydraulic fractures
Development of an Improved Methodology to Assess Potential Unconventional Gas Resources
Authors: Salazar J. , McVay D. A. , Lee W. J.
Published: December 2007

Considering the important role played today by unconventional gas resources in North America and their enormous potential for the future around the world, it is vital to both policy makers and industry that the volumes of these resources and the impact of technology on these resources be assessed. To provide for optimal decision making regarding energy policy, research funding, and resource development, it is necessary to reliably quantify the uncertainty in these resource assessments.

Since the 1970's, studies to assess potential unconventional gas resources have been conducted by various private and governmental agencies, the most rigorous by the United States Geological Survey (USGS). The USGS employed a cell-based, probabilistic methodology, which incorporated simplifying assumptions to derive analytical equations to calculate distributions of the resources assessed. USGS assessments have generally produced distributions for potential unconventional gas resources that are unrealistically narrow for what are essentially undiscovered, untested resources.

In this paper we present an improved methodology to assess potential unconventional gas resources. Our methodology is a stochastic approach that includes Monte Carlo simulation and correlation between input variables. Application of the improved methodology to assessment of potential unconventional gas resources in the Uinta-Piceance province of Utah and Colorado with the USGS data validates the means and standard deviations of distributions produced by the USGS methodology, but reveals that these distributions are not right skewed, as expected for a natural resource. Our investigation indicates that the unrealistic shape and width of the gas resource distributions are not caused by lack of correlation between input variables, but rather the use of narrow triangular input parameter distributions.

The stochastic methodology proposed here is more versatile and robust than the USGS analytic methodology. Adoption of the methodology, along with a careful examination and revision of input distributions, will allow a more realistic assessment of the uncertainty surrounding potential unconventional gas resources. Reliable assessments of uncertainty are important in the decision-making process for exploration and development of potential unconventional gas resources, and will be valuable to both government and industry in the timely development of unconventional gas resources for the public benefit.
Recent Acid-Fracturing Practices on Strawn Formation in Terrell County, Texas
Authors: Zaeff G. , Sievert C. , Bustos O. , Galt A. , Stief D. , Temple L. , Rodriguez V.
Published: December 2007

The goal of an acid fracture treatment is to generate a highly conductive pathway of sufficient length from the reservoir to the wellbore. Depth of penetration of live acid is the critical factor in determining the success of an acid-fracturing treatment. Depth of penetration is controlled by the acid reaction rate, leakoff, and stimulation rate. Acid reaction rate is a function of several factors, the most important of which is the reservoir temperature. Yet another concern, in acid fracturing in long carbonate intervals, is attaining the necessary diversion to ensure that multiple sets of perforations are adequately stimulated.

Because of their high solubility and highly fractured/vugular nature, carbonate reservoirs in the Permian Basin show excellent response to acid fracturing treatments. However, inadequate diversion can leave substantial portions of the reservoir untreated. Different acid systems have been developed to counter the problems in acid fracture stimulations. Chemical and mechanical means of diversion have been used with varying degrees of success. Likewise, there have been many attempts made in retarding the reaction rates of hydrochloric acids in high temperature environments. Recently, there has been a large number of highly successful acid fracture treatments in the Permian Basin incorporating a combination of new polymer-free self-diverting acid combined with an existing acid-oil emulsion technology.

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This paper will discuss a combination of technologies, which has recently been applied successfully in the Strawn formation in Terrell County, Texas. It will also focus on what is being done to mitigate the affect of high temperature on hydrochloric acid's reaction rate. It will further develop improvements in reservoir characterization and pay zone determination, which has been improved by the utilization of resistivity imaging logs. Some examples presented contain information from radioactive tracers and production logs, which are fundamental to understanding how good zonal coverage was achieved using different techniques. Additionally production analysis has been conducted to determine the effective fracture half-length and etched conductivity. Finally, a relative comparison between the old and new completion methodologies is made taking into account that the new completion practices have only been applied in full combination since 2004.
A Novel Foamer for Deliquification of Condensate-Loaded Wells
Authors: Orta D. , Ramanchandran S. , Yang J. , Fosdick M. , Salma T. , Long J. , Blanchard J. , Allcorn A. , Atkins C. , Salinas O.
Published: December 2007

Continuous increase in worldwide brown-field activity and overall depletion of current gas fields has renewed focus on maximizing gas production from existing wells. In most gas wells, water and/or condensate is produced along with gas. In mature gas wells, decreasing formation pressures and gas velocities gradually cause the wells to become "loaded" with liquids. A method commonly used to deliquify these wells is through the application of chemical "foamers". However, these traditional foamers tend to be ineffective as the condensate-to-water ratio increases. This paper describes the performance of a novel foamer specifically designed to unload condensate from wells. This foamer helped unload a gas well that produced condensate via intermittent production at 2:1 condensate-to-water ratio. Parameters for well selection are described, as well as operational processes to maximize continous production. As a result of this treatment, the daily average gas production rate increased significantly and shifted the daily on:off production cycle from 1:1 to 11:1. This minimized well down time and increased the overall daily production averages by 60 percent.
Application of Indirect Fracturing for Efficient Stimulation of Coalbed Methane
Authors: Olsen T. N. , Bratton T. R. , Donald A. , Koepsell R. , Tanner K.
Published: December 2007

Propped hydraulic fracture stimulation has been one of the primary completion methods for coalbed methane wellbores for more than twenty years. However direct fracturing of coal seams has been notoriously inefficient. High fracture pressures in coal seams, coal cleating and natural fractures can lead to shear slippage and inefficient non-planar fracturing which significantly underperforms the stimulation potential compared to conventional clastic rock fracture stimulation. In 2003 the concept of indirect fracturing was introduced to significantly increase Coalbed methane (CBM) fracturing efficiency by initiating fractures in lower stress clastic rock adjacent to coal seams and allowing these induced fractures to connect and grow into the coal seams. This paper presents several examples of the application of indirect fracturing for the stimulation of coal seams in the Rockies. This paper evaluates production results, fracture pressure analysis, as well as micro seismic results and frac tracer analysis for quantifying the effectiveness of indirect fracturing for the stimulation of CBM reservoirs. From this data we present guidelines for when and where indirect fracturing is applicable and just as important, where indirect fracturing is not appropriate.
Optimization of a Scale Treatment in the Uinta Basin—A Case History
Authors: Maschio Leonardo , Cherian Bilu , Lungwitz Bernhard , Tyndall Michael , Garcia Marieliz , Longwell John
Published: December 2007

The precipitation and accumulation of scale deposits is a major concern for production companies in the Uinta Basin. Since 2003, conventional hydraulic fracturing treatments with scale inhibitor pumped simultaneously as an additive have been offered to this region. This service proved to be very effective in the Permian Basin using borate crosslinked fracturing treatments (with scale inhibitor concentrations as low as 5 gal/mgal). However, these design criteria and formulation of the scale treatments had to be changed significantly to be effective in the typical Uinta Basin gas well environment: low permeability (<0.1 md), multi-layered, commingled gas reservoirs. Typically, a well completed and placed on production without any scale inhibitor in the Uinta Basin may show signs of scale buildup in as little as 30 days. The effects of the scale accumulation can be seen everywhere from an exaggerated production decline to scale deposition on production equipment. This paper outlines the learning procedure and present designs, testing and monitoring results from scale treatments together with a case study from the Uinta Basin.
Analytical Evaluation of Gas/Condensate Skin in Hydraulically Fractured Wells
Authors: Ravari Reza Rostami , Wattenbarger Robert A. , Doust Alireza Rezaei , Amani Mahmood
Published: December 2007

The work in this paper is a result of a problem encountered in producing a low permeability formation from a hydraulically fractured well in South Texas. The well was producing from a tight gas condensate reservoir and there was concern about damaging the well if the wellbore pressure fell below the dew point. However, it turned out that condensate damage was not a problem. Lower wellbore pressures only resulted in higher rates.

This study employs analytical methods to evaluate production impairment by use of fracture face skin concept, sff, which is a permeability reduction normal to the face of the fracture. Due to very tight formation and presence of infinite conductivity fracture which propagates the entire drainage boundary of the well, the flow pattern from the formation into the hydraulic fracture is linear. The reservoir was modeled by a synthetic single phase linear model and the simulation results were compared to analytical solutions. In order to investigate if the analytical equations properly quantify the production impairment, at this stage the single phase fluid model was used to ignore productivity decrease due to condensate damage.

Single-phase damage analysis shows that for a linear reservoir producing at constant rate conditions, sff is additive to the analytical solutions. It also shows that sff calculated in transient and pss periods are identical to that calculated by using Cinco and Samaniego equation.

The same analysis for the constant pwf case assuming that the sff is additive to the analytical solutions shows that the calculated skin in transient period changes with time.
Material Balance of Fractured Fields–Double Reservoir Method
Authors: da Costa Peron José Renato
Published: December 2007

The conventional material balance methodology for fractured fields considers a single system with double porosity, compressibility, saturations, etc.

The method proposed in this paper employs a double reservoir concept.
Challenges and Solutions in Hydraulic Fracture Jobs in Land Fields in Alagoas, Brazil
Authors: Payão Edson , Gomes Luiz
Published: December 2007

In this paper, we will describe techniques used to overcome the problems faced on the hydraulic fracturing jobs during the oil-to-gas conversion campaign in the Pilar field, Brazil.

The increasing demand for clean-burning natural gas in the Northeast of Brazil is fueled by the region‘s industrial growth over the recent years, and represents the main drive for the oil-to-gas conversion campaign witnessed in the wells previously producing at marginal oil rates from the Coqueiro Seco formation in the Pilar field. These old wells are now producing gas from the 3000 meters deep Penedo sandstone formations. One of the main steps to meet the goals for natural gas output in the Pilar field was the hydraulic fracturing campaign in the deep Penedo formation. The treatment design and execution process to create these fractures was quite distinct from the normal jobs aiming at increasing the oil productivity in wells producing from the shallow Coqueiro Seco formation.

The Barra de Itiúba gas-bearing formation in the Furado, São Miguel dos Campos and Cidade de São Miguel dos Campos fields was also included, to a lesser extent, in the stimulation campaign aiming at the increase in natural gas production.

This paper describes the completion strategy for the old wells converted from oil to gas producers, highlighting the problems faced and overcome during the hydraulic fracturing campaign. In deviated wells crossing the deep Penedo reservoir, the risk of multiple fractures and influence of tortuosity have been diminished through corrective techniques, unique for each one of the existing wells. In the early hydraulic fracture treatments performed in the Pilar field, premature screen-outs were commonplace, disencouraging the use of the technique. The need to produce gas brought new ideas to the battlefield, and their implementation led to results beyond expectations.
Produced Water Reinjection in Mature Field With High Water Cut
Authors: Navarro William , Muro Leytzher
Published: December 2007

This paper describes the current development and acquired experiences obtained in a produced water re-injection (PWRI) project in high WOR mature oilfields located in the Amazon rainforest in Peru.

Pluspetrol operates Block 8 and Block 1-AB, both located in the Northern part of Marañon foreland basin in Peruvian jungle. Twenty-four oilfields had been discovered between 1971 and 1980 and they have been producing since 1978. Currently 174 wells are producing from 17 fields with average water cut as high as 95%.

Productive reservoirs are composed of fluvial, estuarine and shallow marine sandstones from Vivian and Chonta formations of Cretaceous age. Main reservoirs have lateral continuity with porosity between 12 and 24% and permeability between 50 md and 5000 md.

The production mechanisms are bottom and edge water drive. It is observed that water cut in these reservoirs shows a very sharp increase to values above 90% in early stages of exploitation due to mobility differences between viscous oil and formation water.

In a first stage a series of injectivity test were performed in both shallow and deep reservoirs. These tests showed a better injectivity in deep reservoirs like Vivian and Pozo.

At the beginning injection rates were under matrix conditions but later with the aid of thermal effect and high injection rates, injection under fracturing conditions was achieved allowing us to increase injectivity index and thus reducing the number of required water disposal wells.
Artificial-Lift Systems Overview and Evolution in a Mature Basin: Case Study of Golfo San Jorge
Authors: Hirschfeldt Marcelo , Martinez Paulino , Distel Fernando
Published: December 2007

The Golfo San Jorge basin, located in the central Patagonia, is the oldest productive basin of Argentina, where the first economic discovery took place in 1907, in Comodoro Rivadavia.

With 11,680 active oil wells, is the first oil producer basin of Argentina producing 258,549 bpd of oil and 2.56 MM bpd of water.

The main characteristics of the basin are: –Faults and sand stone lens–HWOR–Increasing fluid flow rate per well–Complex fluids: corrosive, heavy oil, gas, sand and scale–Multiphase fluids–Multilayer reservoir: from 1.800 to 9000 feet

In this context, the selection, operation and optimization of the different Artificial Lift Systems (ALS) plays an important role for following the development of the basin.

This paper describes the best practices, experiences and trends, using ALS as Progressing Cavity Pump(PCP), Electric Submersible Pump(ESP) and Sucker Rod Pumping(SRP); and a basic description about Gas Lift, Plunger Lift and Hydraulic jet Pumping experiences.

Information as pump depth, flow rates, operational conditions, surface and sub-surface installations description, technical limits, failures statistic and new technologies from more than 9,000 active wells from different oilfields were collected and analyzed.

As result of this overview, an ALS reference guide was completed with parameters and benchmarking indicators; and some important conclusions appear.

Complementary information will be presented in the Appendix (Fig-A1, A2, Table-A1, etc)
Speeding Up Oil Recovery by Infill Drilling Prior to Considering Implementation of a Full-Field WAG Process–El Furrial Field, Venezuela
Authors: Leonardo Lopez G. , Rivas Analiesse , Bello Joaquin , Cordoba Pablo
Published: December 2007

El Furrial field is located in the Eastern part of Venezuela. The OOIP is about 7,500 MMSTB and the current daily production is 400 MSTBD. Due to the rapid pressure decline and the risks of asphaltene deposition, Enhanced Oil Recovery (EOR) processes have been implemented by water injection at the flank areas since 1992 and gas injection at the top of the structure since 1998.

Technical economical feasibility of infill drilling has been evaluated prior to considering the implementation of the full-field Water Alternating Gas (WAG) process. The main goal is to speeding-up of the recovery associated with the current EOR schemes. The applied methodology is based on maximization of the Net Present Value (NPV) under various schemes of production including new infill drilling.

The combination of numerical simulation results and economical analysis have led to a particular configuration of infill locations that will allow the extension of the current production plateau from 2007 to 2010. Incremental recovery after 20 years are as much as 250 MMSTB and the NPV could be increased more than 5000 MMUS$. Additionally, areal and vertical gas and water sweep efficiency is expected to improve with the optimization of the new well locations and the use of selective completions. This production plan would allow maximizing the efficiency of the current EOR schemes before implementing a WAG process.
Permeability Model Calibration and Pore Throat Radius Determination Using Core Analysis and Nuclear Magnetic Resonance Data in Mixed-Lithology Reservoirs, South Western Venezuela
Authors: Ferrer F. , Vielma M. , Lezama A.
Published: December 2007

In complex geological sequences composed by clastic and carbonatic rocks, where the matrix can be formed by several minerals, such as calcium carbonate, silica and magnesium carbonate, the determination of reservoir properties and rock quality represents a major challenge. Using conventional logs to calculate total and effective porosity in this type of reservoirs can lead to underestimation or overestimation of pore space in the rock and do not provide information about pore size and porosity distribution associated with irreducible water saturation that possibly will impact of reservoir permeability. To address these problems the response of the Nuclear Magnetic Resonance Log was calibrated to the petrophysical and geological properties measured in core. Correlation models were generated for total porosity, permeability and pore throat radius; which could be used in future wells of the area, where core data is not available.

A relation between the predominant pore throat radius calculated with the Pittman R45 equation (1992) and the irreducible water saturation from the Nuclear Magnetic Resonance Log was obtained. From this analysis five petrofacies were obtained: megaporous, macroporous, mesoporous, microporous and nanoporous, being predominant the macroporous, mesoporous, and the nanoporous. Total Porosity from the Nuclear Magnetic Resonance correlates very well with the total porosity data from core analysis. To calibrate permeability values derived from NMR data two different T2 cutoffs and Coates-Timur equation constants were used. Showing a relation with sedimentological facies described in macroscopic whole core analysis.

Seven sedimentary facies type were identified: Limey Sand, Sandy Limestone, Glauconitic Sand, Muddy Sand, Fine-grained Sand, Coarse-grained Sand and Shale. The best types of rocks (megaporous and macroporous) correspond to the best facies (Fine-grained Sand and Coarse-grained Sand). Limey Sand, Muddy Sand and Sandy Limestone were identified in mesoporous, microporous and nanoporous rocks, and most of the glauconitic sand intervals correspond to microporous and nanoporous petrofacies.
Saving Energy in Heavy-Oil Fields in Colombia With Progressive Cavity Pumps
Authors: Ramírez J. , Abril W. , Vargas Leonel , Trivino C.
Published: December 2007

One of the mayor economical impacts in a Project of artificial lift system shift is the associated cost of energy moreover the maintenance and well intervention must be considered. These variables are reflected as addition on the final artificial lift cost selected.

This study was accomplished based on experience at the Teca and Nare fields operated by Omimex Colombia where an artificial lift system shift was performed from Rod Pump (RP) into Progressive Cavity Pump (PCP), achieving significant savings in well downtime and energy comsuption at the same volume of production.

The strategy to develop this project started with the identification of well candidates where steam injection was not feasible then a change on the artifitial lift system was proposed to a set of wells.

Also is highlighted the importance of the operational variables in long term at the moment to choose an artifitial lift system
Production and Video Logging in Horizontal Low-Permeability Gas Wells
Authors: Sask D. , Hundt C. D. , Slade J. M. , Daly P.
Published: December 2007

The intention of this paper is to discuss and recommend effective production logging techniques for low rate horizontal gas wells. Between June 2005 and September 2006, a total of eight wells were evaluated using either traditional production logging (PL) tools or downhole video logging tools. Pressure, temperature, nuclear fluid density, single capacitance, capacitance array, fullbore spinner, caliper, and gamma-ray data were retrieved by production logging methods. Video logging collected thousands of wellbore images as well as pressure and temperature information.

A significant issue in logging horizontal wells is the method of delivering tools into the well. Tubing diameter, open hole diameter, horizontal length, horizontal trajectory and the desired results all influence the selection of conveyance method. The methods used in this study were CoRod, coiled tubing (CT) and wireline tractor.

The production logging data indicated liquid accumulations however the different logging tools showed varying degrees of detail. As an example, the capacitance array tool tended to show liquid with gas pockets while the radioactive density tool and spinner tool indicated 100% liquid. Video logging data provided definitive images of gas bubbles and slugs flowing through liquid.

The objectives of a logging program will dictate either a qualitative or quantitative evaluation. Video logging is an excellent technique to use as a general overview when initially investigating openhole sections. It can provide insight on complex production problems that never would be suspected or detected using traditional production logging methods.
Propellant-Assisted Solution to Perforation Penetration and Breakdown—San Jorge Field, Argentina: Case Histories
Authors: Elnaga Ashraf Aly Abou , Almanza Edgar , Batocchio Marcelo , Folse Kent , Schoener-Scott Martin
Published: December 2007

Chevron San Jorge S.R.L. operates in the Loma Negra area and El Trapial field located in the Neuquén Basin, Argentina.

El Trapial wells are characterized by stratified, shallow- to medium-depth reservoirs with permeabilities of 35md to 85md and porosities of 18 to 30%. The wells are completed in oil reservoirs that have been perforated using conventional methods, fracture stimulated to increase production, and later, completed with electro-submersible pumps (ESPs).

To effectively meet the operator's needs for a method that would help optimize well productivity, and at the same time, be cost effective without compromising the results of the operation, an improvement over traditional tubing-conveyed perforating (TCP) was required. A propellant-assisted (PA) perforating method that could optimize well productivity while maintaining stringent health, safety and environmental standards was proposed. The propellant-assisted perforating method uses standard perforating components and procedures, thus providing the same safety features available to the industry today when conventional TCP operations are used. The propellant is an oxidizer that creates carbon dioxide gas at extremely high peak pressures in the millisecond time regime to overcome in-situ stresses and create perforation breakdown and mild fracturing near the wellbore.

This paper will focus on two case histories describing the methods and improved results obtained from the application of the propellant perforating technique.

The information in this paper will verify that the technique was capable of satisfying the operational challenges in these reservoir types. Instrumental in the success of the propellant-assisted perforating methodology was 1) the proper screening of candidate wells, 2) good pre-job design modeling, and 3) adherence to industry accepted best practices with constant communication.
Geomechanical Application for Drilling Optimization in Marginal Fields, East Venezuela
Authors: Romero Franklin , Yu Woo Kenny , Meaño William , López Wilmer , Balseiro Prudencio , Romero Jorge , Castillo José , Rodríguez Luz Mery , Galíndez Nicolás , Rodríguez Jacqueline
Published: December 2007

This study is intended to show that it is possible to reduce risks, time and costs in well drilling through application of Geomechanics in marginal fields. It refers to the Oritupano-Leona field, East Venezuela, which has more than 700 wells drilled from 1938, 29 of which are horizontal wells.

In spite of the production success, 6 over 29 wells, 25%, presented problems due to hole instability that lead to several stuck pipes, sidetracks and down time.

Drilling parameters of 23 horizontal wells, operational problems, geomechanical information and regional geology were considered for this analysis. Problems associated to mechanical/chemical instability and operational problems were identified. Geomechanical parameters were calculated and analyzed with the specialized software considering pore pressures, mud density, minifrac and electrical logs, where the stress direction was studied with the interpretation of imaging logs and review of the regional stresses. A friction diagram adjusted to the wide of the breakout was applied, whereas vertical stresses were calculated through density log integration. Rock mechanical parameters were product of RSD tests that included rock mechanical resistance analysis (UCS), determination of the internal friction angle and the Poisson's ratio and Young modulus, calculated with the use of neural networks.

Drilling events were visualized in order to define the stability frame of the area for the different operational parameters based in geomechanical parameters previously calculated. With this data a new well design was elaborated integrating trajectory optimization and operational parameters in order to diminish the stability problems.

Different mechanical instability values were identified in the study in three zones of the field, and the safe operating window for drilling and operational parameters was identified for each one, guarantying hole cleaning.

The application of the criteria and recommendations of the results of this study had an outstanding impact on the horizontal well drilling in the Oritupano-Leona field. In 2005, a new record was established with the drilling of the ORM-174, which is the fastest horizontal well drilled in the field history. Two other wells were drilled in 2006 with excellent results.
Plunger-Lift Advancements, Including Velocity and Pressure Analysis
Authors: Morrow Stanley J , Hearn William
Published: December 2007

The interest in and demand for natural gas in the past few years has dramatically shifted the focus for many operators. Plunger lift, which for many years was viewed as a last resort, and somewhat of a nuisance, has gained an all time high in popularity and effectiveness and applicability. Much of the guesswork in evaluating candidates has now been replaced with exotic programs that combine Nodal analysis with performance based calculations.

In recent years both equipment and applications have improved, and the production range of plunger lift now includes many wells previously not possible to produce with plunger lift. Being able to correctly assess applicability, and identify the best type system is reducing the trial and error process previously associated with plunger lift evaluations and operations.
Beam Pumping System Optimization Through Automation
Authors: Sanchez Juan Pablo , Festini Diego , Bel Oscar
Published: December 2007

Recent economic conditions in the oilfield have given extra emphasis for operators to look for new ways to improve production operations and reduce operating costs. One means of doing this for rod pumped wells is utilizing Rod Pump Controllers (RPC). They have been available for over ten years in Argentina and only a relatively small percentage of operators have utilized it.

This paper presents the theoretical and practical benefits obtained with the inclusion of RPCs in beam pumping systems:

Energy saving: Despite the energy cost is not high in Argentina, the actual crisis force us to decrease the energy consumption through any circumstance.

Production Optimization: In general, any increase in well production is a result of the RPC providing immediate significant operating information to allow early detection and identification of potential pumping problems.

Expense Reduction: If a pumping system experiments a fluid pound or a system failure (i.e., stuck pump, pump "sanded-up", parted rod strings, tubing leak, etc.) the RPC will take action immediately.

Manpower Utilization: Since a RPC can provide fault messages related to the problem it has identified, corrective action is more easily determined.

The document shows a short technical description of the RPC and the Telemetry Software.

Then, to demonstrate reality results, a test realized in Lomita oilfield (Rincón de Los Sauces – RepsolYPF) will be exhibited. On it, some practical advantages will be put on view. Finally, a comparison between production controls, failures indexes and energy consumption before and after the test will be presented.
A Parametric Study of Reservoir Parameter for Micellar Solution Injection Process in Oil Reservoirs of Northeast Brazil
Authors: Medeiros H. O. , Barillas J. L. M. , Dutra T. V. , Mata W.
Published: December 2007

Chemical flooding is a process that improves recovery efficiency based on injection of a chemical system that contains surfactants and polymers. Surfactants are substances that alter the interfacial tension and promote a miscible displacement with residual oil. Polymers decrease the water mobility and, in this process, it is injected after the surfactant injection to promote an immiscible displacement of the micellar bank. Diverse operational and reservoir parameters can influence the micellar injection process. This work analyses the oil recovery efficiency of this process in reservoirs with characteristics of existing reservoirs in the northeast region of Brazil, identifying the optimal applicability parameters and the possible technical viability with these characteristics. The numerical study was done using the commercial software "Stars -CMG" (Computer Modelling Group).

The reservoir parameters evaluated were: porosity, permeability, oil viscosity and initial oil saturation, according to some Brazilian northeast reservoirs characteristics, in order to obtain the applicability of the process with these reservoir characteristics, and the optimal application conditions. Then, an analysis of the operational parameters was carried through, with the objective of optimizing the process. The results showed improved recovery efficiencies for diverse reservoir characteristic encountered in the State of "Rio Grande do Norte". For the cases and reservoir conditions studied, the most critical factor that affects the micellar process was initial oil saturation, and the process optimization showed an increase on cumulative oil and on recovery factor. An increase in oil recovery with small costs is the search of petroleum industries together with academic institutions because of uncertain oil price. Therefore, it may be necessary the study of different processes to improve recovery efficiency such as chemical flooding.
Recoverable Reserve Estimation in a Tight Gas Reservoir During the Exploration Stage, Neuquen, Argentina
Authors: Ucan Sezai , Olmos Sebastian , Valencio Daniel , Mosquera Alfonso , Alonso Jorge , Marin Horacio
Published: December 2007

A rapid and an effective reservoir simulation model was built based on limited information. 3D seismic impedance, two exploratory wells' log interpretation, a core data, and a well test consisting of an isochronal test and, several months later, an extended flow followed by long build up test were basic available data for this field. The main objective of this study is to estimate recoverable reserve with or without hydraulic fracturing in Mulichinco formation at the Paso Del Indio Field.

Material balance and decline curve analyses have important limitations to estimate ultimate recoverable reserves in the tight gas reservoirs. Well types that are derived from the conceptual simulation models do not reflect the effective drainage area or permeability heterogeneity in the field. A representative permeability in well spacing area should be averaged harmonically or geometrically. In order to estimate the ultimate recoverable reserves in the tight gas reservoirs, permeability heterogeneity or the effective available drainage area to hydraulic fractures should be simulated effectively. Relatively small changes in permeability can results in unsuccessful fracture design and in uneconomical flow rates.

A very quick and effective simple reservoir simulation model was established to estimate recoverable reserves rather than using conventional volumetric, material balance, and decline curve analysis in tight gas reservoirs. Not having any production histories, well test information was used very successfully as history matching information to validate the geological, petrophysical, and PVT models.