bluuebunny/crossref_metadata_2025_split huggingface dataset:
Laboratory Evaluation of Acid Refracturing Performance
Authors: Pournik M. , Smith B. T. , Li L. , Wang G. , Nasr-El-Din H. A. 
Published: December 2010

AbstractAcid fracturing is a stimulation process in which the dissolution of the fracture faces creates conductivity after fracture closure. The resulting fracture conductivity depends highly on the amount and pattern of etching in addition to the strength of asperities. Various field acid fracturing treatments have shown sharp reduction in conductivity with production with almost no significant conductivity after some time. As a result, wells are refractured with the attempt of restoring or enhancing the conductivity of initial fracture. However, performance of acid refracturing treatments has not been studied and the conditions that result in success of refracturing operations are not understood.A systematic experimental study was conducted to investigate the performance of acid refracturing process. Indiana limestone samples were treated with three typical field HCl systems of gelled, viscoelastic, and plain HCl. Conductivity measurement was performed on acid-etched core faces up to various levels of closure stress and then the samples were acid refractured again under the same conditions as the initial acid fracture. The re-etched fractures were once again placed under closure stress and conductivity measurement taken at different loads.Experiments clearly show that acid refracturing performance is influenced by the acid system. Enhancement of conductivity with acid refracturing depended upon the acid system with greatest enhancement with plain HCl and even a deterioration with gelled acid system. While acid refracturing process did not result in significant increase in etched volume as compared to the initial treatment, it did usually cause greater enhancement in etching pattern.There have been many developments in enhancing the performance of acid fractured wells. However the major reason for lack of success of refractured well is limited understanding of conditions that control success rate. In order to understand the controlling factors for success of acid refracturing process, systematic experimental work must be performed. Based on the findings of important parameters for success rate of acid refracturing, acid refracturing treatments can be better designed to always lead to enhanced productivity.
World's First Fracturing-Stimulation Application Through Selective-Injection Completion: Casabe Field
Authors: Olarte P. , Amaya R. , Cortes G. , Artola P. , Yeguez R. 
Published: December 2010

Abstract
This document presents a new fracturing application carried out through pre-existing selective completions in non-stimulated water injection wells from the Casabe field in Colombia. The technique was created as part of the revitalization strategy of this mature field, to improve the injection performance.
Selective water injection completions were implemented in the Casabe field in 2006 in order to address the low vertical efficiency of the injection, stemming from the high vertical heterogeneity of the formation, made of a large number of intercalated sands and shales, when using conventional, non-selective completion strings. In spite of the implementation of selective injection as mitigating measure, several reservoirs or sand layers were still not flooded by water, while these sands hold important remaining reserves of oil.
The new stimulation technique focused on the further improvement of vertical sweep efficiency by fracturing those low water admission layers through the selective injection strings already installed in the wells. A pilot application was successfully carried out, proving the technique as a highly profitable, rig-less operation, which minimizes operating costs and risks. As a result of this novel fracturing application, the injection rates in the stimulated wells increased over seven times and vertical sweep improved between 70% and 100%.
In comparison with conventional fracturing, the operating time with the new fracturing technique was reduced by 50%, resulting in cost savings approximately of 1MMUSD per well. This fracture technique has shown an 80% of success and it is intended to apply it widely in all preexisting and future injection wells completed selectively in the field.
This world's first successful application is consistent with the permanent industry needs to implement technically sound and viable secondary recovery techniques or methodologies for increasing profitably oil production, and for boosting recovery factors, in a fluctuating oil price environment.
A Study of the Impact of 4D-Seismic Data on TSVD-Based Schemes for History Matching
Authors: Dickstein F. , Goldfeld P. , Pfeiffer G. T. , Amorim E. P. , dos Santos R. W. , Gómez S. G. 
Published: December 2010

Abstract
We discuss a TSVD (truncated singular value decomposition) optimization scheme for history matching. We are particularly interested in studying the performance of TSVD under integration of P-wave velocity data. We compare the structure of the main singular value triplets with or without time-lapse seismics. We then analyze the impact of introducing the seismics in a synthetic two-phase model problem. We observe in our experiments a strong regularization of the inversion algorithm due to the seismics. At the same time, we obtain much better reservoir descriptions when 4D seismics is available.
3D Geomechanical Modeling for the Apiay and Suria Oil Fields Llanos Orientales Basin, Colombia: Insights on the Stability of Reservoir-Bounding Faults
Authors: Fernández-Ibáñez F. , Cardona F. , Holland M. , Araujo E. , Brudy M. , Alvarellos J. , Ordóñez Y. , Mateus D. 
Published: December 2010

Abstract
Understanding the spatial variation of stresses and rock mechanical properties is the key to optimize strategies for field development. In geologically complex regions, as faulted and folded domains or areas of lateral facies changes, integration of the geologic structure is crucial to better predict geomechanical attributes. This has been done in an area located in the Llanos Orientales Basin (Colombia) by means of a three-dimensional geomechanical model. The model integrates knowledge of the geological structure and regional stratigraphy, data collected in more than 40 wells, and the drilling experience acquired over 20 years. The result is a high resolution 3D model, easy to handle and to update, with a number of immediate applications that go from field exploration to harvesting and abandoning.
Seismically resolvable faults and horizons have been brought into three-dimensions to build a structural model of the Apiay- Suria region. The structural framework has been used to propagate the geomechanical attributes of a number of wells using geostatistical algorithms. As a result, we have built a 3D model comprising the magnitudes and orientations of the three principal stresses, the pore pressure regime, and rock mechanical properties as uniaxial rock strength, internal friction or Poisson's ratio.
The resulting 3D model provides a high resolution database that maps any lateral variation of the geomechanical attributes across the field and can be used to assess wellbore stability for any future well trajectory and location. The 3D numerical geomechanical model has been also used to determine the stress conditions near the main faults. The stress tensor is here combined with a failure criterion to assess the potential for fault instability. This study provides a valuable insight on the risk of losses while drilling through these faults and the possibility of seal rupture and leakage during injection and hydraulic fracturing activities.
Environmental Governance in Oil-Producing Developing Countries: The Case of Peru
Authors: Alba E. Mayorga 
Published: December 2010

Abstract
This paper reports the results of a survey of 27 oil-producing countries conducted by The World Bank to compare environmental and social governance against a benchmark standard representing a compendium of best practices for minimizing environmental impacts of oil and gas development.
Countries surveyed have in place a largely theoretical environmental policy and legal framework. However, the effectiveness of this framework is compromised by the lack of organized administrative structures that enable regulatory compliance. Human and financial resources needed for environmental governance are generally missing.
Most countries have adopted an EIA process. However, the emphasis appears directed toward approval of projects, rather than reflecting a life cycle management approach to environment and social issues. In general control and enforcement mechanisms after approval are rather limited.
Governments may consult, but disclose little to the public and affected stakeholders. Consultation is more about informing stakeholders about proposed projects once the operator is selected rather than involving them in project related decisions. There are barriers to disclosing project information and the social environments in which they occur, and to implementing a centralized information system.
Governments pay little to issues regarding liability and decommissioning of facilities. Efforts to involve private operators in applying internationally accepted practices to minimize impacts of industry development could be improved.
The paper describes the survey themes, the bench mark countries and derived standards and the evaluation process. It provides an overview of the results focusing in the Latin American countries and Peru, in particular.
Recommendations comprise: Undertake a gap analysis as a further refinement.Improve capacity in EIA monitoring and follow-up through training, workshops, and case studies; and use of qualified consultants.Improve consultation and outreach processes to build trust between industry, governments, and local communities through regional livelihood development programs.Support the development of regional information systems for disseminating environmental and social information relating to oil and gas projects.Support an approach for managing environmental liabilities including a regulatory and accounting framework; determination of liability costs and their assignment; and a better understanding of decommissioning procedures.
Seismic Innovation Challenges for Developing Stratigraphically Complex Mature Oil Fields: An Example From VMM, Colombia
Authors: Reyes-Harker A. , Agudelo W. M. , Guevara S. E. , Sandoval J. R. 
Published: December 2010

Abstract
Spatial distribution of sand bodies with the capacity of storing hydrocarbons follows complex patterns in reservoirs deposited in fluvial environments. Understanding this distribution is one of the most important factors to consider in the planning and management of any development strategy.
Usually, a vertical distribution of the sand bodies is obtained from well logs, core description, and outcrops added with sedimentation and depositional modeling using different techniques. This information is transferred to 2D and 3D stratigraphic models in correlations and stratigraphic panels. Despite of model depuration and tuning with development information, uncertainty is still very high. The acquisition of 3D multi-component seismic information was defined as the tool to reduce this uncertainty in the volumetric distribution of sand bodies and their connectivity, to build the geometry of the reflectors with the wave field P, identifying the lithology and the presence of fluids.
A pilot of this technology was designed in the Tenerife field (Middle Magdalena Valley Basin, Colombia) focused in obtaining information of the Mugrosa formation, of Oligocene age, composed basically by sandstone deposited in thin fluvial channels, primarily meandering. To obtain the planned outcome, a high density design (480,000 traces / km2) was developed to allow a sufficient relation signal/noise in the S wave. Non conventional field tests allowed the design of the parameters of charge from the energy source and the depth of the receptors. For the static solutions, multi-component "upholes" and the description of the shot point (SP) where tested to allow a geological model of the strata that could be related with the velocities of the P wave and S wave.
The innovative design for the management of the combination of seismic attributes of the S wave and P wave has shown considerable advantages in the definition of the sand bodies in fluvial environments as heterogeneous as this case. This innovation opens immense possibilities for the development of similar fields in the Middle Magdalena Valley Basin as in other regions of the world with similar deposits.
Potential Economic Value-Added Model Using Formation Sampling-While-Drilling in Development Fields
Authors: Djefel M. , Tigre C. , Proett M. , Eyuboglu S. , Naupari C. , Beck G. 
Published: December 2010

Abstract
Formation sampling-while-drilling (FSWD) technology has recently been introduced, and this new method of obtaining formation samples is expected to reduce costs in development and appraisal wells. Formation testing on wireline (FSWL) pumpout tools have become the preferred method for obtaining formation samples in the drilling stages of a well to appraise the production potential. Although FSWD has the potential of reducing the sampling time, many factors must be considered when evaluating the economic benefit of a new technology. Now that day rates for deepwater drilling have reached $1 million, this has become one of the primary considerations.
This paper presents an economic model that can be used to evaluate the cost benefit and to make a comparison between wireline formation fluid samples acquired by the customer in a deep water field in Campos Basin, Brazil, in two scenarios (clastics and carbonates), with the simulation results obtained by the FSWD sensor.
Recent publications indicate a potential to reduce the sampling time with FSWD because of reduced invasion time. They also consider other factors, such as the permeability, porosity, and in-situ viscosity of the producing intervals, and the mud system properties that can have an equal effect on the invasion and pumpout time required to reach a sufficiently low contamination sample to evaluate the reservoir.
These factors are then used in an economic model that features operation costs for FSWL and FSWD, including the uncertainties regarding the following:
Fishing time, which is normally associated with the wireline operation Reduced pumping times associated with lower invasion, which will also reduce operational pump failures associated with extending pumping times Ability to obtain fluid samples in high angle or horizontal sections, reducing the operational time and enabling the operators to change their traditional well construction programs reducing or cancelling the need to drill a pilot well section and/or setting an intermediate casing string
Field Development Strategies for Bakken Shale Formation
Authors: Zargari S. , Mohaghegh S. D. 
Published: December 2010

Abstract
Bakken shale has been subjected to more attention during the last decade. Recently released reports discussing the high potential of the Bakken formation coupled with advancements in horizontal drilling, increased the interest of oil companies for investment in this field. Bakken formation is comprised of three layers. In this study upper and middle parts are the core of attention. Middle member which is believed to be the main reserve is mostly a limestone and the upper member is black shale. The upper member plays as a source and seal which has been subject to production in some parts as well.
In this study, a Top-Down Intelligent Reservoir Modeling technique has been implemented to a part of Bakken shale formation in Williston basin of North Dakota. This innovative technique utilizes a combination of conventional reservoir engineering methods, data mining and artificial intelligence to analyze the available data and to build a full field model that can be used for field development. Unlike conventional reservoir simulation techniques which require wide range of reservoir characteristics and geological data; Top-Down modeling utilizes the publicly available data (production data and well logs) in order to generate reservoir model. The model accuracy can be enhanced as more detail data becomes available. The model can be used for proposing development strategies.
The model is then used to identify remaining reserves and sweet spots that can help operators identify infill locations. Furthermore, a predictive model was generated, history matched and economical analysis for some proposed new wells is performed.
A Systematic Approach to Modeling Condensate Liquid Dropout in Britannia Reservoir
Authors: Göktas B. , Macmillan N.A. , Thrasher T.S. 
Published: December 2010

Abstract
Britannia field is a gas-condensate reservoir in the central North Sea, and has been producing since 1998. Condensate accumulation near the wellbore continuously impairs well productivity during the first year of production, as wellbore pressure drops below dew point, before stabilising where further well performance deterioration becomes negligible. The magnitude of the initial productivity loss averages 50-60%. Using several Britannia field well examples, this paper presents a comprehensive and systematic production data analysis approach to modeling well productivity deterioration due to condensate accumulation.
Production performance of Britannia wells is monitored by routine bottom-hole and wellhead back-pressure curves constructed using separator well test data. Permeability levels within the Britannia reservoir zones are high enough that the wells reach pseudo steady state (pss) flow within about a month. The well performance signature (shape of back-pressure curves) is characterised by performance points moving quickly to the left from the pss line, as condensate accumulates around the wellbore and reduces well deliverability. The workflow described in this paper uses the slope of the back-pressure curve of the late-time performance in order to provide estimates of kh, mechanical skin and non-Darcy flow coefficient. Effective permeability to gas (krgk) in the transient or stabilised deliverability equation is adjusted to match separator test points for estimating condensate blockage as a function of producing time. Reservoir simulation sector models are used to convert gas-relative permeability versus time relationships to gas-relative permeability versus saturation relationships. Pressure transient analysis, production data analysis type curves and the flowing material balance method are collectively utilised to fine-tune the initial estimates of kh and skin used in the deliverability equation.
Back-pressure curves are routinely used to identify wells for workover to improve well productivity, and candidates for capillary string installation or to evaluate benefits of additional field-wide compression.
Relative Permeability Hysteresis Effects in the Near-wellbore Region During Liquid Loading in Gas Wells
Authors: Zhang He , Falcone Gioia , Teodoriu Catalin 
Published: December 2010

Abstract
In oil and gas field operations, the dynamic interactions between reservoir and wellbore cannot be ignored, especially during transient flow in the near-wellbore region. A particular instance of transient flow in the near-wellbore region is the intermittent response of a reservoir that is typical of liquid loading in gas wells. Our previous numerical simulation study (Zhang et. al. 2009 and 2010) successfully captured the liquid backflow rates resulting from bottomhole pressure (BHP) oscillations typical of liquid loading, and emphasized their detrimental effect on gas production.
This paper presents a numerical modeling effort to investigate the relative permeability hysteresis effects in the near-wellbore region during transient flow conditions for a synthetic, low permeability gas reservoir. Firstly, the previously validated "U-shaped" pressure profile along the reservoir radius was generated with an increased BHP from a starting steady-state flowing configuration. This pressure profile can lead to reinjection of the liquid phase into the reservoir. The BHP was then let to decrease, with a corresponding temporary recovery in gas productivity. With subsequent BHP oscillations, the flow direction was allowed to switch back and forth, which could represent a typical liquid loading scenario. The Killough method was used to calculate the relative permeability hysteresis during the various imbibitions and drainage processes.
The results reveal that the hysteresis effect is negligible at a high-frequency alternation of imbibition and drainage in the near- wellbore region, and may therefore not be significant in liquid loading problems.
Use of Natural Gas as a Driving Force in a Diluent-Gas Artificial-Lift System Applied to Heavy Oils
Authors: Brito F. , García L. , Brown J. 
Published: December 2010

Abstract
The diluent-gas method is an artificial lift system for heavy oils (as low as 8.5 °API), where a light crude is used as diluent and it is injected into the well along with natural gas in order to reduce the viscosity of the crude oil therefore increase oil production. This method is unique in the world and has been long used in Venezuela.
Due to high maintenance costs, 20,000 US$ annually, incurred in replacing and repair diluent pumps (reciprocating pumps), which are used to inject at 900-1,000 psig the diluent (28-35°API) into the well, those pumps are considered as a critical system, basically, because of high operational pressures and oil production deferred, which is estimated in 2,500 barrels per year.
This project was based on analyzing a novel way to pump the Diluent and Gas down the well. The equipment designed is denominated Gas Displacement Pump and utilize the same gas lift (900 – 1,000 psig) as a driving force to inject the Diluent into the well. The system is made up of a vessel, a group of valves, pipes, level control systems, etc.
This novel design will allow minimizing; deferred oil production, environmental damage and maintenance costs, OPEX is reduced considerably (85%), as the Gas Displacement Pump will not have moving parts thus maintenance expenses would be low, generating this significant savings to the company. Finally, it was demonstrated that there is no slug flow formation using this new system and that the flow regime governing the system is stratified.