bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effect of Heterogeneity on Production Performance in Low Permeability Reservoirs
Authors: Kewen Li , Yangtze U. , Ronghua Xie 
Published: September 2011

Abstract
It is well known that heterogeneity is one of the most important factors in affecting production performance. These include oil production rate, oil recovery before water breakthrough, water cut, etc. However, it has long time been a challenge to correlate the heterogeneity and the oil production performance quantitatively, especially in low permeability reservoirs. To this end, fractal dimension inferred from mercury-intrusion capillary pressure data and other parameters were used to quantitatively characterize the heterogeneity of rock in this study. Over 100 core plugs were sampled from different wells in a low permeability oil reservoir. Routine and special core analysis tests were conducted in these core samples with a permeability ranging from less than 0.1 to over 100 md. Correlation between heterogeneity and oil production performance was investigated at both the microscopic (core) and macroscopic (well and reservoir) scales. The results demonstrated that the fractal dimension was correlated with the production performance at microscopic and macroscopic levels. The oil production rate and the water breakthrough time show an inverse relationship with fractal dimension, while the water cut shows a direct relationship with fractal dimension.
Prediction of the Efficiency of Impulse-Wave Impact Application in the Well Treatments
Authors: Zamakhaev V. , Miftakhov S. 
Published: September 2011

Abstract
On the long-developed fields structure of residual stock is deteriorating and to maintain the highest possible rate of recovery different technologies for the rehabilitation of wells and enhanced oil recovery are applied. Hydraulic fracturing or explosive effects often lead to significant heterogeneity complicates the process of extracting oil. Discontinuities positive effect has short duration that lead to search for other approaches to solving this essential issue.
The impulse-wave impact (IWI) technology is an advanced method based on a combination of impulse effect (water hammer), which creates in layer longitudinal and transverse waves of seismic frequencies, and physicochemical effect. However, such aggregation is not a simple combination of these influences, but should be considered as a single process consisting of preparation for the impulse impact by directional changes in the adsorption conditions in a large reservoir volume and impulse action.
To achieve high technical and economic indices of reserve development is necessary to define scientifically grounded criteria for the organization of events; usage of large-scale geological field data representing objects for work and establishing specific technical recommendations for the IWI technology appointment and the optimal treatment condition for a particular well.
This paper deals with a predictive modeling, carried out within the bounds of a systemic approach to the selection of objects, appointment of manufacturing operations, the overall organization recovery works in water injection wells and exploitation wells as an example of fields in Western Siberia.
Predictive modeling of formation pay zone treatment process was conducted based on the accumulated initial geological, geophysical and technological information using the method of factor analysis. The advantages of this approach are particularly evident in the first stages of a trial simulation with the need to incorporate in the model of a large number of factors and the lack of "observations".
A Multimode Inversion Methodology for the Characterization of Fractured Reservoirs from Well Test Data
Authors: Lange Arnaud , Bruyelle Jérémie 
Published: September 2011

Abstract
Optimizing the exploitation of fractured reservoirs requires a reliable characterization of the most influential heterogeneities on flow properties. To this end, reservoir simulation models should remain interpretable in geological terms. Workflows are available (i) to construct geologically-realistic models of fracture networks, (ii) to turn these models into simplified conceptual models usable for field-scale simulations of multi-phase production methods. However a critical step remains that of characterizing the flow properties of the geological fracture network. The multiscale nature of fracture networks and the associated modeling cost impose a scale-dependent characterization: (i) multi-scale fractures are characterized in local dynamic tests area, e.g. well test drainage area, through the calibration of geologically-realistic Discrete Fracture Network (DFN) models and accurate local flow tests simulations; (ii) large-scale faults are characterized through reservoir-scale production history simulations. This paper presents an efficient "multi-mode" inversion methodology to facilitate the characterization of fracture properties from well test data. The fracture model is optimized sequentially according to different modes of deformation. First, the parameterization is defined such that the fracture model is deformed as a whole (mode 1), then S fracture sub-sets are defined accordingly to their sensitivities to well test data (mode S), where S is increased sequentially. The optimization is performed via an original evolutionary algorithm that has been coupled with a 3D DFN flow simulator. An application is presented on a fractured reservoir model having two facies, four fracture sets and involving a horizontal well test. The characterized fracture properties are the mean size properties, mean conductivity and facies-dependent fracture densities.
This "multi-mode" inversion methodology is shown to be much faster to characterize physically meaningful and data-consistent fracture properties, compared with a direct optimization application on all model parameters. This methodology facilitates the characterization of fractured reservoirs flow properties.
Workflows and Methods to Optimize Well Construction through a Collaborative Environment
Authors: Raja Hamayun , Carpenter Glenn , Oliver DeShawn 
Published: September 2011

Abstract
Since the advent of improved telecommunications in the early 1990s, operators and service providers have sought to reduce non-productive time (NPT) through remote operation capabilities delivered using real-time centers (RTC) or with a combination of remote expertise and computing power to monitor operations and provide technical advice to the field. Although the RTC concept has delivered tangible benefits, these benefits were less than anticipated and have been more difficult and expensive to implement than initially expected. Currently, advances in RTC and research and development (R&D) focus on integrated workflows to address specific problems. The goals are to safely reduce NPT, risk, and uncertainty to improve decision making and performance of the entire operation and to facilitate the prospect of remote, automated operations.
This paper presents two examples of workflows (i.e., geosteering and stimulation workflow) that can enhance operations for both the operating and the service company. This paper will also discuss some of the challenges in applying these integrated operations. These workflows, also known as 3-D collaborative environments, demonstrate the use of real-time information to model, measure, and optimize field performance, efficiency, and safety through the use of remote, closed-loop, real-time data and knowledge transmission. The 3-D collaborative environment for the stimulation workflow allows operators to use the data available from several product service lines to make decisions in real time that will improve production rates and reduce NPT. This particular workflow allows the use of geological, geophysical, stimulation, and micro-seismic data to visually understand actual fracture growth during a stimulation treatment. Knowing the location of micro-seismic events as they relate to geological boundaries and surfaces allows the fracture engineer to quickly make decisions during pumping to reduce undesirable results. The "geosteering workflow" provides a 3-D collaborative effort between the customer's geological and geophysical software and the service company's geosteering software. This workflow resolves structural solutions in complex geological situations in real time, where the solution cannot be resolved by either system alone. Structural grids, faults, well picks, fault picks, and control points move between the software using a WITSML proprietary code. The results include fewer sidetracks, redrills, and maximizing reservoir exposure to the wellbore.
Well Test Analysis of Medium-Rich to Rich Gas-Condensate Layered Reservoirs
Authors: Kgogo T. C. , Gringarten A. C. 
Published: September 2011

Abstract
Gas condensate reservoirs exhibit complex flow behaviours when the bottomhole pressure drops below the dew point pressure. This is due to the creation of condensate banks around the wells, which also induce losses in productivity. Multi-layered reservoirs add to the complexity as a consequence of contrasting properties in the different layers. Understanding the pressure behaviour of layered systems is important to determine reservoir parameters, predict well performance and maximize hydrocarbon recovery.
This paper investigates well test behaviours below the dew point pressure of vertical wells in medium-rich to rich gas condensate layered reservoirs, with and without crossflow. 3-D compositional simulation was used to investigate wellbore pressure responses below the dew point pressure, and in particular the effect of condensate drop-out on the productivity of the different layers.
It was found that composite well test behaviour due to condensate bank, and multi-layer behaviour are superimposed, with the condensate bank appearing on top of multi-layer effects on the pressure derivative. In a two-layer reservoir, the condensate bank radius is always greater in the most-permeable layer. Near-wellbore liquid saturation is lower in the least permeable layer at early times; becomes equal to that in the most permeable as production rate and time increase and pressure in the two layers stabilizes; and increases above that of the most permeable layer at later times when there is crossflow. Eventually, the least permeable layer becomes choked by its condensate bank and all production occurs through the most permeable layer only.
Results from this study were used to understand well test data from the E-M field located offshore South Africa and to repair a vertical well in that field.
Torque and Drag Software Model Comparison: Impact on Application and Calibration of Field Data
Authors: McCormick John E. , Frilot Melissa , Chiu TzuFang 
Published: September 2011

AbstractWith the number of extended-reach wells steadily increasing, software modeling has become a commonplace and essential process during a well's planning phase. Over the years, numerous computer programs have been developed to predict torque and drag (T&D) forces experienced during oilfield drilling and completion operations. Accurate prediction of T&D forces can reduce serious drilling operation risks such as buckling, pipe failures, box swelling and the inability to get liners and casing to total depth (TD).Most, if not all, industry available T&D software programs allow users to manipulate inputs such as friction factors, mud weight, and string component parameters, such as pipe weight, grade and dimensions. While the ability to alter the inputs in the T&D model is a practical necessity, the possibility of unknowingly impacting the calculations is an ever present danger. In addition to a thorough knowledge of how to input well parameters and analyze outputs, it is crucial for program users to question the reliability of each program and to understand the impact that changes in inputs have on the model's outputs.This paper will describe the technical differences between two T&D modeling programs, the underlying calculations, and the practical implications in terms of calibrating the two models to the same sets of field data. This paper also endeavors to increase knowledge and competency for T&D software users in the oil and gas industry.
Optimizing Horizontal-Well Hydraulic-Fracture Spacing in the Eagle Ford Formation, Texas
Authors: Mendoza E. , Aular J. , Sousa L. 
Published: September 2011

Abstract
The successes of horizontal-well completions in the Eagle Ford formation have increasingly attracted interest within the oil and gas industry. An improved stimulation technique using new fluids and proppants has resulted in better zonal coverage through improved diversion and tagging. Low-permeability reservoirs attract increased attention from oil companies because of increased demand and limited opportunities in conventional (higher-permeability) reservoirs.
This paper presents a case study of a horizontal well in the Eagle Ford reservoir. The reservoir rock is considered 100% dolomite with 9 to 12% porosity and permeability of 4.0E-5 md. Vertical wells in this area, even being hydraulically fractured, still produce below economic limits. Horizontal wells with multiple, transversal hydraulic fractures have shown to produce more than vertical wells and have been successfully applied in low-permeability reservoirs in Texas.
The principal objective of this paper is to show the analysis and selection process of a completion design for a new well to evaluate the reservoir parameters and determine the optimum hydraulic-fracture completion design, including fracture stages and an economics review. In this work, 3D fracture growth and conductivity models were calibrated and optimized using the existing fracture post-job reports of neighboring wells completed in the Eagle Ford reservoir.
This workflow could be applied to any low-permeability reservoir with the intent to optimize the number of hydraulic-fracture stages on a new horizontal well, minimizing the stages’ interference and maximizing the expected net present value (NPV). This workflow demonstrates an effective methodology for capturing essential characteristics of Eagle Ford reservoirs and offers a quantitative means and platform for optimizing shale reservoirs.
Hybrid Drill Bit Improves Drilling Performance in Heterogeneous Formations in Brazil
Authors: Thomson I.. , Krasuk R.. , Silva N.. , Romero K.. 
Published: September 2011

Abstract
Geologically heterogeneous (mixed) formations pose a significant challenge to drillers in terms of drilling performance. Shale and other soft and plastically behaving rocks favor the use of PDC bits, while hard and abrasive sandstone with hard cement stringers favors roller cone bits.
With recent advances in PDC cutter technology it is possible to combine the best features of both bit designs to drill formations that constantly fluctuate between hard and soft lithology, and often without notice. This has been achieved by using a basic PDC bit design and replacing the secondary blades on the periphery with rolling cutters equipped with tungsten carbide inserts. The resulting product is frequently referred to as a hybrid bit. A hybrid bit allows the maintenance of overall penetration rate (ROP) at much higher levels than that of a roller cone or PDC bit alone. Avoidance of the necessity of tripping for bits due to formation changes or for premature bit wear is clearly advantageous. Experience from the USA, where up to a 35% reduction in drilling time has been achieved in heterogeneous formations, prompted the use of this technology in Brazil.
A similar challenge exists in NE Brazil with geologically interbedded sandstone and shale sequences. The challenge was to drill the interval with improved ROP and with reduced vibration while simultaneously reducing the need for bit change related trips. Experience in Brazil to date shows that by maintaining a consistent ROP in interbedded formations, aided by better toolface control due to lower torque fluctuations, a 44% decrease in total drilling time has been achieved while run length more than doubled. Future evaluation of this new technology extends to Brazil offshore basins (Campos, Santos, and Espirito Santo) where Albian and Aptian carbonate reservoirs have different lithologies but the challenges of geological heterogeneity are similar.
Improved Characterization of Non-Linear Injectivity Formation Damage from Coreflood Pressure Measurements
Authors: Vaz A. S. , Bedrikovetsky P.. , Fernandes P. D. , Furtado C.. , de Souza A. L. 
Published: September 2011

Abstract
PWRI and seawater injection may result in drastic injectivity decline. The reason is solid and oily particles, which are captured by rock from injected water causing steep permeability decline. The reliable injectivity decline prediction, allowing for injector stimulation planning and design, is based on mathematical modelling with well-known values of two model functions of filtration and formation damage.
Previous works proposed the method to determine two injectivity damage constants - filtration and formation damage coefficients - by measuring pressure drops on the core and also on its first section (so called 3-point-pressure method). Dimensionless pressure drop, which is proportional to skin factor, was proven to be linear with time, allowing for unique solution of the laboratory data matching problem. Yet, often the skin growth curves are non-linear. It is explained by the retained concentration dependence of filtration and formation damage functions. In the previous works, the physics reasons for filtration functions to be linear have been analysed. Therefore, the filtration coefficient was assumed to be linear function of retained concentration. The inverse to the formation damage function was assumed to be quadratic polynomial of retained concentration, which caused non-realistic skin prediction and non-unicity of the matching problem.
In the present paper, the inverse to the formation damage function was assumed to be monotonic power function of retained concentration, allowing for unique matching with laboratory data. An analytical model developed accurately describes pressure data of several coreflooding tests. In order to validate the proposed method, the pressure drop was measured on the second core section on top of the first section and the overall core. The measured data were compared with modelling tuned by the data from the first section and the overall core. Good agreement between the measured and fully predictive modelled data was observed, which validates the proposed method.
Production Experience in the BC-10 Parque das Conchas Development Offshore Brazil
Authors: Souza B.. , McFee K.. , Caillaux P.. , Langedijk R.. 
Published: September 2011

Abstract
July 2009 saw the start of production from Phase 1 of the Parque das Conchas project, an offshore cluster development located in license block BC-10, 120km off the Espirito Santo coast in the Campos Basin, Brazil. Phase 1of the project consists of three diverse, small fields with a wide range of oil types, tied back to a Floating Production Storage and Offloading vessel (FPSO). The eight producers located in the Ostra and Abalone fields flow to a subsea artificial lift manifold (ALM), where gas and liquids are separated, with the liquids pumped to surface via caisson-based electrical submersible pumps (C-ESPs). The two producers in the Argonauta field flow to a second subsea ALM, where the multi-phase fluids are pumped via non-separated C-ESPs. The produced gas is re-injected into a gas disposal well in the Ostra aquifer until export facilities are available.
On start-up, a few key uncertainties remained on the performance of the wells in the field, particularly related to initial production rate, well connectivity and the potential for fines migration inside the formation and the gravel-packs. A surveillance plan was developed before first oil to assure integrity of the wells and to determine and improve the performance over time. The plan was linked to the available measurements of permanent down-hole pressure and temperature gauges (DHPTG) and subsea multi phase flow meters (MPFM) in most wells. A schedule of interference tests, individual well tests and pressure build-ups was planned for the initial production phase.
Conclusions drawn from the surveillance plan are based on the analysis of the whole range of collected data, matched to single well and integrated system models. This paper will describe the logic of the surveillance plan and the experience gathered from the wells during the first year of production from the Parque das Conchas fields and how this information has been used to optimize production.
Production Logging in Horizontal Wells: Different Deployment and Data Acquisition Methodologies in Open-Hole and Cased Completions
Authors: Torne Juan , Arevalo Francisco , Rourke Marvin , Jay Phil , Kwong Shan 
Published: September 2011

Abstract
The horizontal wells drilled during the last few years are coming to a mature state in different fields and locations. This maturing has created the requirement to evaluate the performance of the wells and determine water sources for proper reservoir management.
In horizontal-well tool deployment, multiple sensor data acquisition and the interpretation of these results is a challenge particularly when there are long intervals of open-hole completions and where fractures are often encountered. The horizontal cased-hole completions use multiple downhole valves and external packers to provide isolation between intervals.
This paper reviews the two primary deployment techniques of coil tubing and tractor conveyance and highlights their advantages and limitations. In the paper, we propose a general guideline for their use.
The use of different sensors and their application is reviewed, providing recommendations particularly for low flow-rate conditions. Two interpretation methodologies are evaluated and results are compared along with the interpretation from other sensors.
The value of integrating of all available information and the value of different data acquisition and evaluation techniques is presented as well in the paper. The conclusions highlight the operational considerations, the data interpretation, and added value in the evaluation of well performance to maintain production and improve reservoir management.