bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of the ß-Integral Derivative Function to Production Analysis
Authors: Ilk D. , Hosseinpour-Zonoozi N. , Amini S. , Blasingame T. A. 
Published: December 2007

Abstract
In this work we present the application of the β-integral derivative function for the interpretation and analysis of production data. The β-derivative function was recently proposed for the analysis and interpretation of pressure transient data [Hosseinpour-Zonoozi, et al (2006)], and we demonstrate that the β-integral derivative and its auxiliary functions can be used to provide the characteristic signatures for unfractured and fractured wells.
The purpose of this paper is to demonstrate the application of the "production data" formulation of the β-derivative function (i.e., the β-integral derivative) for the purpose of estimating reservoir properties, contacted in-place fluid, and reserves. Our main objective is to introduce a new practical tool for the analysis/interpretation of the production data using a new diagnostic rate and pressure drop diagnostic function.
This paper provides the following contributions for the analysis and interpretation of gas production data using the β-integral derivative function: Schematic diagrams of various production data functions using the β-integral derivative formulation (type curves).Analysis/interpretation of production data using the β- integral derivative formulation.
Effects of High-Pressure-Dependent Leakoff and High-Process-Zone Stress in Coal Stimulation Treatments
Authors: Ramurthy Muthukumarappan , Lyons Bill , Hendrickson Randall B. , Barree Robert D. , Magill Douglas P. 
Published: December 2007

Abstract
Hydraulic fracturing in coals have been studied extensively over the last two decades. However, there are factors that were often ignored or diagnosed incorrectly resulting in screenouts. Assuming that a majority of the perforations are open and there are no problems with the stimulation fluids, screenouts during coal hydraulic fracture treatments can be attributed to either high pressure dependent leakoff (PDL), high process zone stress (PZS) or in some cases both. The objective of this work is to discuss, help identify and present solutions to address these reservoir related issues such that screenouts can be avoided in optimized re-fracture treatments and new well stimulations.
The tools for identifying these reservoir related parameters include Diagnostic Fracture Injection Test (DFIT) and a grid-oriented fully functional 3-D fracture simulator with shear decoupling. An example for each respective case is presented in this paper. In the first example, where high PZS was considered to be the dominant reason for screenout or pressure-out, the well was re-stimulated successfully by implementing the solutions presented in this paper. In the second example, where high PDL was considered to be the main reason for screenout, there were several wells in the same project area that exhibited the same behaviour resulting in screenouts. After implementing the solutions presented in this paper to address high PDL all new wells were stimulated successfully without any issues.
Field Case Studies of Completion FluidsTto Enhance Oil and Gas Production in Depleted Unconventional Reservoir
Authors: Pursley John T. , Penny Glenn , Benton John , Nordlander Gary , McDougall Mike , Greene David , Crafton James W. 
Published: December 2007

Abstract
A study of completion techniques in depleted/low pressure tight permeability gas/oil reservoirs shows great promise through the use of a microemulsion (ME) additive in energized fracture stimulation treatment of new infill wells. This paper presents a comparison of four (4) wells completed according to historical stimulation practices and two (2) wells completed with microemulsion additive. See Table 1 for baseline data.
The damage mechanisms from past practices were exacerbated by depleted/ low bottom-hole pressures, high water saturations, and low bubble point crude. The use of the microemulsion additive reduced the liquid load and promoted liquid recovery, enabling the base fluid gases to establish gas saturated pathways and promote the production of the natural solution gas that is the field's primary economic resource. CO2 is thought to enhance this process by promoting the reduction of the near fracture face oil saturation. The microemulsion potentially enhances this action by reducing the mobility contrast between introduced fluids and reservoir oil, water, and gas phases.
Analysis of the production histories shows that the microemulsion additive significantly enhanced the reservoir conductivity and effective fracture length when compared to the historical completions when in sustained production. The two wells treated with microemulsion additive also experienced less damage as a consequence of the long shut-ins prior to sustained production, than did those with historical completions, which had much shorter shut-ins.
Internal Formation Damage Properties and Oil-Deposition Profile within Reservoirs During PWRI Operations
Authors: Ochi Jalel , Rivet Pascal , Benquet Jean-Claude , Détienne Jean-Louis 
Published: December 2007

Abstract
To predict correctly injectivity for Produced Water Re-Injection (PWRI), a good description of the formation damage by oil and solid particles have to be introduced in simulators for both fractured and non fractured flows. It is well known that the complex mechanisms of the formation of an external filter cake and of a deep internal damage should be better understood. In a previous published work1 we attempted to quantify the petro-physical external filter cake properties. In this paper, results from core flood experiments (CFE) aimed to quantify the internal damage are presented. In recent published works, CFE were performed to examine, along rock samples, the deposition profile of only solid particles. The present work focuses on the oil droplets deposition profile. The mechanisms and laws governing the internal damage with oil are different from those concerning solid particles. Like solid particles, oil tends to deposit preferentially at the core entrance but quickly a moving front of oil droplet is generated. According to our experimental results a simple method for modeling the evolution of the internal damaged permeability is presented and finally an attempt is made to extrapolate these results to the well scale for both matrix and fractured flows.
The Dendritic Well: A Simple Process Creates an Ideal Reservoir Drainage System
Authors: Rae Phil , Di Lullo Gino , Moss Paul , Portman Lance 
Published: December 2007

Abstract
Oil and gas wells are constructed with the intention of accessing and recovering hydrocarbons from permeable rock formations. Ideally, we would like to do that as quickly and as efficiently as possible. Unfortunately, we generally try to accomplish this goal by drilling only a few wells and depending on the native rock permeability, or the presence of natural fractures, to convey hydrocarbons to these few wells. This process is inefficient and, ultimately, leaves significant reserves unrecovered.
Natural processes often offer valuable insight into the most effective ways to exploit, or distribute, resources. If reservoir engineers could drill wells, they would surely not drill a single, small diameter hole, with the walls of that hole damaged to the point they are initially impermeable. They would more likely construct a network of branches, mimicking the root structure of plants, evolved to efficiently drain nutrients from a soil reservoir. This type of network, for the collection or distribution of materials, is a frequently repeated feature in natural systems and clearly represents a highly efficient method to access resources, of one kind or another. Such a network could maximise the contact between reservoir and wellbore and distribute inflow across an enormous surface area. This is the "Dendritic Well" – until now, an impractical concept but one that may have some future with further refinement of the technique reported here.
This paper describes several wells where multiple, relatively short-length laterals were constructed by pumping hydrochloric acid though a specially designed jetting assembly, attached to the bottom of a 1/" coiled tubing unit. This revolutionary method creates a "reservoir engineer's" hole, using simple equipment at low-cost. A highly stimulated lateral tunnel, branching from the original well with a fractal of smaller branches (wormholes) born out of the lateral hole, mimicking a plant root, is the end product.
Structural Styles and Tectonic Framework of the Fold and Thrust Belt in Tierra del Fuego and Offshore Austral-Malvinas Basins, Argentina
Authors: Martínez Pedro Bonillo , Figueroa D. , Ghiglione M. C. 
Published: December 2007

Abstract

Description
The Andes Patagónicos bend to the east at the latitude of Tierra del Fuego island, were they constitutes the Cordillera Fueguina. This cordillera plunges eastward into the offshore and represents the southern border of Austral and Malvinas basins.
The studied area includes the outer foothills of the fold and thrust belt located in Austral and Malvinas basins and their associated tertiary foreland deposits.
The regional tectonic framework is mainly a resultant of the interaction between South America, Pacific, Antarctica and Scotia plates during Late Cretaceous and Tertiary times.
The fold and thrust belt of Malvinas basin is a frontier area where no hydrocarbon exploratory wells have been drilled so far. Most of the data available are 2D regional seismic lines. Repsol YPF, as the operator of a consortium, recently acquired a 2500 km2 3D survey on this fold and thrust belt.
Five restored cross sections in the area are shown and its timing reconstructed. Once the cross sections timing is established, it's associated and related to the tectonic evolution of the area.

Application
Once the traps formation timing is defined, a reliable basin modelling can be performed to reduce the uncertainty associated to the trap charge and type of hydrocarbons.

Result, Observations and conclusions
The structural style is quite variable along the outer foothills region. It changes eastward from a thin skin deformation style in Tierra del Fuego (Argentina) to a thin skin combined with basement inverted faults in Malvinas basin. The main decollements are Lower Cretaceous and Paleogene shales.
The evolution of the fold thrust belt has been mainly controlled by the Scotia Plate activity, resulting in an intercalation of compressional/transpressional periods with others of extensional/transtensional character.
It is postulated that the structures studied in the outer foothills were developed during Oligocene and Lower Miocene times. These ages correlate quite well with a period of high oceanic crust generation at Scotia Plate.

Significance of subject matter
In a fault thrust belt, different compressive pulses configure the traps final geometry. The timing of these different pulses is critical for a correct basin modelling and a prospects risk evaluation.
Use of Discrete Fracture Network "DFN" to Characterize and Model a Naturally Fractured Sandstone Reservoir: A Case Study of Orocual Field, San Juan Formation, Venezuela
Authors: Guaiquirian L. , Gonzalez P. , Gonzalez A. , Hernandez M. Manuela , Le Maux T. , Mattioni L. , Rouvroy P. 
Published: December 2007

Abstract
Orocual field is an anticline located in the East of Venezuela within El Furrial Trend. The San Juan Formation, a tight Late Cretaceous-Early Paleocene sandstone, is one of the best producing reservoir of Orocual. Located at a depth of about 14000 feet, it is characterised by a low matrix porosity (5 to 6%) and permeability (below 5 mD in average). Very quickly identified as a possible fractured reservoir due to the difference between producers' performance and petrophysical data, this hypothesis was later confirmed with the acquisition of cores and borehole image logs ‘BHI’. Both show the presence of numerous open or partially open tectonic fractures.
The present paper focuses on one of the four structurally compartmentalized fault blocks of the field that presents the highest potential of reserves. It is shown how all available data, geology (Bore Hole Image logs, cores and wireline logs), geophysics, and reservoir engineering data (production data, flowmeters, welltests) were combined to identify the main types of fractures, to predict their occurrence in the reservoir and to determine the hydraulic properties of the different fractures sets. The DFN approach was used to characterise the natural fractures at well scale and to model the full field 3D fracture network. From BHI and core analysis, it was found that the formation Vshale and the porosity were the main geological drivers on natural joints (small scale fractures) occurrence. Those properties associated to the matrix were used to populate in 3D the fracture network model. A second type of fractures, large scale fractures associated to faults, although not identified on wells but strongly suspected to exist, have also been included in the 3D model. The model was hydraulically calibrated first through simulation of a measured flowmeter log with the DFN model and then through match of the KH measured from transient welltests with the KH derived from the model.
The outcome of the study is a reliable set of fracture properties that can directly be used in the 3D simulation model in order to improve the current history match and evaluate injection scenarios for the future.
A Field Development Strategy: When a Simple Stochastic Model Surpasses Numerical Simulation
Authors: Sancho V. , Berrios V. , Gulino F. , Oquendo O. 
Published: December 2007

Abstract
Numerical simulation of reservoirs is one of the most important engineering tools in monitoring mature fields, but depending on the precision and heterogeneity of the data, it can be replaced with an analysis based on statistics and production management.
Señal Picada field, located in The Naquin Province, Argentina, was discovered in 1963. It produced by primary recovery with an almost null declination for more than 12 years. After that, a disorganized secondary recovery process started in 1976, which increased substantially the water cut, due to an early waterfront irruption. In 2002, a reservoir numerical simulator was developed just for an isolated block that contained the 30% of the total reserves of the oilfield.
Due to the uncertainty generated by the quantity and quality of the historical data, the possibility of extrapolate the results of the simulator to another areas was evaluated versus other techniques. In a scenario of high oil prices, it is quite important to have no delays in implementing field development activities. Here is where the choice of one or another methodology can make an economical difference.
All uncertainties involved in field development through different methodologies, such as water conformance, Pattern Injection modifications, etc., can be minimized by the analysis of production data and statistical reserves analysis, combined with an analytical simulation. This allows a plan for recovery reserves faster than the construction of a numerical simulation model.
In the case of Señal Picada, due to the heterogeneity of the data, an accurate simulation of the entire reservoir would take a long time. The use of statistics and production data analysis guided by the analytical simulation has offered an accurate overview of the field behavior. Complementing this evaluation with the results of the numerical simulator, it will accelerate incremental oil production, maximizing the field internal rate of return.
Pore-Scale Characterization and Productivity Analysis by Integration of NMR and Openhole Logs–A Verification Study
Authors: Galarza Tania , Giordano Sergio , Fontanarosa Michael , Saubidet Marcelo , Altunbay Mehmet , Saavedra Benito , Romero Pedro 
Published: December 2007

Abstract
Presently, NMR logs are routinely used to estimate the irreducible portion of the bulk volume of wetting phase (BVI), permeability and the type of hydrocarbons present when filtrate invasion is limited or non-existent. In most cases, the rest of the pore-scale information contained in NMR log data is overlooked or ignored as the model equations used to infer it are empirical in nature. Our aim in this study is to demonstrate the use of and the degree of accuracy of porescale data derived from NMR logs by presenting an actual case study with production test results and comparison to corebased information. This study also demonstrates the importance of NMR based pore-scale characterization if or when the filtrate invasion limits the hydrocarbon typing capabilities.
Pore scale characterization is obtained by transforming the NMR data to synthetic capillary pressure and evaluating the dynamic properties of the formation in conjunction with the fluids present. The capillary transformation of NMR data is performed based on experimental models. The BVI from this transformation (RBVI) is tested against the conventional T2cutoff based BVI for accuracy and reliability prior to the determination of Swanson-based Swirr, relative permeability transformations and the critical Swirr that can be used for identifying transition zone. T2cutoff independent BVI (from which Swirr is derived), threshold pressure, mean pore-throat radius, effective permeability to wetting and non-wetting phases and the md-ft evaluation of subject intervals are the end products of this study. The results are compared to production test data to demonstrate the utility of NMR logs both to production/completion engineering and to well/formation economics.
R Sand Production in an Oil Field of Eastern Venezuela Basin: Example of Change in the Operation Strategy in a Mature Field Reactivation
Authors: Bellorin William , Castillo José , Lopez Sonia , Riera Ladimier 
Published: December 2007

Abstract
The study area has produced over 457 MMBbl of oil since its discovery in 1954. This study is focused on the R sand reservoir, one of the most important of the area. The original oil in place (OOIP) is 140 MMBbls and before the begining of the project, the accounted recovery of OOIP was 7.2%.
The field reactivation was performed after a thorough analysis that included a geological model review and creating a numeric simulation model. This resulted in an increment of the field production which reached up to 7000 Bbls/d of oil and an enhanced recovery factor of 13.6% by March 31st, 2005.
The main producing zone of the study area comprises Early to Mid Miocene (Oficina Formation); it is interpreted as interbedded sandstone, deposited in a fluvial environment with marine to shallow marine influence. Core analysis in one well shows that R sand was deposited in coastal plain influenced by tides and characterized by connected channels and outlets. The 3D seismic information available in the area made it possible to accurately define the structural model. After defining the static model and with the support of the engineering study, the reservoir development plan could be defined, which was oriented to improve and to increase the field productivity. It mainly consisted in drilling horizontal wells where succesful results were obtained after drilling and completing seven wells. This shows the impact of this type of wells in terms of economic benefits resulting in an increment in production and the recovery factor.
Impact of Pressure Depletion on Oil Recovery in Naturally Fractured Reservoirs
Authors: Chacon Abel , Tiab Djebbar 
Published: December 2007

Abstract
In naturally fractured reservoirs (NFRs), current analyses for quantifying reserves based on the material balance equation (MBE) assume that fractured reservoirs behave similar to homogeneous reservoirs, which implies that the fracture and matrix pore volume compressibilities are equal. There is considerable evidence that such assumption is not always valid leading to wrong estimation of reserves. In order to overcome this deficiency a complete treatment of the material balance formulation for naturally fractured reservoirs is presented. The proposed general MBE takes into account the fact that fracture and matrix pore volume compressibilities are different. This equation is used to investigate the impact of pressure depletion on the estimation of oil in place and recovery factors.
As results of this study, new equations to compute hydrocarbons originally in place in NFRs are developed for undersaturated and saturated reservoirs. New plotting schemes for the MBE involving the storage capacity ratio at initial reservoir conditions of fracture and matrix pore volume compressibilities are proposed. The capacity ratio is computed from pressure transient test performed during the early stages of production. These new plotting schemes requires only one regression parameter, the slope of a straight line passing through the origin on a Cartesian plot, which reduces the uncertainty that traditionally two regression parameters (intercept and slope) introduces; as consequence, better estimation of oil in place with fewer historical production data can be obtained. This new method is illustrated by several field examples.
It is concluded that (a) the proposed material balance formulation gives better estimation of oil in place than the traditional MBE computations; (b) the split of hydrocarbons originally in place between fracture and matrix frames depends upon the storage capacity ratio at initial reservoir conditions and; (c) the impact of pressure depletion on the estimation of reserves and recovery factors in naturally fractured reservoirs is significant.