bluuebunny/crossref_metadata_2025_split huggingface dataset:
Decline Curve Analysis of Fractured Reservoirs With Fractal Geometry
Authors: Camacho-Velázquez R. , Fuentes-Cruz G. , Vásquez-Cruz M. 
Published: December 2007

Abstract
Evaluation of reservoir parameters through well test and decline curve analysis is a current practice used to estimate formation parameters and to forecast production decline identifying different flow regimes, respectively. From practical experience, it has been observed that certain cases exhibit different wellbore pressure and production behavior from those presented in previous studies. The reason for this difference is not understood completely but it can be found in the distribution of fractures within a Naturally Fractured Reservoir (NFR). Currently, most of these reservoirs are studied by means of Euclidean models, which implicitly assume a uniform distribution of fractures and that all fractures are interconnected. However, evidences from outcrops, well logging, and production behavior studies, and in general, the dynamic behavior observed in these systems, indicate that the above assumptions are not representative for these systems. Thus, the fractal theory can contribute to explain the above.
The objective of this paper is to investigate the production decline behavior in NFR exhibiting single and double porosity with fractal networks of fractures. The diffusion equations used in this work are a fractal continuity expression presented in previous studies in the literature, and a more recent generalization of this equation which includes a temporal fractional derivative. The second objective is to present a combined analysis methodology which uses transient well test and boundary-dominated decline production data to characterize NFR exhibiting fractures depending on scale.
Several analytical solutions for different diffusion equations in fractal systems are presented in the Laplace space for both constant wellbore pressure and variable pressure-variable rate inner boundary conditions. Both single and dual-porosity systems are considered. For the case of single porosity reservoirs analytical solutions for different diffusion equations in fractal systems are presented. For the dual-porosity case, an approximate analytical solution, which uses a pseudo-steady state matrix-to-fractal fracture transfer function, is introduced. This solution is compared with a finite difference solution and good agreement is found for both rate and cumulative production. Short- and long-time approximations are used in order to obtain practical procedures in time for determining some fractal parameters. Thus, this paper demonstrates the importance of analyzing both transient and boundary-dominated flow rate data for a single-well situation in order to fully characterize a NFR exhibiting fractal geometry.
Synthetic and field examples are presented to illustrate the methodology proposed in this work and to demonstrate that the fractal formulation explains consistently the peculiar behavior observed in some real production decline curves.
Evaluation of Commingled Reservoir Properties Using Production Logs
Authors: Poe B. D. , Atwood W. K. , Kohring J. , Brook K. 
Published: December 2007

Abstract
This paper presents the results of an investigation concerning the development of a reliable and accurate technique for establishing the stabilized deliverability performance of multi-layer commingled systems using multirate production log measurements. Both linear and non-linear systems are addressed in this paper, providing a basis for the analysis of reservoirs exhibiting Darcy and non-Darcy flow, respectively.
Extension of the conventional Selective Inflow Performance analysis is also presented in this paper to obtain estimates of the formation and well completion properties such as effective permeability, radial flow steady state damage/stimulation skin effect, and non-Darcy flow coefficient. In the specific case where the deliverability performance of a vertically fractured well is considered, estimates of the effective fracture half-length and average fracture conductivity may be derived from the analysis. In cases where the multirate deliverability tests are performed under boundary dominated flow conditions, conventional deliverability analysis techniques may also be employed to derive estimates of the reservoir drainage area in addition to the well and reservoir parameters that can be obtained in a transient flow analysis. Applications of the analyses reported in this paper demonstrate the use of the analyses to evaluate the inflow performance measurements of commingled multi-layer reservoirs obtained using multi-rate production logs.
Assessment of Oilfield Souring Mechanisms by Mass Spectrometry Analysis of the Stable Sulfur Isotopes Ratio
Authors: Martins M. O. , Marques L.C. C. 
Published: December 2007

Abstract
Reservoir souring is defined as the increase mass of gaseous Hydrogen Sulfide (H2S) per unit mass of produced fluids. Unless the onset of H2S takes place either during the appraisal of the well or in the very early stages of oil and/or gas production, it is not quite straightforward to identify the origin of souring. Under reservoir conditions, H2S is extremely reactive thus being able to react with native H2S-sequestering agents and be converted to metallic sulfides, elemental sulfur or organic sulfur compounds. This phenomenon can account for the delay of the onset of souring in the producer wells.
It is a common practice in offshore facilities to prepare the drilling, completion and work-over fluids using seawater which is rich in sulfate and contains sulfate-reducing-bacteria (SRB). Should these fluids be lost to formation there is potential of (anthropogenic) reservoir souring promoted by these bacteria. In most situations, these fluids have always to bear the blame of reservoir souring (and many other problems). But it is not always correct to blame these fluids, because huge amounts of treated seawater are also injected in the formation (water flooding) for secondary recovery. Besides, H2S may be derived from non-anthropogenic sources. Consequently, a given souring problem may be derived from different sources and the existence of multiple possibilities render the souring identification a kind of difficult sometimes. But, this problem can be solved with the aid of instrumental analytical tools.
The sulfur isotopic ratio (34S/32S) determination by Mass Spectrometry (MS) has been used to identify the H2S genesis, a key to properly address this controversial issue. This paper focuses on the use of this analytical tool to determine the sulfur isotope ratio and, therefore, to identify the source of souring. This paper also presents case histories on the use of MS to address souring problems that took place after workover jobs done in Campos Basin. Some aspects of reservoir souring mechanisms and SRB behavior are discussed as well.
Including Nonisothermal Effects in Models for Acidizing Hydraulically Fractured Wells in Carbonate Reservoirs
Authors: Civan F. 
Published: December 2007

Abstract
This paper presents an improved practical model including the non-isothermal effects involved in the acid stimulation of hydraulically fractured wells. The mathematical model presented here considers a transient-state invasion of acid solution into fractured reservoir formations, dilution of acid by mixing with the reservoir brines, and reaction of acid with the carbonate formation under the effect of the local temperature increase due to the release of the heat of reaction, coupled with the well heat transfer problem. The dissipation of the reaction heat occurs rapidly and increases the acidizing reaction rate according to the Arrhenius law. This is considered in the differential heat balance. The fluid flow is described by means of the material and momentum balance equations in the formation around the fractured well. The model developed here can be facilitated for convenient description of the effect of non-isothermal conditions in acidizing hydraulically fractured wells completed in carbonate reservoirs.
Implications of Linearization in Analytical Modeling of Matrix-Fracture Transfer Functions With Skin Effect
Authors: Rasmussen M. L. , Civan F. 
Published: December 2007

Abstract
This paper investigates the implications of the various linearization schemes considered in the analytical solution of the transient-state nonlinear capillary diffusion equation for derivation of the matrix-fracture-transfer models for naturally fractured petroleum reservoirs. The analysis is carried out by considering a restricted and hindered matrix-fracture interface fluid transfer owing to the finite-skin present at reservoir matrix block surfaces separated with intersecting fractures. The skin is attributed due to the formation of a stationary fluid film or an actual skin because of formation damage by various processes, such as deposition of minerals and other debris, and adverse rock-fluid interactions. The approximation errors associated with the linearization of the nonlinear capillary diffusion model are quantified. It is demonstrated that such errors may be negligible when compared to the uncertainties involved in actual reservoir data. This nevertheless depends greatly on the reservoir rock and fluid properties, and choice of linearization and manipulation methods.
Innovative MPD Techniques Improve Drilling Success in Mexico
Authors: Miller A. , Boyce G. , Moheno L. , Arellano J. , Murillo J. , de la Serna M. Á. A. , Lopez A. U. , Corona Á. M. 
Published: December 2007

Abstract
The Bermudez geological complex includes mature oil-producing fields in the Tabasco State, Southern Mexico. These fields typically produce from underpressured, fractured Cretaceous reservoirs. Similarly, the mature Jujo-Tecominoacán fields are producing from fractured Jurassic carbonate reservoirs.
Drilling the pay zone in these fields with conventional drilling fluids results in lost circulation and associated problems such as differential sticking and poor hole cleaning. Local field experience also has found that drilling with conventional lost circulation materials (LCM) impairs production and causes handling problems when received at production facilities.
Managed-pressure-drilling (MPD) techniques using low-density fluid systems had been capable of successfully addressing the challenges in these fields since 1996. Recently, however, new drilling challenges in highly depleted fractured reservoirs have occurred. These required new advances in MPD techniques, and these innovations have included: High-temperature recyclable foamed drilling fluidHybrid foam/2-phase fluid systems for tapered tubular geometriesFoam bullheading to re-establish circulationMethods to address hole-cleaning challenges in geo-mechanically unstable areas.
This paper will discuss the innovative solutions to the challenges later experienced and the resulting extension of managed-pressure-drilling solutions to meet the specific needs of an integrated services drilling project. Examples will demonstrate how these solutions are improving drilling success for the service company that drilled the wells as well as provided added value to the operator developing the fields.
New Life for a Mature Oil Province via a Massive Infill Drilling Program
Authors: Flores J. G. , Gaviria W. , Lorenzon J. , Alvarez J. L. , Presser A. 
Published: December 2007

Abstract
Breathing new life into a mature oil field is a challenge that has been facing national and private oil companies for almost as long as the oil industry has been in existence. Oil production from mature fields accounts for approximately 70% of the worldwide oil production. Unfortunately, more often than not, mature oil fields equate to high cost and low productivity, making mature fields unattractive when competing for resources with other options in a company's portfolio of investments.
Major opportunities for production optimization in mature oil provinces are typically scarce, more so, if throughout the long lives of the fields nearly all conventional optimization strategies have already been attempted and implemented. The re-development project presented in this and its companion paper1 (SPE 104041) looked at the technical and business opportunities for two main re-development components. The first component aims to beat the natural production decline curve via the implementation of a massive infill drilling program; the second component aims to maintain production levels through the integration of various Improved Oil Recovery (IOR) methodologies.
A multi-disciplinary team studied and recommended the implementation of a massive infill drilling program in a portion of Block 10, operated by Petrobras Energia Peru S.A. in the Talara area of Peru, to improve recoveries in a column of over 2,500 ft of shaly sands, with absolute permeabilities not higher than 1 md and with average well spacing already in the order of 20 Acre. The study included the design of the facilities to process and handle the incremental production.
Analyses confirm that a massive infill drilling program would significantly increase the production in a period of 4 years, from current 3,200 bopd. The study also identified the areas with best potential for infill drilling. Among the sub-products developed in the study were a new production database to facilitate the task of mapping and calculating volumetrics, and a new methodology to estimate average net pay thickness from limited log information. The approach and methodologies developed for this project can be used to give new life to mature oil provinces around the world.
Stability Analysis of Gas Lift Wells Used for Deepwater Oil Production
Authors: Guerrero-Sarabia I. , Fairuzov Y. V. 
Published: December 2007

Abstract
Continuous flow gas-lift wells are susceptible to hydrodynamic instability (heading), which causes cyclic variations of the wellhead pressure, oil and injected gas flow rates. Flow instability is an important issue in the design and operation of continuous flow gas-lift installations used in floating production systems. In such systems, the produced fluids from wells are transported through a flexible riser pipe to the Floating Production, Storage and Offloading (FPSO) vessel. In this paper, the influence of the riser design, the well design, and the gas injection system design on the stability of the production facility is studied. Gas-lift stability maps showing the operational and stability boundaries are presented. The application of different well stabilization techniques in offshore gas-lift installations is discussed.
New Life for a Mature Oil Province via the Integration of Improved Oil Recovery Methods
Authors: Gaviria W. , Flores J. G. , Lorenzon J. , Alvarez J. L. , Presser A. 
Published: December 2007

Abstract
Breathing new life into a mature oil field is a challenge that has been facing national and private oil companies for almost as long as the oil industry has been in existence. Oil production from mature fields accounts for approximately 70% of the worldwide oil production. Unfortunately, more often than not, mature oil fields equate to high cost and low productivity, making mature fields unattractive when competing for resources with other options in a company's portfolio of investments.
The re-development project presented in this and its companion paper1 (SPE 104034) looked at the technical and business opportunities for two main re-development components. The first component aims to beat the natural production decline curve via the implementation of a massive infill drilling program; the second component aims to maintain production through the integration of Improved Oil Recovery (IOR) methodologies.
A multi-disciplinary team studied and recommended the implementation of a program to drill a massive number of infill wells in a portion of Block 10, operated by Petrobras Energia Peru S.A. in the Talara area of Peru, to improve recoveries in a column of over 2,500 ft of shaly sands, with absolute permeabilities not higher than 1 md and with average well spacing already in the order of 20 Acre. A second objective for the study team consisted of evaluating the technical feasibility for a massive waterflood project, including a preliminary design of the surface facilities necessary to collect, process and inject seawater. The third objective consisted of investigating the technical feasibility for miscible gas flooding into an equally tight reservoir, together with the facilities to collect and inject the gas. Both injection projects required consideration of the processing needs for the incremental oil, water and gas production. Traditional optimization technologies were also revisited, including the hydraulic fracturing of the infill wells to attain initial productivity gains of 25% with respect to that of current wells, but without impacting the completion cost.
Based on analytical and numerical analyses, it was found that a massive waterflood would extend the production plateau reached by infill drilling and produce additional reserves. The study also found that to be able to displace oil in the Mogollon formation it would be necessary to inject gas at pressures in excess of 3,000 psi. The approach and methodologies developed for this project can be used to give new life to mature oil provinces around the world.
Fracture Porosity of Naturally Fractured Reservoirs
Authors: Tiab D. , Restrepo D. P. , Igbokoyi A. 
Published: December 2007

Abstract
The storage capacity ratio, ω, measures the flow capacitance of the secondary porosity and the interporosity flow parameter, λ, is related to the heterogeneity scale of the system. Currently, both parameters λ and ω are obtained from well test data by using the conventional semilog analysis, type-curve matching or the TDS Technique. Warren and Root showed how the parameter ω can be obtained from semilog plots. However, no accurate equation is proposed in the literature for calculating fracture porosity.
This paper presents an equation for the estimation of the λ parameter using semilog plots. A new equation for calculating the storage capacity ratio and fracture porosity from the pressure derivative is presented. The equations are applicable to both pressure buildup and pressure drawdown tests. The interpretation of these pressure tests follows closely the classification of naturally fractured reservoirs into four types, as suggested by Nelson1.
The paper also discusses new procedures for interpreting pressure transient tests for three common cases: (a) the pressure test is too short to observe the early-time radial flow straight line and only the first straight line is observed, (b) the pressure test is long enough to observe the late-time radial flow straight line, but the first straight line is not observed due to inner boundary effects, such as wellbore storage and formation damage, and (c) Neither straight line is observed for the same reasons, but the trough on the pressure derivative is well defined. Analytical equations are derived in all three cases for calculating permeability, skin, storage capacity ratio and interporosity flow coefficient, without using type curve matching.
In naturally fractured reservoirs, the matrix pore volume, therefore the matrix porosity is reduced as a result of large reservoir pressure drop due to oil production. This large pressure drop causes the fracture pore volume, therefore fracture porosity, to increase. This behavior is observed particularly in reservoir where matrix porosity is much greater than fracture porosity. Fractures in reservoirs are more vertically than horizontally oriented, and the stress axis on the formation is also essentially vertical. Under these conditions, when the reservoir pressure drops, the fractures do not suffer from the stress caused by the drop. Using these principles, a new method is introduced for calculating fracture porosity from the storage capacity ratio, without assuming the total matrix compressibility is equal to the total fracture compressibility.
Several numerical examples are presented for illustration purposes.
Heavy-Oil Field Development and Reservoir Management Challenges in Producing Onshore Shallow Reservoirs in Suriname
Authors: Kartoredjo H. , Moe Soe Let K. , Nadeson G. , Nandlal B. 
Published: December 2007

Abstract
The Tambaredjo field was discovered in 1968, near the Calcutta village, by a wildcat well C9. A production test was carried out in the appraisal well TA-4, which proved the find to be semi-commercial at the time of the discovery[1].
After the establishment of Staatsolie Maatschappij Suriname N.V., the State Oil Company of Suriname, South America, on December 13, 1980, another well TA05 was drilled and tested in 1981. This well proved the producibility of the field. Oil production started on November 25, 1982 and the production was 250 BOPD from 5 wells. As of May 2006, the average oil production is 13,000 BOPD from 914 production wells in the two fields, Tambaredjo and Calcutta.
The coastal plain of Suriname, together with that of both French Guyana and Guyana, form the onshore part of the Guyana sedimentary basin. Progressively, older beds overlap the basement in northern direction. The reservoirs are of coastal and non-coastal depositional environment (fluvial to shore-face) presenting erratic sand development. Reservoir continuity and heterogeneity within these shallow thin fluvial related sands pose great uncertainty even within a grid drilling of 10 to 30 acres spacing. This is uniquely challenging for field development and reservoir management.
Oil production in Tambaredjo comes from a number of unconsolidated sands, especially the T-sands with thickness from 3 to 45 ft, at average depths of 900 (275 m) to 1200 ft (400m) with a formation temperature of 98°F (37°C). Reservoir pressures are hydrostatic. It has an average porosity and water saturation of 39.0 and 25.0 percent respectively. The oil has a viscosity of 600 cp and an API degree of 17.
Developing and producing this 600 cp heavy oil within thin sand with low reservoir pressure warrants the use of artificial lifting by means of progressive cavity pumps (PCP). This adds to the difficulties of getting valuable wireline survey or subsurface data acquisition.
Reservoir performance prediction utilizing the production data history has always been challenging. Efforts are being made to increase recovery and reserves by applying EOR processes (polymer flood and in-situ combustion) and infill drilling to increase production within these thin sands with high geological uncertainties and early water breakthrough problems. Hence, this paper presents some of these unique challenges in developing, producing and managing these onshore shallow reservoirs in Suriname.