bluuebunny/crossref_metadata_2025 huggingface dataset:
Miscible Gas/Oil Gravity Drainage
Authors: Verlaan M. , Boerrigter P.
Published: December 2007

Oil recovery from oil and mixed-wet naturally fractured reservoirs is difficult. Standard production mechanisms like water injection and countercurrent imbibition will not work. Gas–oil gravity drainage (GOGD) is then the production mechanism of choice. Gravity drainage with immiscible/ solution gas can result in low production rates and/or high residual oil saturation due to capillary holdup.

When the injected gas is miscible with the oil, density and viscosity reduction will occur. Miscibility adds the advantages of single-phase flow and interfacial tension reduction, which further improves GOGD rates and ultimate recovery.

The paper discusses the modeling and upscaling of first contact miscible gravity drainage as well as the differences from regular gas injection processes. The key parameters for this case were identified to be width over height ratio, layering heterogeneity and gas recycling rate. First contact miscible gas injection benefits the most from the IFT reduction and is most suitable in heterogeneous reservoirs with large capillary hold up and re-imbibition effects.
Successful Application of Exploration Lessons Learnt to Deliver Stretch HT/HP Well Delivery Objectives (Krishna Godavari Basin, India)
Authors: Kumar Suresh , Affes Sami
Published: December 2007

Much work has already been undertaken by various operators throughout the industry to explore frontier areas and drill into ever-deeper geological horizons. High pressures and temperatures in the range of 15,000 psi and 450-F need to be handled to safely drill and produce these targeted reservoirs.

This paper illustrates the experience of an E&P operator in the exploration process of a deep Ultra HPHT field offshore east India.
Pressure Monitoring: Key for Waste Management Injection Assurance
Authors: Fragachán F. , Ovalle A. , Shokanov T.
Published: December 2007

The volume of cuttings and produced waste, particularly produced water, will increase as brownfield developments progresses. Missing environmental and economic targets represent a major investment exposure. As a resut, there is an increasing demand on engineering to mitigate process risks and ensure injection and sound subsurface waste management.

This paper describes the outcome of pressure analysis successfully used for Cuttings Re-Injection (CRI) and disposal of produced water resulting from closely monitoring pressure injection and decline. It addresses proper root-cause engineering diagnostic processes that were implemented during abnormal pressures increases and restrictions observed during annulus injection in North Sea projects.

Severe risks were mitigated with injection pressures observed, on occasion above overburden, to maintain safe injection assurance. A methodology was developed and implemented, as a result of process mapping based on signature pressures from pressure decline. Their characterization represents a major step in mitigating risks posed by waste injection, providing not only engineering understanding valuable to overall drilling operations planning, but also minimizing potential environmental impact with sound engineering subsurface waste management.
Outcrop Characterization of Fractured Cretaceous Carbonate Reservoirs, Zagros Mountains, Iran
Authors: Sharp I. , Gillespie P. , Lønøy A. , Horn S. , Morsalnezhad D.
Published: December 2007

Well-exposed outcrops of Middle Cretaceous carbonates in the Zagros fold belt, Iran have been used to provide input data for a dual porosity reservoir model incorporating both matrix and fracture heterogeneity. The modelled outcrop area is located on the steeper dipping limb of a large-scale (10km wide, 100km long) asymmetric Tertiary anticline. The outcrop is structurally and stratigraphically analogous to producing and prospective anticlines in the nearby subsurface.

Matrix heterogeneity can be divided into primary (depositional) and secondary (diagenetic) heterogeneity. Sources of primary heterogeneity include: 1)large-scale depositional architecture (e.g. shelf margin clinoforms, depositional sequence architecture), 2) macrofacies architecture and distribution, e.g. length scale distribution and geometry of carbonate sand shoals and rudist biostromes, 3)microfacies distribution and associated variability in primary pore types. Sources of secondary heterogeneity include diagenetic alteration of primary pore systems, karstification and hydrothermal dolomitisation. We demonstrate a close link between primary heterogeneity and secondary porosity-permeability distribution in the matrix.

To construct the outcrop model, vertical stratigraphic logging and sampling were undertaken to establish a synthetic well log from which reservoir architecture, zonation, facies, microfacies, pore-type, and porosity-permeability data could be derived. "Walking-out" of depositional and diagenetic elements captured horizontal and vertical correlation length scales of porosity-permeability distribution and architectural features.

The main fractures present are normal faults and joints. Faulting was characterized using measurements of fault kinematics, orientation, displacement, length, fault zone thickness and fault zone petrology. The normal faults are nonstratabound and have power-law scaling. Faults were stochastically simulated in a discrete fracture network and then scaled up to a reservoir simulation grid. Resulting porosity-permeability distributions are highly heterogeneous.

Joints are stratabound and have an almost constant density within the same stratigraphic horizon, regardless of outcrop location (e.g. fold limb vs fold crest). In contrast, joint density varies greatly vertically according to lithology/facies. Joints were modelled using a simple parallel plate model approximation. Permeability due to joints is highly heterogeneous vertically, but laterally homogeneous.

Construction of the outcrop model has been key to reducing uncertainty in geological interpretation and modelling of subsurface data, in particular with regard to characterization of porosity-permeability distribution and in interpretation of test data. The modelling workflow presented in this paper is directly relevant to producing and prospective fractured Middle Cretaceous carbonate reservoirs elsewhere in the Middle East and in Mexico.
Decline Curve Analysis of Fractured Reservoirs With Fractal Geometry
Authors: Camacho-Velázquez R. , Fuentes-Cruz G. , Vásquez-Cruz M.
Published: December 2007

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

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

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

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

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

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

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

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

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

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

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.
Gelation Kinetics of an Organically Cross-Linked Gel at High Temperature and Pressure
Authors: Al-Muntasheri G. A. , Nasr-El-Din H. A. , Zitha P. L. J.
Published: December 2007

Due to their thermal stability, organically cross-linked gels have been used to control water production in high temperature applications. Most of these gels consist of a polyacrylamide-based polymer and an organic cross-linker. Polyethyleneimine (PEI) has been used as an organic cross-linker for polyacrylamide-based copolymers.

Recent work indicated that PEI can form ringing gels with polyacrylamide homopolymers (PAM). However, no study reported on the kinetics of PAM/PEI gels. The gelling system examined in the present study is based on a PAM cross-linked with PEI. This paper will show for the first time the possibility of cross-linking polyacrylamide with PEI at high temperatures and pressures.

Therefore, the gelation time of the PAM cross-linked with PEI at high temperatures up to 285°F (140°C) and pressures up to 435 psi (30 bars) was measured. The effects of polymer concentration, cross-linker concentration, temperature, salinity and the initial degree of hydrolysis of the polymer on the gelation time were examined in detail. All measurements were conducted in the steady shear mode at low shear rates using an Anton-Paar high temperature/high pressure viscometer. C13 Nuclear Magnetic Spectroscopy (C13 NMR) was extensively used to relate gelation time to changes in the structure of the polymer and hence, explain the variation in the gelation time in terms of the system chemistry.

Thermally stable gels were obtained by cross-linking PEI and PAM at high temperatures (120°C) for at least 2 weeks. The activation energy of this system at high temperatures in distilled water was found to be 71.3 kJ/mol. The addition of sodium ions increased the activation energy to 88 kJ/mol.
Log Data Preparation: A Real Opportunity To Save Money and Time
Authors: Barbato R. , Quaglia A. , Porras J. C. , Panesso R. , Soria J.
Published: December 2007

In spite of new or old planning philosophies, log data preparation has been overlooked by a lot of players in the oil business. We are not speaking about conventional data preparation, such as depth shifting, normalization or editing, for these are very well taken care of in most projects. We want to go a step back. We are talking about the initial phase, even previous to vectorización. Well logs have a large variety of users but each of them has different needs and use different parts of the logs with different goals. Doing a gross generalization, Petrophysicists will go after most curves, use detailed-scaled logs (1:200), and concentrate in the reservoir area; geologists will usually go for SP, GR, resistivity and porosity logs in a reservoir-to-formation scale, using intermediate to large scale logs (1:500 and 1:1000); geophysicists mostly use large scales (1:1000 to 1:5000); and drillers use 1:10.000 or larger scales and mostly GR, density and sonic logs; and so on.

If the original digital data exists, every one will be happy, but if only analogical data exist, problems will rise because every specialist will try to get what he or she needs as fast as possible and with the quality that he or she needs without taking into account the needs of other specialists or the organization mid-to-long term needs. No one can blame them since there are deadlines and goals to achieve, but for the next project in the same area it will happen again….and again….and again. At the end the logs are digitized using completely different approaches leading to a chaotic mosaic of pieces of logs that do not match anyone's final needs, the data base becomes a mess and all upcoming projects will always have problems with log data.

In this work, a FRONT END LOADING approach is proposed and applied, leading to a group of specifications and best practices to be used as guidelines in well log preparation for Reservoir/Field/Asset/Corporation well log databases. The application of these guidelines will satisfy the needs of any well log user, optimize database management and improve the productivity of project teams. These best practices are supported by years of time-saving and technical improvements in a large numbers of projects. Time and money invested at the beginning of the projects will become even larger time and money savings at the long run.
Calibration of Parameters Used in the Processing of Nuclear Magnetic Resonance Data, Acquired in Heavy- to Extraheavy-Oil Reservoirs, by Integrating Core, Production, and Conventional Log Data With Magnetic Resonance Data—Orinoco Belt, Eastern Venezuela
Authors: Hernandez H. , Odreman J. , Moya Y. , Tineo F.
Published: December 2007

Permeability, fractional porosities, irreducible water saturation and fluid viscosity calculations, derived from Nuclear Magnetic Resonance (NMR) data, are largely dependant on T2 decay rates (in NMR terminology, T2 is the time constant that characterizes the decay rate of the echo train).

NMR models show that the T2 of oil is directly proportional to porosity and permeability and inversely proportional to viscosity. As oil viscosity increases, T2 decreases and the NMR signal of heavy oil may coincide with the clay bound and capillary bound water signals or even be much faster. Therefore, conventional parameters and cutoffs, used in the calculations of petrophysical properties, generally cause underestimation of porosity and permeability.

By integrating core, production and conventional log data with NMR data it will be able to determine appropriate parameters and cutoffs and also generate a model to be used in the calculations of petrophysical properties from NMR data.

The correct parameters, cutoffs and generated model can later be used to process NMR data from other wells where core and or production data is not available.
Sand Mapping Using Multiwavelet Seismic Trace Decomposition and Reconstruction
Authors: An Ping
Published: December 2007

A seismic trace is decomposed into a set of Ricker wavelets of different dominant frequencies and amplitudes. The seismic trace can then be accurately reconstructed with all the wavelets in the set of wavelets. With certain targeted objective in mind, a new seismic trace can be reconstructed with a selected subset of the wavelets. This reconstruction is found very effective in reservoir sand mapping and characterization. Some examples are demonstrated.
Sanding—Not as it First Appeared
Authors: Abulsayen Ahmed , Enneamy Abdulwahab , Qiu Kaibin , Marsden Rob , Alexander Joe , Safdar Muhammad
Published: December 2007

This paper described a case study involved an investigation in a field in Libya, where massive unexplained fill had been reported accompanying obstruction of production for majority of production wells since the onset of production, indicating possible sanding issues for this field.

To investigate this problem, relevant data from different sources and different domains (i.e., wireline logs, laboratory test data, drilling data, well data and field data) were integrated to generate a Mechanical Earth Model (MEM). This model provided the descriptions of the rock strengths and in-situ stresses in the reservoir formation. Somewhat surprisingly, the model, backed up by the core laboratory test data, observations from core inspection and thin section analyses, revealed the rocks to be extremely hard and strong, and therefore highly unlikely to sand. These findings contradicted with initial impression and previous expectation on this sandstone that it should have been sand-prone formation. Facing these apparent inconsistencies, the investigation moved beyond an initial focus of sanding risk evaluation and sandface completion optimization. The final results revealed that the problems facing the field were other than conventional sanding and formation failure, and that they involved some rather interesting and misleading phenomena, such as precipitation of salt from production, tubing scale, spalling of borehole wall with drawdown and cavings bridge (cavings might fall into and become wedged in the openhole, forming a bridge with no material beneath).

The investigation concluded that installing sand control facilities were unnecessary, which otherwise would have cost millions of dollars without correctly addressing the real problem that this field was facing. The study highlighted the importance of a thorough investigation of the mechanism and source of sanding rather than premature conclusions based initial, and potentially misleading evidence. It also highlighted how the integration of information from different sources and disciplines were able to correctly identify and address a particular borehole fill problem, allowing for optimizing field operations, field management and workover strategies.
Correlations to Predict Frictional Pressure of Hydraulic Fracturing Slurry in Coiled Tubing
Authors: Shah Subhash , Zhou Yunxu , Bailey Michael , Hernandez John
Published: December 2007

Compared with conventional tubing fracturing, coiled tubing (CT) fracturing has several advantages. CT fracturing has become an effective stimulation technique for multi-zone oil and gas wells. CT fracturing is also attractive production enhancement method for multi-seam coalbed methane wells as well as wells with bypassed zones. The excessive frictional pressure loss through CT has been a concern for CT fracturing. CT strings have small diameter and this limits the cross-sectional area open to flow. Furthermore, the tubing curvature causes secondary flow and hence results in extra flow resistance. This increased friction pressure results in high surface pumping pressure. The maximum possible pump rate and sand concentration, therefore, have to be reduced. To properly design a CT fracturing job, it is, therefore, essential to be able to predict the frictional pressure loss through CT accurately.

This paper presents two correlations for the prediction of frictional pressure of fracturing slurries in coiled tubing. One is developed based on full-scale slurry flow tests with 1-1/2-in. coiled tubing and slurries prepared with 35 lb/Mgal guar gel. The extensive experiments were conducted at the full-scale coiled tubing flow test facility. The other correlation is derived from the Srinivasan's friction factor correlation of Newtonian fluid in coiled pipes. The Srinivasan correlation is modified for the non-Newtonian fluids and it further requires an inclusion of the relative slurry viscosities which have been thoroughly evaluated in this study. The proposed correlations have been verified with the experimental data and actual field CT fracturing data. Case studies of wells recently fractured using CT are provided to demonstrate the application of the correlations. The correlations will be useful to the CT engineers in their hydraulics design calculations.
Nanologging: Use of Nanorobots for Logging
Authors: Singh Pratyush , Bhat Sumit
Published: December 2007

The idea of nanotechnology if applied in any of the technological fields will put LWD and MWD as outdated technology and can prove to be a boon for the next technical revolution. Already postulated to be effective in medical science such as destruction of disease causing bacteria or drug targeting, the nanorobots could be used for logging purpose by circulating these nanorobots, which have nonomotors being driven by the ions in the mud or by mud circulation system. Expensive wireline tools are conventionally used in all types of wells to find important formation properties. I have come up with an idea of nanorobots for oil field logging. Nanorobots can eliminate use of these tools, entirely and small particles of order of nanocentimeter can be put in the drilling mud to obtain useful information. These robots equipped with nanosensors could be used to measure various properties of formation, borehole environment, mud properties and many more. Nanorobots can be constructed in a manner so that they possess sensors, on-board driving mechanism and microcomputer as well as interface mechanism from where it can send instructions to microcomputers from surface computers. Transmission to surface is by means of electromagnetic waves and detected by means of probes on surface. They facilitate wire-less communication and real time surveillance. Thus in comparison to the conventional logging they can save rig hours and can be more accurate and precise as compared to presently used techniques like logging while drilling and measurement while drilling. They can move with circulating mud or they can be made to propel or stop by the on-board computer instructions depending upon the measurement to be taken. They will also be able to invade the formation and get important petrophysical parameters.
A Permeability Model for Coal and Other Fractured, Sorptive-Elastic Media
Authors: Robertson Eric P. , Christiansen Richard L.
Published: December 2007

This paper describes the derivation of a new equation that can be used to model the permeability behavior of a fractured, sorptive-elastic media, such as coal, under variable stress conditions commonly used during measurement of permeability data in the laboratory. The model is derived for cubic geometry under biaxial or hydrostatic confining pressures. The model is also designed to handle changes in permeability caused by adsorption and desorption of gases from the matrix blocks. The model equations can be used to calculate permeability changes caused by the production of methane from coal as well as the injection of gases, such as carbon dioxide, for sequestration in coal. Sensitivity analysis of the model found that each of the input variables can have a significant impact on the outcome of the permeability forecast as a function of changing pore pressure; thus, accurate input data are essential. The permeability model can also be used as a tool to determine input parameters for field simulations by curve-fitting laboratory-generated permeability data. The new model is compared to two other widely used coal permeability models using a hypothetical coal with average properties.
Interwell Heterogeneity Analysis by Dynamic Correlation Method
Authors: Liu Mingxin , Liu Y. Z. , Guo Tongcui , Cai Lei
Published: December 2007

A method was tried to analyze interwell heterogeneity economically and conveniently by correlation of injection and production data. The basic idea of this method is that the fluctuations of injection rate of injector and production rate of producer can be regarded as lines of wave changing with time. A correlative coefficient is used to estimate the correlation between the two lines of waves.

Taking a group of injection production wells as a study unit, centered on injection well unit, we calculate the correlative coefficient of performance parameters between production well and injection well in "correlative time window", using the correlative coefficient to reflect the relative extent between the two lines of waves.

We study the reservoir in the following aspects according to correlativity and the delay time when the correlative coefficient reaches best: (1) correlative coefficient was used to distribute the injection rate, and to analyze the effect between injection rate and production rate. (2) The delay time is the effective response time for water flooding when the correlative coefficient reaches best, then we can determine which well has little effective response time, and which well is the main flow direction of injection well flow to. Only if the delay time is zero, can there be obvious flee channels between production well and injection well. (3) The analysis of the reason for minor production, output reducing and lack of injection (4) Evaluation of formation interconnection and identify big pore wormhole. This method has been made into software, it has visual operation interface, which is easy in operation and studying. The diagnostic example of big pore wormhole in china oilfield made an excellent agreement with the tracer result.
Steamflood Trial and Research on Mid-Deep Heavy-Oil Reservoir QI40 Block in Liaohe Oilfield
Authors: Jiuquan An , Li Ji , Jiang Hua
Published: December 2007

In the paper, the implementation process and results of the pilot tests and expanded tests of steam drive in Block QI40 in Huanxiling Oil Recovery Plant of Liaohe Oilfield is analyzed, the patterns and production features of steam drive in moderately deep, medium ~ thick interbedded conventional heavy oil reservoirs after steam huff and puff are studied and the supporting technologies developed during the steam drive in Block QI40 are outlined together with the problems solved by the technologies. Valuable knowledge and experience have been obtained in terms of heavy oil steam drive in moderately deep formations. At the same time, it has been proved that satisfactory development results and reasonable economic benefits can be obtained when steam drive is applied to the moderately deep heavy oil reservoirs after many cycles of huff and puff, providing reliable operational experience and technical support for the commercialization of steam drive in Block QI40 and similar oilfields.
Pioneer Application and Promising Future of Horizontal Water-Injection in China
Authors: Fang Jie , Jia Chengzao , Li Baozhu , Luo Kai
Published: December 2007

The horizontal water injection is utilized in some oilfields worldwide. The successful practices show that horizontal water injection can enhance the injectivity. Especially for the fields in high water-cut stage, horizontal injection can improve the reservoir pressure maintenance level, sweep efficiency, recovery, and achieve good economic benefit. Applications in an oilfield in West China demonstrate that horizontal injection can raise the water injection volume, improve the sweep efficiency. This is the first pioneer case that adopts horizontal injection fieldwide, showing the promising future of horizontal injection in China.
The Research on Asphaltene Deposition Mechanism and Its Influence on Development During CO2 Injection
Authors: Ying Jia , Lei Sun , Liangtian Sun , Lei Huang , Chunxia Huang , Lin Hong
Published: December 2007

Based on high pressure physical property experiments, such as swelling experiment, multi-contact experiment and asphaltene precipitation experiment et al, thermodynamic characteristics of asphaltene precipitation during CO2 injection have been analyzed comprehensively with numerical simulation, which make up the deficiency of analyzing physical and chemical parameters with experiments; adsorption and plugging of asphaltene on rocks and rheology characteristic of oil containing precipitated asphaltene have been studied; the influence of asphaltene deposition on reservoir have been researched; Found on above-mentioned study, the mathematic flow model considering asphaltene deposition has been established. Take one oil field in our country as example, the influence of asphaltene deposition on production dynamics during CO2 injection has been researched. The results were in agreement with field observation and history data, which can be efficient for the further production prediction.