bluuebunny/crossref_metadata_2025 huggingface dataset:
Evaluating Resource Plays With Statistical Models
Authors: Hall Russell K.
Published: December 2007

The purpose of this paper is to help you, the evaluating engineer, understand the assumptions and procedures used to estimate probabilistic reserves using numerical simulation. More specifically, we will examine Monte Carlo predictions in resource plays. Throughout this paper, I assume that you are a bright petroleum engineer well versed in the traditional methods of estimating reserves such as decline curve, volumetric, and material balance analysis, but you are relatively unfamiliar with numerical simulations and probabilistic reserve estimates. This paper discusses some of the basic concepts of Monte Carlo modeling with a particular emphasis on the underlying assumptions. The paper offers some definitions to help identify resource plays and the assumptions used to forecast reserves and performance. The techniques of Monte Carlo simulation are then applied to various resource plays to estimate probabilistic reserves.
Screenless Completions as a Viable Through-Tubing Sand Control Completion
Authors: Wise M. R. , Armentor R. J. , Holicek R. A. , Gadiyar B. R. , Bowman M. D. , Jansen R. A. , Krenzke S. N.
Published: December 2007

Screenless sand control completions provide a cost-effective means of completing wells in the Gulf of Mexico by eliminating the need to have a rig on location. To date, six screenless completions have been performed for a major operator in the Gulf of Mexico. Each of the six treatments provided significant cost savings, as well as excellent return on investment for the operator.

Screenless completions are an integrated solution that involve many field-proven technologies such as reservoir characterization, perforating, coiled-tubing intervention, matrix acidizing, resin consolidation, optimized fracturing with proppant flowback control, and fines migration prevention. The proper candidate selection, treatment design, treatment execution, production management and co-ordination of all services are essential to the success of the screenless completion.

In this paper, the common sequence of events for a screenless completion is presented as well as the key technologies involved, from perforating to production. Each of the six case histories are examined in detail and will show that screenless completions provide effective through-tubing sand control in a variety of well conditions. Screenless completions have been proven effective in reservoirs from 10 to 60 ft in thickness, at depths from 4,000 to 10,500-ft true vertical depth, in casings from 3-1/2 to 9-5/8-in. and in oil and gas reservoirs at rates of up to 600 BOPD, 1750 BFPD or 3.5 MMSCFD and in wells deviated as high as 42o. The technique can also be applied in different wellbore configurations to target pay behind casing, and also zones that are located behind both tubing and casing.
Quantitative Analysis of Reaction Rate Retardation in Surfactant-Based Acids
Authors: Nasr-El-Din H. A. , Al-Mohammed A. M. , Al-Aamri A. D. , Al-Fahad M. A. , Chang F. F.
Published: December 2007

Fracture acidizing has been a dominant practice in the industry to enhance well productivity in low permeability carbonate reservoirs. Many acid systems have been developed to improve this stimulation process. The most desirable characteristics for an acid system to be suitable for fracture acidizing are leakoff control and retarded reaction rate. These characteristics are required for deep acid penetration so that when fracture closes, long flow channels are etched on the fracture surfaces. Leakoff control is normally achieved by a pad containing viscosifying or solid bridging agents to plug wormholes generated by acid dissolution. Reaction retardation is normally attempted by lowering the effective diffusivity of hydrogen ion.

It is well known that during an acid fracturing operation the overall reaction rate of hydrochloric acid with limestone is mass transfer limited. Designing the treatment requires knowing the effective diffusivity of the acid fluid system. This parameter does not exist for viscoelastic surfactant gelled acids. Due to its combined leakoff control and retardation capabilities, surfactant-based acids have been used in acid fracturing treatments. As more carbonate reservoirs to be treated by the surfactant-based acid, it is important to obtain the effective diffusivity of H+.

The rotating disk device has been used to investigate the reaction kinetics between a reactive solution and carbonate rocks because the thickness of the boundary layer is uniform throughout the disk surface. This paper discusses the reaction rate data recently generated for surfactant-based acid using a rotating disk apparatus and presents the methodology used to quantitatively extract the effective diffusivity from the measurements.

The results obtained indicated that the viscoelastic surfactant examined (Betaine-type) reduced the dissolution rate of calcite with HCl acid. The surfactant reduced the diffusion coefficient for H+. The effect of temperature on the diffusion coefficient did not follow Arrhenius law.
Evaluation of Formation Damage of Turkish Southeastern Reservoirs Caused by Drilling Fluids
Authors: Iscan A. Gurkan , Turkse N. V. , Kok Mustafa V. , Strauss Heike
Published: December 2007

One of the major reasons of reservoir formation damage is fines migration during drilling operations. In this paper, three different water-based drilling fluids were used to test permeability reduction ratio with Turkish South Eastern sandstone and limestone core samples using a dynamic drilling fluid circulation system. The drilling fluids were prepared due to API specifications with non-treated bentonite fluid, Polymer-XT and PAC –XC at 11 different differential sticking pressures. The core plugs were saturated with brine after being vaccuumed and initial permeabilities were measured. After the circulation of drilling fluids for two and three hours, return permeabilities were measured from the other end of the cylindrical core plugs. The permeability reduced due to the invasion of the fines particles into the core plugs. The damage ratio concept was used for permeability reduction analysis as the ratio of the difference between final and initial permeability to initial permeability. The limestone core samples gave out the minimum damage ratio with the fluid including PAC-XC at a permeability damage ratio of 32% whereas sandstone core plugs resulted in 46% damage ratio. The highest damage ratio with non-treated bentonite fluid was obtained with sandstone core plug as 78.4 %. The optimum drilling fluid sustaining the least formation damage was determined. An exponential correlation relating damage ratio and filtration pressure was applied to the experimental data. The experimental and correlated results match accurately with each other. The correlation equation was linearized by taking natural logarithms of the both hands sides of the correlating equation. Correlation coefficients for each drilling fluid were determined. High regression coefficients around 0.90 were obtained. This correlation enables the determination of further damage ratios at different filtration pressures for sandstone and limestone core plugs.
Borehole Stability (Geomechanics) Modeling and Drilling Optimization Practices Improve Drilling Curves in Naturally Fractured Shale—A South Argentina Experience
Authors: Fontana Horacio , Paris Martín , Ong Seehong
Published: December 2007

Borehole instability related problems due to massive formation caving in micro-fractured shale resulted in substantial non-productive times (NPT) and accounted for as much as 25% of the total programmed drilling time.

Geomechanics and image log analyses clearly showed the natural/micro fractures were responsible for large cavings. Drilling optimization strategies to mitigate formation caving were focused on:

Reducing mud weight to decrease fluid/pore pressure penetration in fracture planes Use of mud additives to seal-off natural fractures Drilling with downhole motor and stabilizers to minimize lateral vibrations.

Average drilling time prior to implementing these strategies was 14.75 days. The drilling time improved to 8.18 days after the implementation, an improvement of 44.5% with no occurrence of major instability events.

This paper will present a case study from an oilfield in Southern Argentina demonstrating how the assimilation of geomechanics modeling and drilling optimization practices is critical to improving the drilling curves.
Black-Oil Simulations for Three-Component – Three-Phase Flow in Fractured Porous Media
Authors: Geiger S. , Matthäi S. , Niessner J. , Helmig R.
Published: December 2007

Discrete-fracture modeling and simulation of two-phase flow in realistic representations of fractured reservoirs can now be used for the design of IOR and EOR strategies. Thus far, however, discrete fracture simulators fail to include a third compressible gaseous phase. This hinders the investigation of the performance of gas-gravity drainage, water alternating gas injection, and blow-down in fractured reservoirs.

Here we present a new numerical method that expands the capabilities of existing Black-Oil models for three-component – three-phase flow in three ways: (i) It utilizes a finite element - finite volume discretization generalized to unstructured hybrid element meshes. (ii) It employs higher-order accurate representations of the flux terms. (iii) Flash calculations are carried out with an improved equation of state allowing for a more realistic treatment of phase behavior.

We illustrate the robustness of this numerical method in several applications. First, quasi-1D simulations are used to demonstrate grid convergence. Then, 2D discrete fracture models are employed to illustrate the impact of mesh quality on predicted production rates in discrete fracture models. Finally, the proposed method is used to simulate three-component – three-phase flow in a realistic 2D model of fractured limestone mapped in the Bristol Channel, U.K. and a 3D stochastically generated discrete fracture model.
NAF Filtercake Removal Using Microemulsion Technology
Authors: Quintero Lirio , Jones Thomas A. , Clark David E. , Twynam Allan
Published: December 2007

Traditional chemical methods for removal of non-aqueous fluid (NAF) filter cake and internal formation damage use acids, solvents and mutual solvents mixed in clear brine. In some cases, this conventional technology gives good results; but, in other instances, the results can be disappointing.

A new generation of single-phase microemulsion stimulation fluids has been developed for removal of filter cake and formation damage in wells drilled with NAF systems. The development work included the design of microemulsion formulations, determination of the destruction rate of the filter cake with additives that prevent massive completion fluid losses, and evaluation of return permeability for injector and production wells.

The driving mechanism of this technology is to obtain a near-zero free energy state between the novel microemulsion and the NAF filter cake or damaged formation face which promotes incorporation of the oil into the microemulsion and spontaneously reverses the wettability of the filter cake particles, disaggregating them so they are no longer damaging. The laboratory results described in this paper show that the novel microemulsion design delays its spontaneous action long enough to permit well completion operations without experiencing massive losses to the formation. Permeability data obtained demonstrate that this new technology is highly effective for enhanced water-injection and productivity.
Proven Synergistic Approach in Well Cementing Across Thief Zones: East Venezuela
Authors: Tranquini N. , Soto J. , Reveth V. , Prato L. , Williams H.
Published: December 2007

Drilling operations for several operators in East Venezuela are increasing in complexity each year. Many challenges are encountered while drilling across weak formations with considerable variability in lithology and pore pressure. A narrow drilling window between formation pore and fracture pressures has become one of the main concerns for the operator. Primary cement placement faces similar challenges when placed across weak formations.

New producing zones are currently being targeted in deeper sandstone formations and a variety of loss circulation issues are encountered. For example, in the Tacata field, lost circulation is occurring across a series of depleted zones located above the producing zone. In the Orucual field, losses were observed immediately below the producing zone. From the wells observed in this study, losses were observed most frequently under slim-hole conditions and low fracture pressures. In these wells, combinations of demanding well and formation parameters have made it more difficult to achieve successful cement placement. Minimizing losses during cement placement, achieving predicted top of cement (TOC) and reliable zonal isolation are current challenges in East Venezuelan fields.

The need to improve conventional lost circulation approaches during well drilling and cementing was determined by service company and operator field experience and dynamic cement placement simulations. A high performance light weight (HPLW) slurry was recommended along with an engineered fiber material (EFM) to avoid losses by reducing the hydrostatic pressure in the annulus and artificially increasing the fracture pressure of the thief zones during placement.

From several case histories, the synergy between HPLW and EFM approaches resulted in improved zonal isolation, less reservoir damage and cost savings by avoiding remedial cementing and non productive time (NPT).
Trust-Region Approach To Find Constants of Bourgoyne and Young Penetration Rate Model in Khangiran Iranian Gas Field
Authors: Bahari A. , Seyed A. Baradaran
Published: December 2007

Up to now, authors have proposed several drilling rate models. Bourgoyne and Young model represents a general relation between penetration rate and some drilling variables. In this model, there are eight constants, which are dependent to the formation type and must be found from previous drilling data. Bourgoyne and Young recommended multiple regression method to solve these eight unknowns but this method is limited to the number of data points and recommended ranges for drilling parameters. In this research, by writing a computer program, three other mathematical methods were applied on nine wells data of Khangiran gas field to find each formation constants. Results of applied four methods were compared to each other and it was found that trust-region method is the best mathematical method to find Bourgoyne and Young penetration model constants and in many situations, results of other three methods were not meaningful. Since, this method has not limitations of recommended method, it can be applied easily to predict penetration rate when e few data points are present and when drilling parameters are not in the recommended ranges.
Analyzing Transient Pressure From Permanent Downhole Gauges (PDG) Using Wavelet Method
Authors: Shi-Yi Zheng , Xiao-Gang Li
Published: December 2007

Reservoir pressure monitoring during its production life is to evaluate its performance to ensure the effective extraction of hydrocarbon from the reservoir. Continuous reservoir monitoring offers a window of prospects to increase well productivity, while reducing operating costs through an improved and more accurate well performance. These are achieved through analyzing the long term, real time, dynamic transient pressure obtained from Permanent Down-hole Gauges (PDG), which will provide input and vital information for improving the existing reservoir model for flow simulation.

Reservoir monitoring during field development can amplify the understanding of the reservoir depletion, compartmentalization, and efficiency of water injection, also the presence of any flow barriers (such as activated fault). On this basis, reservoir management can be more accurate and realistic.

In contrast to the data obtained from the traditional well test such as DST, pressure data from PDG is large in quantity (long term up to six years), noisy, multiple phase flow and multiple rate. The key for the analysis of such data set to extract reservoir information is to develop a technique in handling the data, i.e. to make the data analyzable but not losing the true information contained in the data.

This paper presents techniques using wavelet transform method for such purpose. These have been developed recently through an industry sponsored research Project. The procedures include PDG data visualization, de-noising, smoothing and "break point" (due to drop of rate and well shut-in) identification through analyzing field examples provided by the sponsors. After this process, transient pressure data (extracted drawn-down and build up) can then be analyzed using current traditional methods and software. The analysis results such as skin factor and reservoir effective permeability can be evaluated in a time lapse fashion to reveal information about the dynamic changes of the reservoir.
Evaluation of In-Situ Generated Acids for Filter-Cake Cleanup
Authors: Nasr-El-Din H. A. , Al Moajil A. M. , Al-Aamri A. D.
Published: December 2007

Filter cake removal is a difficult task, especially in horizontal and extended reach wells. Water-based drilling fluids consist of xanthan gum as a viscosifier, starch as a fluid-loss control, sized calcium carbonate or salt particles to increase the mud density. Conventional chemical means used to remove filter cake are reactive mineral acids, enzymes, chelating agents, oxidizers, or combinations of these chemicals. Controlling of the reaction rate of the cleaning fluids with the filter cake material is an essential factor that determines the efficiency of filter cake removal.

This study assesses the performance of three acid precursors (esters) that produce organic acids. These precursors produce low-molecular weight organic acids that can dissolve calcium carbonate particles from the filter cake. The rate of hydrolysis of acid precursors can be adjusted to produce a predetermine acid concentration at bottom hole conditions. Enzymes, mainly α-amylase, can be added to these esters to break starch that is present in the filter cake. The slow release of these weak organic acids ensures proper and efficient removal of the filter cake.

Lab studies using static HPHT filter press indicated that the three systems can remove the filter cake efficiently. The rate of hydrolysis was measured for each system, and found to be a function of temperature and type and concentration of the acid precursor. Surface tension measurements conducted for solutions of the three precursors at different temperatures highlighted low surface tension values for the spent acids, which are needed to lift the spent acid following the treatment.

No phase separation or precipitation was observed when the three systems were heated at temperatures up to 250°F. Surface tension measurements indicated that the formic acid system had low surface tension, which will accelerate lifting these fluids from tight formations. Acetic and lactic acid systems had much higher surface tension, and a suitable surfactant will be needed to reduce the surface tension. The kinetic study indicated the very rapid reaction rate of the precursor of formic acid and a moderate reaction rate in the acetic acid system. The reaction rate of the precursor of lactic acid was in between the two systems and more close to the in-situ acetic acid system.

HPHT experiments showed that formic acid system was very efficient at short soaking times at temperatures of 200 and 250°F. The performance of lactic acid was comparable to formic acid when the soaking time was increased from 4 to 6.75 hrs. The efficiency of acetic acid was much lower than the other two acids. Acetic acid will require much longer soaking times.
Development of New Retarder Systems To Mitigate Differential Cement Setting in Long Deep Liners
Authors: Al-Yami A. S. , Al-Arfaj M. K. , Nasr-El-Din H. A. , Jennings S. , Khafaji A. , Al-Ariani M. , Al-Humaidi A.
Published: December 2007

When cementing liners, the cement must develop compressive strength at the top of the liner before drilling is resumed. If drilling is delayed in order to acquire the compressive strength at top of the liner, it can result in excessive delays on cement (WOC) time which can exceed 24 hours. Cement slurries with conventional retarders often achieve acceptable thickening times under dynamic conditions. Sometimes these cement slurries do not produce rapid compressive strength under static conditions. The aim of this study is to develop optimized retarder systems for cements that are exposed to BHST of 400 °F at the bottom of liner (BOL) and 330 °F at the top of the liner (TOL).

More than ten retarders including lignosulfonate, ethylene glycol, and aromatic polymer derivatives were evaluated to provide extended thickening times for extreme high temperature cement slurries, while having minimal effect on sonic strength development. The lab studies included comparison between various retarders and their performances of thickening time, sonic strength development, free water, fluid loss, rheology, and gas migration control.

Two new retarded systems were developed. The first system is used for non-latex cements for wells that do not show indications of gas or fluid flow. The second cement system includes latex and is recommended for cases where there is potential for gas migration. The new retarder systems were effectively applied in the field. The paper will address lab studies that led to the development of new retarders.
Evolutionary Optimization of Oilfield Development
Authors: Túpac Y. J. , Faletti L. , Pacheco M. A. C. , Vellasco M. M. B. R.
Published: December 2007

This work presents the development and evaluation of a hybrid intelligent system to optimize oil fields development. This system employs the following techniques: evolutionary algorithms to optimize the positioning and characteristics of wells in a reservoir; distributed processing to perform simultaneous reservoir simulations; function approximation models as simulator proxies; and quality maps to use some reservoir information to improve the optimization process.

This work represents the first stage in the application of modern methodologies for the analysis of alternatives of oil field development under uncertainties, where no uncertainties are considered. In this sense, the optimization consists in finding wells positioning, type and geometry in a delimited petroleum field, in order to maximize the NPV of alternative, considering some technical constrains as the minimum wells distance and maximum wells trajectory.

The problem approached in this work is considered of up most importance and it is recognized as a complex optimization problem, since the benefit of the option to develop an oil field depends on investments which in turn depend on the alternative chosen. The combination with other aspects makes this problem even more complex, yet properly optimized by Evolutionary Algorithms.
A Pore-Scale Network Modeling Study of Gravitational Effects During Solution Gas Drive: Results From Macroscale Simulations
Authors: Bondino I. , Long J. , McDougall S. R. , Hamon G.
Published: December 2007

Although experimental work for solution gas drive processes is routinely carried out and interpreted for the purpose of defining critical gas saturations and relative permeability data, developing a thorough understanding of the results to facilitate confident application to the field is a hard task. Unfortunately, existing macroscopic models are unable to reproduce or take into account several different features of solution gas drive experiments. For example: (i) the impact of outlet boundary conditions upon the formation of saturation gradients, and (ii) transitions between different flow regimes (disconnected immobile gas, disconnected mobile gas, continuous gas flow) that are characterized by different pore-scale dynamics. These features can be considered using pore-scale modeling techniques. However, such microscopic applications, even in the few cases where they are refined enough to include viscous or gravitational forces, have perhaps their greatest limitation in the number of pores that can be simulated. This consequently makes it virtually impossible to simulate flow regimes that are not capillary dominated at an appropriate physical length scale.

In this work a pore scale network modeling approach is presented which is capable of reproducing gravitational effects during oil depressurization through simulation in samples of macro-scale height. The models used comprise several hundred thousand pore elements. The primary objective is to fully simulate the physical height of routinely used laboratory samples, in this way reproducing the real scale and pressure dependent balance of forces: this allows us to show how the ratio of gravity to capillarity changes in relation to the rates of depletion (bubble densities), the rock, the fluid properties and the scale of the sample, and how this contributes to affect relative permeabilities and critical gas saturations. In particular it is shown that relative permeabilities can be predicted according to the particular flow regime operating during a given experiment (dispersed and/or continuous). Moreover we show that flow is largely determined by the size and density of gas clusters, whether originating from nucleation or from break-up of larger structures during migration. Furthermore, the ways in which different saturation gradients can develop over the length of a sample and the effects of the outlet boundary conditions upon such gradients are explained. The results are compared to available experimental data.
Cryogenic Scanning Electron Microscope Analysis: An Aid to Formation Damage Assessment
Authors: Denniss E. , Patey I. T. M. , Byrne M.
Published: December 2007

In order to evaluate the risk(s) of formation damage from well operations, laboratory core flood tests are commonly performed to closely mimic wellbore conditions. Analysis is required on the core samples in order to identify formation damage mechanism(s) which may be difficult due to the microscopic scale, opacity of rock and fluids. An already established approach of using cryogenic scanning electron microscopy (CryoSEM) at cryogenic conditions would be advantageous to observe the fluids contained within the pores of core samples to help identify formation damage mechanism(s). Other analysis (e.g. X-rays, acoustic velocity, nuclear magnetic resonance imaging) although useful fail to offer the same level of detail. This paper illustrates the method(s) to obtain the required detail by using additional techniques in conjunction with CryoSEM analysis this is referred to as "CryoSEM technique" from here on. In the past ten years CryoSEM has been revived in conjunction with the developed techniques which enables direct imaging of rock, pore space and fluids. Although quite commonly used and referenced in other papers there has never been a comprehensive description of the CryoSEM technique and its current abilities.

This paper describes in detail the CryoSEM technique and outlines some of the core sample preparation techniques and analysis procedures developed. The use of the CryoSEM technique in the description of critical formation damage mechanisms will be described. Examples of the use of CryoSEM as an aid to interpretation of formation damage mechanism(s) will be presented with some case histories with associated of formation damage mechanisms never previously observed will be presented.

The advantages and disadvantages of CryoSEM and other techniques will be discussed and the authors will also present some potential future developments in this area.
The Value of Oil and Gas Price Forecasts
Authors: Jablonowski C. , MacAskie R.
Published: December 2007

This paper develops a decision-analytic model to value commodity price forecasts in the presence of futures markets. The method is applied to a data set on crude oil prices. We find that to be valuable, forecasts must be accurate at predicting both gains and losses, and that there are positive and diminishing marginal returns to forecast value from improvement in key measures of accuracy. We also find that forecast value is specific to user class, and that value is unique to specific users within the class.
The Effect Of Residual Oil On Deep-Bed Filtration Of Particles In Injection Water
Authors: Ali Mohammad A.J. , Currie Peter K. , Salman Mohammad J.
Published: December 2007

Production of hydrocarbons is usually accompanied by the production of water. This produced water consists of formation water and/or water that has previously been injected into the formation. As more oil is produced, the amount of produced water increases. Unfortunately, the produced water is not a saleable product, hence, an operator must find ways to handle relatively large amount of water in an environmentally-acceptable manner at the lowest cost. One way of managing this water is to re-inject it for disposal, pressure maintenance or enhanced oil recovery. An important and difficult task in the re-injection process is the prediction of the impact of water quality on well injectivity. This is mainly due to the poor understanding of the deposition mechanisms by which suspended solids and oil droplets present in the produced water are retained by the formation.

As part of a study on formation damage, different concentrations of hematite particles suspended in water were injected into sandstone core samples at residual saturation. The theories of deep bed filtration are evaluated. The effects of residual oil on the filtration coefficient λ and the formation damage factor β are examined. The presence of oil caused greater apparent damage (reduction of permeability). It was also observed that there is rather deeper invasion at residual oil saturation than at fully brine saturation,
Solid Expandable Tubulars Expedite Access to Untapped Reserves from Existing Offshore Facilities
Authors: Radtke Cameron , Rivenbark Mark
Published: December 2007

Historically, operators used solid expandable tubulars as contingencies to mitigate unexpected hole problems, minimize loss of hole size and to meet project objectives. However, some operators quickly realized that by incorporating this technology into their initial field development and workover plans, previously untapped reserves could be brought online.

An operator in India combined solid expandable tubulars with sidetracking operations to reach additional reserves with optimized hole size in several offshore wells. Sidetracking out of a milled window results in loss of hole size with consecutive casing strings bringing further reductions. In this common scenario, the operator could be faced with drilling the drain hole with slimhole tools that drastically reduce the flow area and limit logging and drilling equipment availability.

Planning the application of solid expandables through the milled window in these vertical wells allowed the operator to economically extract previously unswept reserves. With conventional technology they were faced with exiting out of the 9-5/8 in. casing and setting 7 in. and 4-1/2 in. liners to isolate problematic and depleted zones above the pay zone. The pay zone would be drilled using 3-3/4 in. slimhole tool strings that placed restrictions in the outflow of the reservoir and compromised the workover program economics.

This paper will discuss how the planned-in use of expandable tubulars enabled the operator to sidetrack and recomplete poor-producing vertical wells into horizontal wellbores. This approach allowed the operator to maintain optimum drain hole that resulted in a five-fold increase in daily oil production. The paper will describe the complimentary technologies used with the solid expandables and the lessons learned in the first two wells. The operator/contractor relationship will also be discussed regarding project management of multi-well workover programs for both offshore and onshore fields.
Development of an Optimized Formulation for Cleaning Water Injection Wells Drilled With Oil-Based Systems
Authors: Dalmazzone C. , Le Follotec A. , Audibert-Hayet A. , Twynam A. , Poitrenaud H.
Published: December 2007

It is widely known that formation damage during drilling and completions are of prime concern for production wells. Formation damage impacts in injector wells, however, have not received the same level of detail and understanding. Water injection wells are of major importance in hydrocarbon recovery. Water injection wells are often completed as open holes, therefore, mud cake clean-up and damage removal by production of formation fluids is often performed in order to maximise subsequent water injectivity. In some wells, however, this production phase can be prevented due to surface handling limitations or low reservoir pressure. In most cases, when a well cannot be backflowed for long periods, it is possible to bypass near wellbore damage by exceeding the fracture pressure, but this may strongly affect sweep efficiency and uniform injection. Consequently, it is often necessary to inject water immediately after drilling and completion i.e. no possible production phase. In this case, a complete well cleanup is required, including the removal of the majority of mud filter cake components in order to maximise water injectivity. The objective of the present study was to develop a completion fluid formulation, based on a previous breaker technology developed by IFP, that allows complete disruption of the oil based mud cake by coalescence of water droplets and dispersion/dissolution of solids which is also compatible with all drilling and production fluids. The experimental methodology used in this study included several steps: the screening of efficient water based additives for dispersing/dissolving solids, the formulation of water-in-oil emulsions with controlled delayed kinetics of breakage adapted to the planned completion program, the assessment of the formulation compatibility with production fluids and finally the validation of clean-up efficiency with dynamic core filtration tests with a significant injectivity enhancement.
Managing Formation Damage Risks from Scale-Inhibitor Squeeze Treatments in Deepwater, Subsea Fields in the Campos Basin
Authors: Bogaert Philip , Berredo Marcos C. , Toschi Celso , Bryson Bill , Jordan Myles M. , Frigo Dario M. , Afonso Macros
Published: December 2007

This paper describes field experience and lessons learned from bullhead deployed scale-control operations in a deepwater subsea development in the Campos Basin, Brazil; specifically, deploying such treatments from the FPSO host, along the production flowlines, into four low-watercut, horizontal subsea wells, completed with sand control.

The relatively small number of high-cost, highly productive wells, coupled with a very high barium-sulfate scaling tendency upon breakthrough of injection water, meant not only was effective downhole scale management critical to achieve high hydrocarbon recovery, but even wells at low water cuts were deemed to be at sufficient risk to require squeeze application.

Initial bullheaded scale treatments comprised mutual solvent preflush, a water-based mainflush, and diesel overflush;so-called "hybrid" treatments.As water production rates rose, so did the treatment volumes required.To improve the logistics of these treatments and to mitigate issues arising from poor injectivity of diesel in these wells, core studies were conducted to investigate the option of exchanging the overflush fluid from marine diesel to injection-quality seawater.This change also introduced the possibility of forming a gas-hydrates plug during shut-in, but this was managed using a thermodynamic hydrate inhibitor and by replacing the flowline contents to flashed crude during the shut-in period.The operational aspects and the response of the wells to the modified treatments will both be compared with those previously deployed, in particular, in terms of the injectivity of the wells during treatment and well clean-up rates and productivity afterwards.

The core studies also highlighted a formation-damage mechanism caused by incompatibility between mutual solvent and the produced oil, which required modification of the treatment.
New Mechanical and Damage Skin Factor Correlations for Hydraulically Fractured Wells
Authors: Mahdiyar H. , Jamiolahmady M. , Danesh A.
Published: December 2007

Hydraulic fracturing is one of the most common well stimulation techniques. Hence, considerable amount of efforts has been devoted to study their performance under different prevailing conditions. Description of hydraulically fractured wells using the existing commercial reservoir simulators requires the use of very fine grids, which is very cumbersome, costly and impractical.

In this work a two dimensional single-well mathematical simulator has been developed, which is based on finite-difference methods, and simulates linear Darcy flow in a hydraulic fractured well. Based on the results of our in-house simulator different correlations have been developed for calculation of fracture (Sf), face damage (SfD), and chocked damage (Sck) skin factors. These formulations benefit from relevant dimensionless numbers expressing the effect of geometry and those used to quantify the extent of damages occurred during fracturing operation. The results indicate that in-house Sf values are more accurate than those available in the literature. SfD, reflecting the reduction of the permeability of the rock close to the fracture, is more realistically captured here when damaged thickness is assumed to decrease linearly towards the tip of the fracture. This is more superior to the uniform thickness assumption made in the literature, which overestimates SfD. It is also shown the available analytical expression for calculation of Sck, which is a reflection of reduction of fracture permeability, overestimate Sck hence, a more realistic correlation has been developed for this purpose.

The skin correlations developed here enables the engineers to study the productivity of a fractured well using simple open-hole system. They can also be used for the optimum design of a hydraulic fracture system by minimizing flow resistance for a given fracture volume and fracture permeability. This can be achieved readily by conducting simple derivation of the mathematical expressions of skin formulations presented here.
Optimisation of Perforation Techniques for Deep, HP Stringer Wells Located in the South of Oman
Authors: Laws M. S. , Al-Riyami A. M. N. , Soek H. F. , Pettitt A.
Published: December 2007

The intra-salt carbonate stringers represent a new oil province located in the south of Oman.To date, over 60 wells have been drilled in and around these reservoirs that in general are high pressure, deep and sour.Fluids within the fields range from a retrograde gas condensate to light oil. The stringers are geologically heterogeneous and commonly have low permeability.They are being developed in a phased manner that will involve miscible gas injection.

This paper describes the strategy that was developed by Petroleum Development Oman to optimize perforation techniques.

Perforations were required to by-pass the drilling induced impaired zone to enable effective stimulation of the reservoir and enhanced inflow performance. It was planned to perforate under-balanced, to apply the highest perforation phasing, to leave minimum gun debris in hole and to pull guns to surface to verify charges had fired and that the reservoir was amenable to future reservoir management activities.

Simulations were carried out to predict penetration depths in the formation using newly developed in-house software and the results were compared with those from an industry-recognised package of a major Service Provider.

In addition, the performance of commercial shaped charge perforators in full bore Harweel core was evaluated under pseudo downhole conditions. A series of tests with agreed procedures were carried out to compare perforation performance in actual core compared to that from industry recognized API RP19B Section 1 tests in cement.

The paper will provide an assessment of the predictive capabilities of the software packages in light of these laboratory tests on Harweel core samples as well as a comparison of the actual perforation performance of the evaluated charges.
Economics of GTL Technology for Gas Utilization
Authors: Ogugbue Chinenye C. , Chukwu Godwin A. , Khataniar Santanu
Published: December 2007

The world's natural gas proven reserves show enormous clean burning energy resources that call for its effective and efficient utilization. These gas resources, exceeding 6000 trillion cubic feet (TCF), currently represent a significant proportion of the energy equivalence of proven oil reserves. With over sixty (60) percent of such gas reserves located too far from potential markets, there is need to evaluate the prospective economics of promising technologies for the monetization of these stranded gas reserves. The main focus of this paper is the economics of the chemical conversion of natural gas to synthetic liquid fuels, favored by recent advances in Fischer-Tropsch (F-T) synthesis techniques, welcomed shift-to-liquid fuel transportation operations, and increased demand for clean burning diesel fuels. The value of this emerging technology will be the ability to turn natural gas reserves, currently too remote from the market, into high-quality premium products that could be transported as liquid fuels.

The effect of capital expenditures (CAPEX), annual operating expenditures (OPEX), product price and various tax schemes on the rate of return (ROR), pay out time (POT) and the net present value (NPV) is investigated to access the economic viability of GTL plants. The range of CAPEX utilized is based on the production of one barrel of hydrocarbon liquid per day (BLPD) whereas the OPEX are expressed as percentages of CAPEX. Also, a construction period of three years is considered, while a 10% net-back on product sales is incorporated to account for the cost of natural gas feedstock. Monte-Carlo simulation is utilized to run sensitivity analysis, incorporating the probabilistic approach, to generate insightful scenarios on the project economics. The results (measures of profitability and their certainty bands) are analyzed and presented in tables, histograms and charts for a 100, 000 BLPD GTL plant.
Economic Decisionmaking and the Application of Nonparametric Prediction Models
Authors: Attanasi E. D. , Coburn T. C. , Freeman P. A.
Published: December 2007

Sustained increases in energy prices have focused attention on gas resources in low permeability shale or in coals that were previously considered economically marginal. Daily well deliverability is often relatively small, although the estimates of the total volumes of recoverable resources in these settings are large. Planning and development decisions for extraction of such resources must be area-wide because profitable extraction requires optimization of scale economies to minimize costs and reduce risk. For an individual firm the decision to enter such plays depends on reconnaissance level estimates of regional recoverable resources and on cost estimates to develop untested areas.

This paper shows how simple nonparametric local regression models, used to predict technically recoverable resources at untested sites, can be combined with economic models to compute regional scale cost functions. The context of the worked example is the Devonian Antrim shale gas play, Michigan Basin. One finding relates to selection of the resource prediction model to be used with economic models. Models which can best predict aggregate volume over larger areas (many hundreds of sites) may lose granularity in the distribution of predicted volumes at individual sites. This loss of detail affects the representation of economic cost functions and may affect economic decisions. Second, because some analysts consider unconventional resources to be ubiquitous, the selection and order of specific drilling sites may, in practice, be determined by extraneous factors. The paper also shows that when these simple prediction models are used to strategically order drilling prospects, the gain in gas volume over volumes associated with simple random site selection amounts to 15 to 20 percent. It also discusses why the observed benefit of updating predictions from results of new drilling, as opposed to following static predictions, is somewhat smaller.
Comparative Analysis of Damage Mechanisms in Fractured Gas Wells
Authors: Friedel Torsten , Mtchedlishvili George , Behr Aron , Voigt Hans-Dieter , Häfner Frieder
Published: December 2007

Productivity impairment in tight-gas formations is a typical phenomenon for fractured wells. Processes responsible for this behavior are related to the characteristics of the porous media, and are induced as a consequence of the fracturing process. Fracture damage has been discussed in the literature for decades. In almost all cases, effects were considered in isolation. This is often not appropriate since natural effects such as stress dependency, fracture closure, and non-Darcy flow are interdependent. The same applies for the cleanup process where the back production of the loadwater from the leakoff zones can be influenced by mechanical damage caused during the fracturing process, or by capillary forces and the gel residues of unbroken fracturing fluids within the fracture plane.

This study analyzed the most common damage mechanisms by means of both generic and real field data. The latter was taken from German Rotliegend gas wells, which were history-matched and used for the evaluation of their cleanup and longterm production behavior. The results obtained were used to rank the individual processes for their damage potential. In addition to a commercial model, a customized in-house simulator was required in order to capture the specific physics.

Results suggest that the consequences of processes independent of the reservoir conditions are not negligible when compared to the damage induced by the fracturing itself. In particular, in tight-gas, the stress dependency of the reservoir rock and fracture closure both tend to have a significant impact on the longterm productivity. Furthermore, inertial non-Darcy flow can cause much higher production impairment than, for example, hydraulic damage. It also shows that low permeability reservoirs are more affected by non-Darcy flow effects in both the fractures and the reservoir than is generally assumed.
Production Pofile of Wells Before and After Treatment Using Novel ThermoChemical Technique
Authors: Amin Remy Azrai M. , Halim Nor Hadhirah , Rosli Kamal Amri , Ali M. Izat , Winnie Ho Wei Nee , Mohamad M. Hafiz
Published: December 2007

Most of PETRONAS fields in Malaysia have been producing for more than 20 years. At this advanced stage of depletion, reservoir driving forces are low. Organic deposition, particularly in the near-and-around well bore region and in production tubing, can further reduce the production of oil by restricting the flow passage from reservoir to wellbore. A study to address this issue with a view to rejuvenate the problem wells through laboratory analysis & pilot field implementation was conducted.

A unique thermo-chemical system has been developed as an effective tool for 1:- Removing the organic deposits near-and-around wellbore and production tubing, henceEnhancing the production from the treated wells.

The two components of the system are injected simultaneously into the wellbore through production tubing. Upon mixing, both components will produce heat and reaction products. The heat generated capable to melt and dislodge the organic deposits. While, the reaction products will act as an effective solvents and surfactants for dispersion of organic species.

The objective of this paper is to present the result of 4 wells treated by the thermo-chemical system. Well selection criteria based on production profile and well history is described. The implementation technique and a post treatment production gain are also highlighted.