bluuebunny/crossref_metadata_2025 huggingface dataset:
Compositional Modeling of Oil-Based Mud-Filtrate Cleanup During Wireline Formation Tester Sampling
Authors: Alpak F. O. , Elshahawi H. , Hashem M. , Mullins O.
Published: December 2007

Miscible oil-based mud (OBM) filtrate contamination poses a major challenge to the acquisition of representative fluid samples using wireline formation testers (WFTs). A sound understanding of the physics of OBM filtrate clean-up and identification of first-order impact parameters is of paramount importance for the design of new generation WFT probes that can operate in OBM filtrate environments with enhanced efficiency.

Analytical as well as numerical models reported in the formation testing literature rely predominantly on simplifying assumptions in terms of the compositions of flowing fluid phases. These models characteristically assume single-component phases in the case of two-phase immiscible formulation, or a two-/three-component hydrocarbon phase in cases of black-oil/extended black-oil formulations. In turn, compositional interactions are entirely neglected or represented through simplistic empirical correlations. Such conventional models are deemed sufficient for pre-job planning and interpretation of measurements acquired in formations subject to water-base mud (WBM) filtrate contamination. Dynamics of flow in OBM filtrate contaminated formations is significantly more complex. A time-dependent coupling between fluid dynamics and phase behavior constitutes the governing physics of OBM filtrate clean-up process. Therefore, for OBM filtrate environments, accuracy of conventional formulations in representing the actual physics of flow is limited.

We have constructed a numerical model for the OBM filtrate clean-up within the framework of an equation-of-state (EOS) compositional fluid-flow simulator. Our numerical framework simultaneously honors the physics of multi-component fluid flow and the thermodynamics of phase behavior. The numerical model was verified against analytical solutions for zeroth-order models for which analytical solutions exist. Simulation results exhibited close agreement with the analytical predictions and with field data for the time dependence of contamination during sampling. A rapid approximate response surface based model, which can serve as a pre-job planning or real-time analysis tool, was derived from extensive simulations conducted with the compositional numerical model. Our simulation and rapid modeling results compare well with empirical observations made in the field. In particular, the rate of change of miscible contamination with time has been found empirically to vary as t5/12. For the first time, modeling has been shown to give essentially the same results as empirical observations. The agreement between our model and common field observation motivates use of our model to analyze the more complex WFT probes, which have recently become available.
Efficient Cost Saving through an Appropriate Completion Design
Authors: Ouyang L. -B. , Huang W. S. , Dickerson R.
Published: December 2007

Well completion plays a critical role in the performance of a well in its entire life. More and more advanced well completion options are available for potential deployment in new wells, especially those in deep water and offshore; however, the cost could vary significantly from one completion type to the other. Considering the fact that completion takes a substantial stake in the whole CAPEX for a new well, the cost and the impact of the well completion is too significant to be ignored.

Two field case studies will be discussed in the present paper to demonstrate the possibility of cost saving through efficient completion designs. The first case study is focused on a deviated gas producer, and the second on a horizontal oil producer. The most popular completion options, including openhole gravel pack, cased-hole gravel pack, openhole, standalone screen, cased-hole frac pack, expandable sand screen, inflow control devices (ICD), intelligent well completions (DIACS), etc, will be considered in the completion selection. Other completion options such as alternating standalone screen and blank pipe that may slash completion cost without sacrifice of well performance will also be proposed and evaluated. Well performance will then be evaluated in details by assessing total well production, annular flow and flow inside the liner/tubing, pressure profiles along the annulus and along the liner, inflow from reservoir to annulus and fluid transfer between annulus and liner, and so on. Cost recovery, water and/or gas shut-off, formation damage, casing collapse, sand prevention issues associated with different completion options will be addressed.

A work flow aiming at optimizing well performance while maintaining completion cost at the minimum will be proposed.
The Eureka Canyon Oil Field: A Case History
Authors: Hesson B. H.
Published: December 2007

The Eureka Canyon oil field is one of the oldest in Ventura County, California. The approximately 920-acre field was discovered in 1893 due to the presence of natural oil seeps. The field is near the City of Piru, south of State Highway 126 and the Santa Clara River, with the wells located in two canyons named Smith and Eureka. Many of the field’s 112 wells were drilled using cable tool rigs. T.E.G. Oil & Gas USA, Inc. (TEG) produces 16 barrels of oil per day from eight wells in Smith Canyon, with production from the Miocene formation found at an average depth of 1,800 feet. Due to marginal production, the wells in the Eureka Canyon area of the field were plugged and abandoned or left orphaned when the last operators-of-record became defunct. Some of these wells are in a remote, steeply sloped area of Eureka Canyon that became inaccessible over time due to erosion and the dense growth of chaparral.

Wild fires rampaged through Ventura County in October 2003, impacting 24 oil fields, including Eureka Canyon. While conducting field inspections following the fires to assess damage and during subsequent well work, the Division of Oil, Gas, and Geothermal Resources (Division) located and identified 17 previously inaccessible orphan wells, 13 without wellheads. As a safety and spill prevention measure, the Division secured these wells. Record rainfall in 2005 washed out lease roads and compromised some of the well locations due to mud and rockslides. Since TEG was not interested in acquiring these orphan wells, and six others for a total of 23 wells, the Division contracted to have them plugged and abandoned. This paper will present a brief field history and describe the Division’s efforts to locate, identify, secure, and abandon these wells.
Using Synchrotron Radiation Wide-Angle X-Ray Scattering (WAXS) to Study the Inhibition Effect of DiEthyleneTriaminePenta (MethylenePhosphonic Acid) (DETPMP) on CaCO3 Scale Formation
Authors: Chen T. , Neville A. , Sorbie K. , Zhong Z.
Published: December 2007

The formation of calcium carbonate mineral scale is a persistent and expensive problem in oil and gas production. Scaling of metallic or insulating walls in contact with hard water may cause unscheduled equipment shutdown and loss of production. The aim of this paper is to further the understanding of scale formation and inhibition by in-situ probing of crystal growth by synchrotron radiation Wide Angle X-Ray Scattering (WAXS) in the absence and presence of diethylenetriaminepenta (methylenephosphonic acid) (DETPMP) scale inhibitor at elevated temperature and high pressure. This novel technique enables in-situ study of mineral scale formation and inhibition and as such, information on the nucleation and growth processes is accessible. This technique studies bulk precipitation and surface deposition in the same system and has great benefit to understand an industrial scaling system. It offers an exciting prospect for the study of scaling.

It has been shown that the nucleation and growth of various calcareous polymorphs and their individual crystal planes can be followed in real-time and from this the following conclusions are reached.

❖ The process of scale deposited on the surface can be divided into an unstable phase and a stable phase. The initial phase of crystallization of calcium carbonate is characterized by instability with individual planes from various vaterite and aragonite polymorphs emerging and subsequently disappearing under the hydrodynamic conditions. After the initial unstable phase, various calcium carbonate crystal planes adhere on the surface and then grow on the surface. ❖ DETPMP has a profound effect on the induction time of the surface deposit. It inhibits scale crystal adhesion onto the surface, although the bulk precipitate is observed in the scaling system. It displays different inhibition mechanisms for bulk precipitation and surface deposition inhibition. ❖ DETPMP inhibits surface deposition. It suppresses calcite formation and results in the least stable vaterite crystal formation.

This paper will discuss how surface scale evolves in the absence and presence of the inhibitor - exploring the power of the synchrotron in-situ methodology.
Evaporative Recovery of Trapped Oil in Fractured Reservoirs: A Pore-Network-Level Analysis of Capillary and Gravity Effects
Authors: Tajer S. E. , Yortsos Y. C.
Published: December 2007

The recovery of volatile oils from the matrix of fractured porous media can be significantly aided through gas injection. Within certain assumptions, this process operates much like the isothermal drying of porous media. For example, recovery is controlled by mechanisms involving capillary, viscous and gravity forces in the liquid and the liquid-gas interfaces, and mass diffusion and convection in the gas phase.

In this work the effect of capillarity and gravity driven viscous flow through macroscopic liquid films during the isothermal drying of porous materials is studied. We use a mathematical model based on a 2-D pore-network representation of porous media. The problem is characterized by two dimensionless parameters, a diffusion-based Capillary number, Caf, and the gravity Bond number, Bg, in addition to the various geometrical parameters of the pore network. The simulator accounts for evaporation and diffusion of a volatile liquid, trapped in a heterogeneous pore network.

Results on the evolution of the liquid saturation, the isolated liquid clusters and the drying rates are obtained as a function of dimensionless time and the dimensionless parameters in the two cases when gravity opposes or aids the process (corresponding to positive or negative Bond numbers, respectively). In the first case, the fronts are stabilized, while in the second they are destabilized. It is shown that gravity-controlled film flow is a major transport mechanism in the drying of porous media, its effect being dominant when gravity and capillarity control the process. Under strong capillarity conditions, the films span across the whole block, enhancing significantly liquid flow from distant clusters and improving recovery rates.

The paper finds application to the recovery of volatile oils from fractured or heterogeneous reservoirs by gas injection.
Estimating Layer Properties for Wells in Multilayer Low-Permeability Gas Reservoirs by Automatic History-Matching Production and Production Log Data
Authors: Spivey J. P.
Published: December 2007

Most of the major unconventional gas plays in the U.S. have multiple productive intervals. Wells are completed with multiple fracture treatments, and are produced commingled. This paper describes a new fully-coupled reservoir/wellbore single-well analytical simulator* for multilayer unconventional gas reservoirs that automatically history matches production and production log data simultaneously.

The layers in the simulator are independent, with different temperatures, pressures, completion types, and reservoir geometries. The simulator rigorously accounts for transient and boundary-dominated flow in each layer and pressure drop in the wellbore, including pressure drop between adjacent layers and pressure drop from the reservoir to the surface.

By history matching data from multiple production logs as well as surface production data, the simulator provides accurate estimates of individual layer properties such as permeability, fracture length, and drainage area. The simulator may be used for reservoir and fracture treatment evaluation, restimulation candidate selection, fracture design optimization, and performance forecasting in multilayer unconventional gas plays.
Effect of Hydrate Inhibitors on Calcite, Sulfates, and Halite Scale Formation
Authors: Shipley H. J. , Kan A. T. , Fu G. , Shen D. , Tomson M. B.
Published: December 2007

Methanol is a common industrial solvent and is added to water to enhance hydrocarbon solubility and to prevent solid hydrate from forming, as well as other applications. One of the side effects of methanol addition to water is it greatly reduces the solubility of ionic solids, particularly divalent solids. The effect of methanol on ionic solubility has been reported only for a few isolated conditions. The effect of hydrate inhibitors on oilfield scale formation has been studied. A semi-empirical approach is proposed to correlate the effect of hydrate inhibitors on scale formation and inhibition from experimental solubility measurements of halite, barite, gypsum, calcite and carbonate equilibrium chemistry. The ion-cosolvent activity coefficients can be used directly in any solution speciation code to evaluate the effect of cosolvent on mineral scale formation. The validity of the equation has been tested between 4-200°C and 1-6 M ionic strength. Barite solubility is significantly reduced, by as much as 20 fold, with 50% (v/v) methanol. Other mineral solubilities are also reduced significantly. Ethylene glycol has much less impact on mineral solubility than methanol. Good agreements between the model prediction versus both experimental and literature results are observed.
A New Cementing Approach to Improve and Provide Long-Term Zonal Isolation
Authors: El-Marsafawi Y. , Al-Yami A. , Nasr-El-Din H. A. , Al-Jeffri A. , Misran M. , Hasan A. , Jain B.
Published: December 2007

A new cement system has been developed to meet oil and gas industry's need for better zonal isolation. In this paper, we present design, execution, and evaluation of the system used to cement solid expandable tubular (SET) in a carbonate field in southern Saudi Arabia. The SET is 900-ft long with 5½-in. diameter, placed horizontally in a 7½-in. drilled hole with a 9,000-ft depth. To enhance well production, two windows were milled from inside the cemented SET to drill laterals to maximize surface contact with the horizontal oil reservoir.

Special laboratory techniques were used to evaluate set-cement and slurry properties of the system to determine its potential use for field application. Distinguishing features of the developed versus conventional cement are also explained.

Pressure and inflow tests were used along with cement evaluation tools to evaluate the success of the operation. Production profile was also studied to ensure durability of the cement system.
Precipitation and Dissolution of Minerals During Waterflooding of a North Sea Oil Field
Authors: Houston S. J. , Yardley B. W. D. , Smalley P. C. , Collins I.
Published: December 2007

A long-term study of produced water chemistry from a North Sea field was used to investigate the mechanisms of water mixing and water-rock interaction in the reservoir. Seawater flooding has continued throughout much of the production life. Detailed repeated sampling of the produced water was undertaken and has produced an extensive dataset, yielding information on water chemistry variations in space and time. The dataset documents both fluid mixing in the field and the physical, chemical and thermodynamic response of the system to the injection of seawater. Analysis of the data establishes the nature of the controls on the composition of the scale-prone formation water, and enables an in-depth look at the fluid-rock interactions occurring in the reservoir during a waterflood.

Changes in produced-water chloride concentration through time reflect changing proportions of injected seawater and formation-water, revealing differing patterns of injected-water breakthrough over the field. However, parallel changes in the concentrations of less conservative fluid components provide evidence of fluid-mineral interactions that occurred in the reservoir on the timescale of the waterflood. For example, calcium is enriched in the produced fluid relative to a linear mixture of original formation-water and seawater, while magnesium is depleted, probably reflecting dolomitisation of calcite and growth of clay. Barium and sulphate are strongly depleted due to precipitation of barite. However, mass balance highlights an additional sink for sulphate, possibly reduction to sulphide. Excess silica present in the produced fluid is ascribed to dissolution of silicate phases in the reservoir. Concentrations demonstrate that the produced water is always close to quartz saturation at reservoir temperature, irrespective of the proportion of seawater produced.

Analysis of produced water chemistry provides insights into the inner workings of the reservoir system during a waterflood. Study of individual dissolved species relative to linear mixing lines between injected and formation water allows measurements of the nature and amounts of dissolution and precipitation reactions affecting scaling ions within the reservoir. This allows for greater understanding of the controls on water composition and of the nature of water mixing in the reservoir, leading to improved prediction and planning of scale occurrence, prevention and remediation.
Simulating Calcium Naphthenate Formation and Mitigation Under Laboratory Conditions
Authors: Dyer S. J. , Williams H. L. , Graham G. M. , Cummine C. , Melvin K. B. , Haider F. , Gabb A. E.
Published: December 2007

A laboratory methodology has been developed to better simulate calcium naphthenate formation and evaluate chemical inhibition measures. Detailed ongoing field experience data and related samples have been used in support of the lab rig design and protocols.

Calcium Naphthenates are becoming more recognized as a major flow assurance issue. When occurring in the field operation, significant quantities (typically in tonnes per day) can be formed and the process operation, chemical controls and monitoring procedures are far from straightforward. The ability to accurately predict calcium naphthenate formation and/or replicate field production conditions in the laboratory has been fraught with difficulties. For example conventional "bottle" or "jar" test procedures suffer from severe limitations relating to poor pH control, inefficient mixing, non representative residence times coupled with relatively indirect assessments often indicating fluid compatibility issues rather than identification of naphthenate deposits.

Recent work examining both current calcium naphthenate problems in existing facilities and the technical requirement to predict the potential for naphthenate deposits in new fields has led to the design and validation of more appropriate laboratory test equipment. This includes new designs of novel dynamic flow systems and modified autoclave approaches which allow the formation of naphthenate deposits, stable emulsions and soap scales to be assessed directly under laboratory conditions using relatively small volumes of reservoir fluids. The designed equipment is shown to overcome the challenges previously associated with the assessment of calcium naphthenate issues, their mitigation and chemical treatment under laboratory conditions.

The ability to simulate naphthenate deposition represents a major step forward in our ability to understand the controlling parameters associated with these complex scales. This paper will describe the novel aspects associated with the laboratory flow rig and other test methods adopted, it will illustrate how the equipment design overcomes the limitations associated with more conventional tests and describe how the results are being used directly to assess the changing naphthenate challenge and its treatment which may be expected throughout a field's lifetime. The composition of solids collected from naphthenate formation tests in the flow rig under different conditions is also presented, thus further validating the effectiveness of the rig design. The paper therefore illustrates how improved equipment design and test protocols can reduce the risks associated with field trials, which have previously been required for optimising treatments against naphthenate deposits.
Automated Liquid Unloading in Low-Pressure Gas Wells Using Intermittent and Distributed Heating of Wellbore Fluid
Authors: Alipour-Kivi G. , Bugacov A. , Khoshnevis B. , Ershaghi I.
Published: December 2007

This paper presents a comprehensive simulation study demonstrating technical merits of automatic intermittent and distributed heating for reducing back pressure and maintaining flow in low pressure gas wells.

Reduction or elimination of the additional wellbore backpressure plays a key role in boosting gas wells productivity and extending the lifetime of the field. The backpressure is mostly due to the development of excess liquid water along the tubing stopping the low pressure gas flow. We present two-phase thermal flow simulations to study the impact of intermittent volumetric heating along the wellbore to reduce or eliminate the excess backpressure caused by either water condensation in the upper part of the wellbore, or the overall increase of density of the two-phase fluid. The proposed method helps in continuous prevention of the excess water development enabling the well to produce without interruption up to its natural limit.

Modeling the thermal exchange in the wellbore, two-phase flow pressure simulation demonstrates that flowing and thermo-dynamic conditions of the water/gas mixture along the wellbore have a substantial impact on the overall backpressure. Our results show that by modifying the thermal profile of the wellbore fluid at specific locations and times, we can maintain significantly lower backpressures and increase well productivity. Our case studies highlight that for very low pressure gas wells, the external power requirements can be more acquiescent to automation and control than the existing methods.

The results yield valuable insight in the development of a novel liquid unloading techniques based on volumetric heating of the wellbore fluid. Our results can also be applied to the elimination of hydrates in gas wells.
Core Data Preprocessing To Improve Permeability Log Estimation
Authors: Cozzi M. , Ruvo L. , Scaglioni P. , Lyne A. M.
Published: December 2007

Two techniques of preprocessing data from core plugs have been investigated to enhance the quality of synthetic permeability estimation from conventional logs using Artificial Neural Networks (ANNs). A first technique consists of ‘cleaning’ the core plug data set by removing the measurements deemed as log-incompatible, i.e. those from plugs corresponding to log measurements affected by shoulder-bed effect, and those from layers with thickness below the vertical log resolution. The second technique relies on building high-resolution digital models of cored intervals using a Process-Oriented Modeling (POM) approach: the core model is populated with permeability values from core plugs and then upscaled to a log-equivalent support volume.

Synthetic permeability curves estimated with the above techniques have been compared to synthetic permeability curves estimated without core-data preprocessing and to permeability estimated directly from core plugs and properly calibrated permeability curves from a Nuclear Magnetic Resonance log tool in a turbidite reservoir, the ground truth value being represented by actual dynamic data. Results highlight that core-to-log scale-effects play a major role in the permeability estimation from conventional logs and show that the proposed preprocessing techniques can be very effective in improving permeability prediction, as they significantly reduce cross-scaling problems related to the differences in support volumes.

Strengths and weaknesses of the two preprocessing approaches have also been compared. The first technique is faster, but its application can be strongly constrained by statistical and geological representativeness of the selected data set, in the sense that some lithologies could go under-represented so as to question the use of estimation tools like ANNs. Conversely, the POM preprocessing technique is more time-consuming and needs detailed core descriptions, but has the great advantage to supply – starting from core data only – a reliable permeability curve that can be retained valid at the log scale.
Swell Packers: Enabling Openhole Intelligent and Multilateral Well Completions for Enhanced Oil Recovery
Authors: Hembling Drew , Salamy Salam , Qahtami Abdullah , Carter Neale , Jacob Suresh
Published: December 2007

Intelligent and multi laterals wells are evolving as key completion technologies to enhance and maximize hydrocarbon recovery. A pre-requisite for the successful application of multi lateral and intelligent well systems is zonal isolation and compartmentalization of the reservoir. Current Techniques either involve the cementing of the mother-bore and/or the use of complex mechanical systems and packers to isolate individual zones. Both techniques increase the complexity of the operation and result in reduced ID from the additional casing string. In addition with intelligent well systems, a feed through system for the hydraulic, eleictrical or fiber optic cable must be used across the isolation device. This join or break represents another weak link or potential failure point in the system.

An isolation device has been developed which uses a rubber elastomer bonded onto a base pipe. The rubber swells in hydrocarbon and provides an effective seal down hole between the base pipe and the openhole to maintain zonal isolation in even the most complex environments. Any number of packers can be made up in the completion string to provide the zonal isolation required and are run as an integral part of the completion string in a single trip.

The swell packer offers many advantages over conventional techniques, besides it simplicity it is able to conform to irregular wellbores, the system can seal in open hole eliminating the need for a completion liner for zonal isolation. This saves rig time and money in the completions and allows for larger ICV’s to be run. In addition, the use of a unique feed through system allows control lines and fiber optic cables to be run through the packer without a connection or splice at the packer. This paper will describe recent case histories and planned operations in Saudi Aramco where the swell packer has enabled intelligent completions, multi lateral, and reservoir compartmentalization for equalizer completions and simplified the process of cable feed through on intelligent completions.
Application of a Maximum Reservoir Contact (MRC) Well in a Thin, Carbonate Reservoir in Kuwait
Authors: Kabir M. , Ingham S. , Sibley D. , Osman K. , Ambastha A. K. , Anderson M. , Rahman B.
Published: December 2007

Mauddud reservoir in the Greater Burgan field is a thin, carbonate reservoir containing light oil in a 10-20 ft target zone with "good" porosity. Matrix permeability is low and natural fracture density can be quite variable in this reservoir. Thus, this reservoir must be exploited using horizontal wells in all areas. In areas where fractures may not be dominant, it is crucial to achieve maximum reservoir contact (MRC) through the well architecture. To this end, a tri-lateral MRC well with a mother bore and two laterals has been recently drilled in this reservoir achieving about 5,000 ft of reservoir contact. This paper details the process followed to achieve this milestone for the first time in Kuwait.

A multi-disciplinary team consisting of Geology, Petrophysics, Geophysics, Drilling, and Service Company was instrumental in utilizing state-of-the-art 3D seismic interpretation, LWD resistivity at bit, real-time imaging, and distance to boundary measurements to place this first MRC well for the Kuwait Oil Company (KOC) entirely within the thin target zone. Real-time decision-making was possible due to seamless integration of all data and interpretation from various disciplines. Internet-based platform was extensively used in this project. Local formation dip changes were computed and well trajectory revised in real time due to such integration.

The process used in this project to place a complex well entirely in a thin target would be applicable to all thin reservoirs that must be exploited through horizontal wells.

Technical contributions discussed in this paper include effective utilization of LWD data to make real-time geo-steering decisions in a thin target, process for real-time calculation of distance to the top (or bottom) and dip changes based on LWD data, and effectiveness of Internet-based platform for communication and decision-making process.
Improving the Value-Risk Management on Revitalizing Mature Oil Fields in One Company's Operating Area
Authors: Aprilian S. S. , Kurnely K.
Published: December 2007

PERTAMINA's mature oil and gas fields in Indonesia have a typical problem related to the following conditions, e.g.: limited data quantity and quality, depleted reservoir with a high watercut, sand/scale problems, small fields in different area (scattered), and mostly having an old infrastructure. However, PERTAMINA has strengths on experienced engineers (local knowledge), high asset value (reserves, operation area, production facilities, and existing infrastructure), committed gas markets, mostly onshore fields, and the fields still under primary recovery. Moreover, there are some unexplored "upside potentials" (deep zones, shallow prospects, adjacent area) surrounding the existing fields.

This paper introduces and discusses the efforts of Management of PERTAMINA Indonesia on managing the values and the risks of the mature fields through a spirit of maximizing their economic recovery. It covers all the potentials by valuation of the assets and making their portfolio investment, applying a new selected technology and approach for focused area, creating a new interpretation for old available data, and optimizing the method of existing production.

Assessing the assets (from reserves to surface infrastructures and company strengths) becomes a primary and critical step before prioritizing and focusing the objective area. Then a reserves evaluation is the further step that maps a new business opportunity. One of the conclusions of reserves evaluation is that the unrecoverable reserves of PERTAMINA's mature fields are still huge and possibly recovered by enhanced oil recovery methods.

By taking the experiences on rejuvenating the South Sumatra, East Java, and Kalimantan mature fields, and the partnership of TAC, JOB, and BOB in managing the mature fields, management of PERTAMINA has self-assurance on further development of their mature fields spread on the eleven operation areas in Indonesia. PERTAMINA puts a great hope on creating the values of their mature fields in the near future
Experience With Rotary Steerable System for Reservoir Drilling in Iranian Offshore Oilfields
Authors: Molayee A. , Teymoori A.
Published: December 2007

The majority of the wells which have been drilled in Iranian oilfields in Persian golf include a horizontal section through the reservoir and the most of them have been drilled by the conventional steerable mud notor assemblies.

Steerable motor drilling is a relatively inefficient process with associated problems, ranging from trajectory control in unstable shales, pipe sticking in lost circulation zones and slide drilling in carbonate reservoirs.

In order to minimize the effect of these issues, rotary steerable system has been deployed in a number of wells for reservoir lateral drilling over the past year.

This paper looks at a range of specific applications where the change from steerable motor to rotary steerable system has been both technically and commercially successful in offshore Iranian oilfields. Through the case histories, this paper will demonstrate both tangible and intangible benefits resulting from the use of rotary steerable systems that have led to a step change in overall drilling performance.
Development and Field Use of a Novel Solvent-Water Emulsion for the Removal of Asphaltene Deposits in Fractured Carbonate Formations
Authors: Lightford S. , Pitoni E. , Armesi F. , Mauri L.
Published: December 2007

The formation of asphaltene scale inside the tubing or in the reservoir is a common problem associated with crude oils in many parts of Italy and common to the industry as whole. In Italy regular treatments using coiled tubing or washing by bullheading are performed to re-establish production. While asphaltene inhibitors can be injected into the tubing string, asphaltenes can still create problems below the injection point and plug the perforations, formation pores, and/or natural fracture network systems.

There is a wide range of hydrocarbon-based solvents that have been used in the industry to remove asphaltenes. The more effective solvents have a low flash-point temperature, making them expensive and hazardous. In addition these hydrocarbon-based solvents leave the formation in an oil-wet state after asphaltene removal instead of re-establishing the water-wet condition that acts as barrier to slow down the deposition of the asphaltene on the formation. This effect accelerates the re-disposition of the asphaltene in the formation and increases the speed of the production decline, increasing the frequency of remedial treatments.

This paper describes the laboratory development and field application of a water/aromatic solvent emulsion system that has been successfully used to clean/dissolve asphaltene and leave the carbonate fractured formation in a water-wet state to delay the production decline. Other advantages when using this type of emulsion are cost reduction and improved effectiveness in removing asphaltene deposits, when compared to alternative solvents that have been employed. This is of particular significance to these wells where large volumes of a washing phase have to be pumped downhole. Hazards have also been reduced by using relatively high flash-point aromatics. Continuous mixing of the emulsion when pumping reduces waste and improves the logistics involved in pumping the large volumes needed to treat long, openhole sections and/or to treat the fractures deeper in the near-wellbore region.

Two successful field applications in south Italy will be discussed in detail, describing the placement technique employed and the results achieved with this new system. These treatments will be compared to previous treatments using a hydrocarbon-based solvent. In the first well, where previous treatments had failed to make significant improvements, following the application of this emulsion the production was practically fully restored and the production decline was significantly slower than previous treatments. The second well treated was a long, horizontal wellbore; again the emulsion and technique proved successful in returning the production to previous levels and sustaining the new level for an extended period of time.
A Case Study for Comparison of Different Real Option Approaches in Petroleum Investments
Authors: Yao Y. H. , Begg S. , van der Hoek J. , Behrenbruch P. , Bratvold R. B.
Published: December 2007

Many oil companies struggle with how to value investment decisions that carry a large amount of risk due to uncertainty. There are two key questions. How should value be adjusted to account for risk? And, what is the value of flexibility (or options) in managing uncertainty?

Traditional project valuation techniques and metrics (Net Present Value based on Cash Flows that are discounted at the WACC, which is sometimes inflated for "risk") are incapable of answering these questions to the degree of accuracy required for many investment decisions.

Real Options Valuation (ROV) is the extension and application to real assets of option-pricing tools that were developed to answer the same two questions in the finance sector. However, due to the differences between real and financial assets, the evolution of this "extension and application" has resulted in a number of variations of approach. These variations are the subject of considerable debate within the petroleum industry. In this paper we describe four approaches, and compare their results using a case study that is dominated by price uncertainty.
Remote Sensing, Fuzzy Logic and GIS in Petroleum Exploration
Authors: Taheri S. R.
Published: December 2007

Despite the known practical applications of remote sensing in a wide range of industries and situations, it has not been used extensively in petroleum exploration, which has relied mostly on geological and / or geophysical surveys. With the advances made in sensing equipment since the Advanced Spaceborne Thermal Emission and Reflection Radiometer (ASTER) became operational, extraction of potential indicators such as: surface emissivity, surface kinetic temperature, brightness temperature and surface radiance needs to be re-evaluated in the context of petroleum exploration. This research will mainly investigate the application of remote sensing techniques to existing petroleum reservoirs with the objective of uncovering diagnostic patterns that could ultimately be used for evaluating virgin territory. Although oil and gas reservoirs are deep below the surface, they have some indicators, which can be detected on the ground. Hazy patches on Landsat MSS images were considered by Collins (1973) as a clue to explore for oil due to their high correlation with existing oil and gas fields, but since the phenomenon was never explained it fell out of favor[1]. This research will try to identify more of these surface phenomena (e.g. surface temperature (TIR) derived from satellite data, vegetation cover, alteration zones, geochemical surface characteristics and any other available surface data) and study their correlation with the presence of oil and gas regardless of whether they can be explained or not. By employing GIS and fuzzy logic a dynamic model will be developed which can be applied to any new petroleum exploration target using the variable input data from that particular exploration target. The selected study area consists of almost 50 existing petroleum oil fields onshore Iran. Following fieldwork in the project area, various valuable layers of information were collected. 20 ASTER scenes over the study area have been received from NASA and data have been retrieved from these satellite images. These data was finally integrated with all the other available data layers to produce the dynamic model. The study is highly significant due to its capability of minimizing exploration costs when remote sensing is combined with other current conventional exploration techniques during the reconnaissance stage. During the course of research quite a good correlation has been observed so far between the analysis results and the presence of oil as a positive indication of the applicability of the proposed model for hydrocarbon exploration.
Recapturing the Value of Fractional Flow Analysis in a Modern Day Water Flood
Authors: Millán H. , Parker A.
Published: December 2007

The Champion Field is located 40 km offshore Brunei, Northern Borneo, in a water depth of 10 – 45 m. It has been on production since 1972 and secondary recovery by treated seawater injection commenced in some reservoirs in 1984.

In this paper we present an analytical approach for estimating relative permeability end-points from production/injection data as a starting point for sensitivity studies on the applicability and value of expanding water flooding to the rest of the Champion field.

A significant volume of special core analysis data is available, however, the representativeness of this data is limited due to differences between reservoir and laboratory conditions. The cores might also have changed properties such as wettability, depending upon coring method, cleaning etc.

In order to screen the value of expanded water flooding a performance review of the Champion water flood reservoirs was carried out using reservoir engineering analytical techniques to generate reservoir fractional flow. The field's performance to fractional flow was matched using a set of Water-Oil relative permeability curves generated by Corey exponents and Buckley-Leverett / Welge theory. This match leading to an estimation of the likely uncertainty range in end point relative permeabilites of Water-Oil curves, mobility ratio and to calculate the expected production profile and ultimate oil recovery. Combined with the available SCAL data and a good understanding of past flood performance an ability to forecast future production was obtained. The work presented forms the first phase in the assessment of the value in expanding water flooding throughout the Field.

In essence the work recaptures the value of analytical methods within the workflow of present-day project developments.
The First Horizontal Underbalanced Well Drilled in Libya: A Case Study
Authors: Safar Husein A. , Majdoub Abdul-Hamid A. , Azhary Sadek A. , Qutob Hani , Chopty James , Obeidat Hassan
Published: December 2007

The National Oil Corporation (NOC) of Libya is considering adapting new technologies to ensure that strategic resources are optimally explored, developed and produced during the life cycle of their oil and gas fields. Among the various options available to achieve these objectives, Underbalanced Drilling (UBD) technology is considered one of the most effective methods.

Zueitina Oil Company, one of Libya's NOC affiliated companies, decided to pioneer the introduction of a new way of drilling horizontal wells in the depleted Sabah Field. Accordingly, UBD technology was utilized to drill the Zueitina Sabah G-55 well in the main Sabah field.

The main objective was to drill the horizontal reservoir section to TD @ 7628 ft MD eliminating/minimizing lost circulation such that no drilling time would be lost due to the need to cure losses or to mitigate other conventional overbalanced drilling problems.

The Sabah G55 well was the first underbalanced horizontal well to be drilled in Libya. The targeted formation is a mature reservoir that has been substantially depleted to a current estimated pressure of 1050 psi. The producing formation consists of two main reservoir zones; Zone I and Zone II, separated by a low porosity tight zone layer. Zone I is made up of dolomite and Zone II of limestone with good porosity development often up to 35%. Abundant fracturing is evidenced by mud losses while drilling, FMI, dip-meter, core description, pressure transient analysis, production performance and others.

This paper discusses the objectives, the planning, the drilling technology used, the performance of the horizontal UBD well compared to offset conventionally drilled wells, problems encountered and lessons learned during the first application of Underbalanced Drilling in Zueitina Oil Company, Libya.
A New Real-Time Monitoring Method for Sandstone Reservoirs' Acidizing
Authors: Zou Jianbo , Li Min , Zhao Liqiang , Wang Qiang
Published: December 2007

Real-Time monitoring of the acidizing process has been shown to be an effective method to improve matrix acidizing treatment and acid volume should be used, and to evaluate the effect of acidizing. As is well known, the basic principle of Real-Time monitoring is monitoring the change of skin factor. However, conventional Real-Time monitoring technique is based upon the measurement of the injection rate and pressure(either surface or bottomhole) during an acid treatment to estimate the change of the skin factor and evaluate the effect of acidizing. While, based on existing techniques, this paper presents a new Real-Time monitoring method which can obtain the change of skin factor by calculating the evolution of permeability and the acid effective penetration diatance during acidizing treatment. The paper also chooses an appropriate Mathematical Model fitting sandstone reservoirs, and then illustrates how to calculate the change of permeability, the acid effective penetration distance and the skin factor. Additionally, this paper develops corresponding program and performs an actual calculation. Results from this calculation agree well with the real case and demonstrate that this method is also an effective Real-Time monitoring technique. Conclusions drawed from this paper suggest this new technique is feasible.
Changes in Completion Strategy Unlocks Massive Jurassic Coalbed Methane Resource Base in the Surat Basin, Australia
Authors: Johnson R. L. , Scott S. , Herrington M.
Published: December 2007

abstract

Since the late 1990's, operators have drilled a number of coalbed methane (CBM) core and exploration wells to definethe gas resource potential of the vast and relatively unexplored Jurassic Walloon Subgroup (SG) in the Surat Basin. Unfortunately, early pilots used completion techniques that failed to fully assess the true potential of this reservoir. Firstly, openhole completions were trialed but had limited success because of fines influx and well collapse. Next, cased and cemented wellbores incorporating hydraulic fracturing stimulation treatments were attempted to improve wellbore stability, reduce fines influx and increase gas production; these wells were ineffective and many experienced problematic casing failures. Finally, an isolated, openhole, under-reamed completion technique was trialed and achieved commercial flow rates representative of the drill-stem testing data indicated from earlier exploratory drilling.

This paper describes the process, experiences and results leading to the present completion strategy. We note production, permeability and skin factors associated with early completions, as well as results obtained from large-scale implementation of this more effective completion method. As a result of this change, the resource potential of the Walloon SG has grown significantly and the operator has proven 3,712 Bcf of reserves from a previously undeveloped resource area.
The Cost of Carbon Capture and Storage in the Perth Region
Authors: Allinson W. G. , Dunsmore R. E. , Neal P. R. , Ho M. T.
Published: December 2007

This paper describes and reports the results of analyses of the costs of CO2 capture and storage in south-west Western Australia. We analyse the costs of capturing approximately 25 million tonnes per year of CO2, and injecting it one of three storage sites-the Gage sandstone offshore of Perth, the Dongara depleted gas field, and the Neocomian sub-crop offshore of Geraldton.

Our central estimates are that the real cost to capture, transport and inject CO2 for a period of 25 years is between A$58 and A$63 per tonne of CO2 avoided in A$2005 terms depending on the location of the injection site.

We also analyse how sensitive our cost estimates are to changes in key assumptions. The sensitivity analyses show that the costs of CCS can vary significantly with different assumptions for key variables.