bluuebunny/crossref_metadata_2025 huggingface dataset:
Remediation of Production Loss Due to Proppant Flowback in Existing Wellbores
Authors: Nguyen P. D. , Stegent N. A. , Ingram S. R.
Published: December 2007

This paper presents the results of experimental study and field case histories of a remedial treatment technique using a low-viscosity consolidating agent placed into the propped fractures by coiled tubing (CT) or jointed pipe coupled with a pressure pulsing tool. The treatment fluids are designed to provide consolidation for previously placed proppant near the wellbore without damaging the permeability of the proppant pack. The consolidation treatment transforms the loosely packed proppant in the fractures and the formation sand close to the wellbore into cohesive, consolidated, yet highly permeable packs.

Laboratory flow testing indicates that the proppant pack in a fracture model under closure stress required low-strength bonds between proppant grains to withstand high production flow rates. Field case histories are also presented to discuss treatment procedures, precautions, and recommendations for implementing the treatment process. One major advantage of this remedial treatment method is the ability to place the treatment fluid into the propped fractures, regardless of the number of perforation intervals and their lengths without mechanical isolation between the intervals. The fluid placement efficiency of this process makes remediation economically feasible, especially in wells with marginal reserves.
Effect of Resident Water on Enhanced Coal Gas Recovery by Simultaneous CO2/N2 Injection
Authors: Jahediesfanjani H. , Civan F.
Published: December 2007

Majority of the coalbed methane reservoirs contain large amounts of water at initial reservoir conditions. Presence of water in the wet coal results from the chemical and physical bonding of coal with water, and influences the properties of coals. Frequently, dewatering is necessary prior to methane production from coal. However, some water still remains in the coal cleat and matrix after dewatering. The remaining water influences the coal gas isotherm, changes the coal gas phase diagram, and hence affects the performance of the enhanced coal gas recovery by simultaneous CO2/N2 injection.

Experimental and theoretical are carried out to establish the multi-component gas, water, and coal isotherms under various pressures and coal grain sizes for both low and high rank coals. The obtained isotherms are used to describe the adsorption/desorption processes involving the system of CO2/N2/CH4/water mixtures in coals. It is determined that presence of water reduces the injected CO2/N2 adsorption rates on both low and high rank coals, and the methane production rate, depending on the composition of the gas and water phases, and the prevailing experimental conditions. It is demonstrated that a higher ratio of the injected nitrogen is required for wet coals than for dry coals to enhance the gas recovery by CO2/N2 injection.
Analytical Solution of Single-Probe Tests in a Horizontal Well and its Application to Estimate Horizontal and Vertical Permeabilities
Authors: Sheng J. J.
Published: December 2007

During a single-probe test in a vertical well, the probe of a formation tester is set horizontally against a side wall of the borehole. In a horizontal well, the probe can be set either horizontally against a side wall, or vertically against the top or bottom wall of the borehole. When the probe is set horizontally against a side wall, the solution for a horizontal well is the same as that for a vertical well. However, when the probe is set vertically against the top or bottom wall, the solution for a horizontal well is not available in the literature. This paper presents an analytical solution to the described problem.

The solution shows that the relationship between the pressure drop and flow rate for a single-probe test in a horizontal well depends whether the probe is set vertically or horizontally against the borehole. One of the important applications of the solution is to estimate horizontal and vertical permeabilities from two probe tests. If two tests are conducted at the same measured depth, with the probe set vertically in one test, while horizontally in the other, two permeabilities are obtained. Then the horizontal and vertical permeabilities at the measured depth can be estimated by combining these two permeabilities.

The analytical solution is validated by numerical simulation, and the solution is shown to be the same as a published analytical solution for a vertical well in an isotropic formation. Examples to estimate horizontal and vertical permeabilities from synthetic tests are presented.
Fracture Stimulation Utilizing a Viscoelastic-Surfactant-Based System in the Morrow Sands in Southeast New Mexico
Authors: Pandey Vibhas J. , Itibrout Tarik , Adams Larry S. , Cowan Tracy L , Bustos Oscar A.
Published: December 2007

This paper discusses the selection criteria, design methodology, and analysis of hydraulic fracturing treatments pumped using a solids-free, liquid CO2 foam-based visco-elastic surfactant (VES) fluid system in Morrow Sand reservoirs located in Southeast New Mexico (SENM).

The wells discussed in the paper were completed in various Morrow Sand intervals around 10,500 ft with an average Bottom Hole Static Temperature (BHST) of 190°F. Wellbore completion constraints combined with reservoir parameters inclusive of low-pressured water sensitive formations, high rock Youngs' Modulus and unpredictable occurrence of water-bearing zones, lead to the selection of foamed VES fluids. This technology was successfully applied in the Morrow Sands in Eddy County of SENM. Fracture geometry analysis using surface treating pressures, radio-active tracers and production data, showed height growth containment and longer effective fracture half-lengths. Results also indicated successful stimulation past the cement squeezed intervals and temporary liner tie-backs run in to overcome lower pressure constraints. Finally, lower friction pressures helped in designing economical fracture stimulations for mature wellbores thereby generating an opportunity to recover otherwise bypassed hydrocarbon reserves.
Application of Relative Permeability Modifiers to Control Water Cut Following Hydraulic Fracturing in Western Siberia Oilfields—Russian Case History Study
Authors: Borodin E. G. , Vakhroushev P. E. , Stolyarov S. M. , Kalfayan L. J.
Published: December 2007

Due to geological characteristics and low permeability of Western Siberia hydrocarbon reservoirs, hydraulic fracturing is the most effective method for improving hydrocarbon production. During recent years the massive fracturing treatments in this area have led to a reduction of well candidates for this type of production enhancement technique. Currently the majority of selected wells for fracture stimulation are considered "risky" because of significant water cut increase after stimulation. The question arises - How to reduce water production while enhancing oil production?

This paper reviews 26 case histories exemplifying the use of Relatively Permeability Modifiers (RPM) in hydraulic fracturing to enhance oil recovery and control water production. Also results of laboratory studies are included to support the RPM-fracturing concept and placement techniques.
Restimulation: Candidate Selection Methodologies and Treatment Optimization
Authors: Moore L. P. , Ramakrishnan H.
Published: December 2007

Restimulation of existing wells represents a vast underexploited resource. A successful refracturing treatment is one that creates a fracture having higher fracture conductivity and/or penetrating an area of higher pore pressure than the previous fracture. Refracturing requirements are different in highly permeable formations (high fracture conductivity) as compared to low permeable ones (moderate fracture conductivity). Understanding these basic differences is essential to a successful restimulation.

In the past, candidate selection methodology has focused on underperforming wells. This simplistic approach has yielded disappointing results and has led to a common misconception that restimulations "don't work." Production statistics of a well alone may not offer an effective restimulation candidate selection methodology. Other parameters such as high BHP (remaining reservoir energy), recoverable reserves, ϕ-h1 and favorable response to original fracture jobs (IP) could play an equally important role, if not greater, in determining the success of restimulation. In fact, studies have shown that selecting poor or underperforming wells for restimulation is likely to result in worse outcomes than random selection of workover candidates.

Studies performed to date have concluded that no selection criteria can be universally applied to every situation; rather that the selection methodology for workover candidates must be customized to fit particular situations. This paper explores the common traits shared by fields likely to have underexploited restimulation potential and suggests methodologies that should be applied to various field types The case histories illustrated in this paper will highlight the various treatment parameters optimized for successful restimulation. The conclusions of this paper are based on our work in selecting restimulation candidates as well as published results of other operators. Application of the correct candidate selection methodology to a particular field type will inevitably lead to a higher success rate of restimulation walkovers and the capture of an underexploited resource.
Applicability of the Forchheimer Equation for Non-Darcy Flow in Porous Media
Authors: Huang H. , Ayoub J.
Published: December 2007

The subject of non-Darcy flow in hydraulically fractured wells has generated intense debates recently. One aspect of the discussion concerns the inertia resistance factor or the so-called beta factor β in the Forchheimer equation and whether the beta factor β for a proppant pack should be constant over the range of flow rates of practical interests. The problem was highlighted in a recent discussion by Batenburg and Milton-Tayler1 and the reply by Barree and Conway2 regarding paper SPE 893253 in the JPT in August 2005.

To properly assess all the arguments and to get a better understanding of the state-of-the-art on non-Darcy flow in porous media in general, literature concerning the theoretical basis of the Forchheimer equation and experimental work on the identification of flow regimes is reviewed. These areas of work provide insights into the applicability of the Forchheimer equation to conventional oilfield flow tests for proppant packs. Models for flow beyond the Forchheimer regime are also suggested.
Long-Term Scale Inhibition Using a Solid Scale Inhibitor in a Fracture Fluid
Authors: Szymczak S. , Brown J. M. , Noe S. , Gallup G.
Published: December 2007

Prolonged scale inhibition in excess of one year is a desirable benefit of oil and gas well formation squeeze treatments. Traditionally liquid inhibitors have given the requisite inhibitor residual for up to one year. Operators desire longer inhibition periods. This paper describes a new scale inhibitor technology that extends scale inhibition beyond one year.

All of the components of a hydraulic fracturing package must be compatible to insure that the rheology of the fluid is not affected. The placement of a scale inhibitor onto a formation requires a suitable inhibitor that will adsorb to the mineral surfaces and return slowly with the produced water. Adding a solid scale inhibitor to a frac package required limited compatibility testing and reformulation in order to meet the fluid integrity and product effectiveness criteria. The scale inhibitor dosage was designed for a three-year life.

The accepted method of monitoring the effectiveness of a scale inhibitor squeeze is through measuring the scale inhibitor residual in the produced water. Traditional liquid scale inhibitors give a high initial residual (>1000-ppm) and deplete to a minimal level (1-10 ppm) within a year. The solid inhibitor placed on the formation during the frac released a residual below 50 ppm at the first reading and has maintained an acceptable level for the life of the placement (as of this writing the residuals are still above the minimum level).

Operators of offshore and remote area wells that are prone to scale deposition must undertake significant intervention measures to remediate scale deposition.1 This new chemical technology extends the life of a scale inhibitor placement beyond the current expectations. The advancement of this technology will save operators money and encourage the development of properties that might be viewed unprofitable due to the high frequency and cost of intervention.
Effects of High Oil Viscosity on Oil/Gas Flow Behavior in Horizontal Pipes
Authors: Gokcal B. , Wang Q. , Zhang H. -Q. , Sarica C.
Published: December 2007

Oil-gas pipe flows are expected to exhibit significantly different behavior at high oil viscosities. Effects of high viscosity oil on flow pattern, pressure gradient and liquid holdup are experimentally observed and differences in flow behavior of high and low viscosity oils are identified. The experiments are performed on a flow loop with a test section of 50.8-mm ID and 18.9-m long horizontal pipe. Superficial liquid and gas velocities vary from 0.01 to 1.75 m/s and from 0.1 to 20 m/s, respectively. Oil viscosities from 0.181 to 0.587 Pa·s are investigated. The experimental results are used to evaluate the performances of existing models for flow pattern and hydrodynamics predictions. Comparisons of the data with the existing models show significant discrepancies at high oil viscosities. Possible reasons for these discrepancies are carefully examined. Some modifications are identified and implemented to the closure relationships employed in the Zhang et al.1 model. After these modifications, the model predictions provide better agreement with experimental results for flow pattern transition, pressure gradient and liquid holdup.
Relative Permeability of Gas-Condensate Fluids: A General Correlation
Authors: Bang V. , Kumar V. , Ayyalasomayajula P. S. , Pope G. A. , Sharma M. M.
Published: December 2007

Predicting production from gas-condensate wells requires an accurate relative permeability model when a condensate bank forms. At high flow rates typical of many gas-condensate wells, the relative permeability is rate dependent. Such rate dependence can be modeled using a capillary number to calculate the decrease in residual saturations and the corresponding increase in relative permeability as viscous forces become dominant over the interfacial forces. New steady-state relative permeability data have been measured over a wide range of capillary numbers including very high values corresponding to the near-well region. These measurements have been made on several reservoir rocks as well as outcrop rocks and over a range of temperature, pressure, connate water saturation and hydrocarbon composition typical of gas-condensate reservoirs. PVT data of gas-condensate fluids can be used to predict the ratio of the gas to the condensate relative permeability and this simplifies the measurements and modeling since only data corresponding to the pressures near wells are needed. A relative permeability model developed at the University of Texas was tested using both new data and data from the literature. With only one parameter set, essentially all of the data for all rocks and conditions was fit within experimental uncertainty.
Using Downhole Real-Time Data To Estimate Zonal Production in a Commingled-Multiple-Zones Intelligent System
Authors: Sun K. , Konopczynski M. R. , Ajayi A.
Published: December 2007

Intelligent well technology provides the ability to monitor well bore data (e.g. down-hole pressure/temperature) in real time through down-hole sensors, and to control fluid flow into or out of the wellbore at each segment. However, integrating these real-time data into a reservoir management work flow and turning the data into measurable and tangible value is still an elusive and complex task.

This paper proposes a technique of integrating down-hole realtime pressure and temperature data to predict and allocate multiphase production in a multiple zone intelligent well system. The technique combines the known position of the installed zonal Interval Control Valves (ICV), measured realtime pressure and temperature data, available production data, and reservoir fluid properties, to estimate the production rate of each zone using customized ICV choke performance models.

In order to account for the impact of phase behavior on the prediction, fluid systems have to be corrected to the prevailing in-situ flow conditions. In light of this, an improved multiphase choke model for down-hole ICV is introduced in this study.

To demonstrate this technique, one example of a hypothetical two-zone intelligent well completion with multi-phase production is illustrated. The example shows how to use the surface production data, e.g., GOR, WOR, API, Gas S.G., and real-time gauge data with the multiphase choke model to predict production of each phase through the ICV.
4D Pressure Pilot to Steer Well Spacing in Tight Gas
Authors: Quint E. , Singh M. , Huckabee P. , Brown D. , Brake C. B. , Bickley J. , Johnston B.
Published: December 2007

Obtaining reliable and accurate formation pressures in micro-Darcy rock has been a formidable challenge for tight gas producers. However, it is these pressures that give the most unambiguous data to identify unique reserves. They help to determine the drainage areas as well as appropriate well spacing for tight gas reservoirs.

A 4D pressure pilot was designed and installed to measure pressure drop at two observation wells equipped with pressure gauges. The pressure gauges enable pressure monitoring along the wellbore (in space) and over time, hence the name 4D pressure pilot. Two wells were drilled with one in the maximum horizontal stress direction (aligned with the hydraulic fracture azimuth) and one perpendicular to this orientation. Each well was placed at approximately 660 ft from an existing producing well, corresponding to a conventional 10-acre pattern. Twenty pressure sensors were distributed over the 6,000 ft productive interval. One well showed significant depletion in the majority of the sands whereas the other displayed very little depletion.

This pressure data together with open-hole and production log data, core data, and geologic models was used to construct detailed static and dynamic models. The resulting history matched models were used to evaluate numerous well densities and patterns. This formed the basis for the two wells per quarter quarter section application for the center of the field, which was approved by the Wyoming Oil and Gas Conservation Commission. Similar data gathering activities have been initiated in other parts of the field to formulate a comprehensive, field-wide spacing plan.

Gauge configuration was designed to collect daily pressures in numerous sands without compromising future production. Combining existing systems offered by two contractors into an integrated package mounted external to the casing enabled us to acquire this data, while still allowing for hydraulic-fracture completion and normal production in the future when monitoring objectives were met.

Obtaining pressure data with dozens of permanent gauges is expensive, but we are convinced that given the significant impact on estimating gas in place, recoverable gas, drainage area and ultimately well spacing, it is cost effective.
Analytical Solutions for Compositional Three-Phase Four-Component Displacements
Authors: LaForce T. , Jessen K. , Orr F. M.
Published: December 2007

The goal of this paper is to obtain by the method of characteristics (MOC) analytical solutions for compositional paths in one-dimensional, dispersion-free flow of four components, when up to three flowing phases may be present. The method is applied to an idealized quaternary system that exhibits a large region of three-phase behavior in order to study the effect of compositional four-component, three-phase flow on hydrocarbon recovery.

Injection of water and carbon dioxide (CO2) into a porous medium containing decane (C10) and methane (CH4) is considered. Two phases may be present in the initial reservoir composition or the injection mixture. The majority of each composition route remains in ternary subsystems defined by the initial and injection compositions, with a shock connecting the two ternary subsystems. As a consequence, a C10 bank is always produced prior to water or CO2 breakthrough.

Water, CH4, and C10 are produced for an extended time before CO2 breakthrough when less than 26% CO2 is injected for the parameters used. The delay in CO2 production is a promising result for both CO2 storage and enhanced oil recovery (EOR). Conversely, if more than 26% CO2 is injected then the hydrocarbons are pushed by a gas bank. Hydrocarbon recovery is studied for a variety of injection and initial oil mixtures. Finally, analytical solutions are compared to finite-difference simulations to study the sensitivity of these complex displacements to numerical dispersion.
How To Establish a Mathematical Model for the Electrostatic Desalting Process Based on Pilot Plant Studies
Authors: Alves R. P. , Oliveira R. C.
Published: December 2007

For the control of any process it is essential to establish a mathematical model capable to correlate the operational and free variables to the respond variables. Experimental studies conducted at a lab pilot plant with different Brazilian crude oil showed that the performance of the electrostatic desalting process can be simulated by using a semi-empiric mathematical model. After an intermediate validation step, the results obtained from this model were used to determine the proper treatment conditions of several offshore desalting plants installed in Campos Basin – Rio de Janeiro, Brazil. The present work shows how the proposed mathematical model was established and its correlation with the data taken from the pilot plant for different crude oils in the range of 15° API up to 30°API. Finally it is shown the correlation relating the data obtained from the proposed model and others collected from processing plants installed in different refineries and offshore production systems.
Scaling Analysis of the Migration of CO2 in Saline Aquifers
Authors: Hesse M. A. , Tchelepi H. A. , Orr F. M.
Published: December 2007

CO2 storage in saline aquifers may be used to reduce greenhouse gas emissions. After injection the CO2–plume migrates along the top of the aquifer for hundreds to thousands of years. An estimate of the area invaded by the CO2–plume is of interest for site selection. During plume migration, CO2 is trapped as residual gas in the wake of the plume. Reduction of the mobile CO2 volume by residual trapping would limit potential leakage.

Plume evolution can be divided into an early stage, where the CO2 has invaded the full thickness of the aquifer, and a late stage where the plume has spread enough to occupy only the top part of the aquifer. In the early regime we choose local variables for the dimensional analysis, to obtain a scaling law for the tip position xtip ∝ t1/2. At late time we choose global variables, obtaining a new scaling relation, xtip ∝ t1/3. Numerical simulations confirm the change in scaling for the tip position.

We also discuss the effect of residual trapping on plume migration. We present semi-analytic results for a plume spreading in a horizontal aquifer and numerical results for a plume in a sloping aquifer. In the horizontal aquifer plume volume decays as a power law, so that the efficiency of residual trapping decreases with time. In the sloping case initial power law decay is followed by ever faster decrease in volume.

The change in scaling for the CO2 front has not been discussed before. This change from t1/2 to t1/3 scaling shows that the plume will spread significantly slower at late times, suggesting that the plume will stay more confined than early measurements would indicate. Residual trapping will be very effective in sloping aquifers, and may be the dominant trapping mechanism.
Imaging Seismic Deformation Induced by Hydraulic Fracture Complexity
Authors: Maxwell S. C. , Waltman C. K. , Warpinski N. R. , Mayerhofer M. J. , Boroumand N.
Published: December 2007

Microseismic mapping is extensively utilized in the Barnett Shale, to map hydraulic fracture complexity associated with interactions of the stimulation with pre-existing fractures. Previous studies have indicated a fair correlation between the well performance and extent of the seismically active volume. However, in addition to this measure of the extent of the stimulated fracture network, the characteristics of this fracture network is also expected to impact the well performance. In particular, the fracture spacing is believed to be important factor controlling the potential gas flow. In this paper, we utilize the density of the total seismic moment release (a robust measure of the microseism strength) as an indication of the seismic deformation that may correlate to the fracture density. The study uses a set of microseismic maps of hydraulic fracture stimulations, including cases where the stimulated reservoir volume measured by the extent of the seismically active region poorly correlated with the well performance. Incorporating the seismic moment density to assess the fracture density with the network extent, an improved correlation with the well performance was observed.
Successful Application of Six Key Elements in Integrating People and Technology Toward Quality Achievements of Angsi Field Development Team
Authors: Abd. Karim Rahimah , Shaufi Dahlan M. , Noordin Khairul Annuar , Noor Harun M.
Published: December 2007

Angsi is an integrated oil and gas development project in offshore east coast of Peninsular Malaysia. It is one of the biggest oil producers in Malaysia, contributing one-sixth of the total national daily oil production. During its planning and execution stages, the project has had many successes and positive outcomes. It has been recognized as the model of success for all domestic and international operations in PETRONAS Carigali Sdn. Bhd. (PCSB).

The uniqueness of achievements in Angsi project relies on the successfulness of integrating its people and technology. With the recent skyrocketing oil price, the trend has been to chase for additional reserves and maximize crude production, and make it happen by whatever means possible (new technologies, joint ventures, aggressive recruitments etc). However, many projects failed to achieve these targets, despite being equipped with niche and advanced technologies.

Angsi project has successfully overcome these obstacles. The secret relies in the six key elements that have been nurtured in the working culture of every team member, which are; People, Focus, Integrated Approach, Planning, Communication and Feedback Loop. With this unique culture, it has allowed the team to achieve major successes over the past 5 years.

Among those is the successful implementation of the largest platform-based hydraulic fracturing program worldwide, and first in Malaysia. This allows the development of 0.5 Tscf gas from the otherwise uneconomic tight gas reservoir. The team also managed to increase its reserves level 2.5 times from its initial size. Consequently, it increases Angsi's daily production rate from 65 to 115 Mstb/d. Finally, Angsi project successfully reduces its unit development cost (UDC) by 67%, lowering it from 5.1 USD/boe to 1.7 USD/boe.

This paper discusses how the six key elements have contributed to the successes of Angsi Field Development Project.
Field Success in Carbonate Acid Diversion, Utilizing Laboratory Data Generated by Parallel Flow Testing
Authors: Nasr-El-Din H. A. , Chesson J. B. , Cawiezel K. E. , Devine C. S.
Published: December 2007

In order to treat the total interval in an anisotropic, heterogeneous carbonate formation, acid diversion is necessary. Many diverting agents are commercially available which will plug higher permeability portions of the formation and divert the acid treatment to lower permeability zones. For an oil-productive reservoir solid diverting agents such as wax beads, benzoic acid flakes, or polymers are used. Several problems may be associated with the use of these diverting agents: 1) too much additive may be used which may result in a severe reduction in acid injectivity and diverter may be very difficult to remove after the treatment; 2) flow may not be diverted from one zone to the other, but, rather, flow is equalized between the high permeability zone and the low permeability zone.

Recently, viscoelastic surfactants have been used in acid treatments for diversion.1-3 The viscoelastic surfactant contains neither solids nor polymer so clean up is of no concern. The appropriate concentration of surfactant is determined by laboratory flow testing of formation cores under reservoir temperature conditions.2

A parallel flow set up has been constructed which allows independent monitoring of flow parameters for a higher permeability and lower permeability formation core pair. Data demonstrate, through pressure analysis and effluent volumes, that flow is diverted from the higher permeability core to the lower permeability core, until acid break through occurs. Pressure data are confirmed by acid effluent volumes which are collected at regular time intervals throughout testing. In all cases, the effluent volume through the lower permeability core is greater than through the higher permeability core. Core plugs are photographed and imaged by the CT-scan technique before and after testing. Parallel flow testing has also been applied to stage treatments in which a stage of stable foam of viscoelastic surfactant in 2 wt% KCl is injected prior to the main acid stage. Appropriate surfactant concentrations in the foamed stage are determined by flow testing with formation cores.

The results of core diversion testing and fluid rheology testing of both the foamed and non-foamed viscoelastic surfactant diverting fluids are discussed. Field case histories of the application of acid treatments, which are designed on the basis of laboratory generated data, are reviewed.
Feasibility Study of Managed-Pressure Drilling with Automatic Choke Control in Depleted HP/HT Field
Authors: Iversen F. , Gravdal J. E. , Dvergsnes E. W. , Nygaard G. , Gjeraldstveit H. , Carlsen L. A. , Low E. , Munro C. , Torvund S.
Published: December 2007

Drilling wells in depleted reservoirs is often characterised by a narrow operating window between formation pore pressure and fracture pressure. Drilling High Pressure High Temperature (HPHT) wells into a narrow margin reservoir is even more challenging, and Managed Pressure Drilling (MPD) techniques may be required in order to operate within safe limits.

Managing the annular pressure profile during MPD operations requires a robust and reliable drilling control system. The presented work treats some challenges and possibilities regarding a MPD choke control system under evaluation for a planned HPHT well in the Kvitebjørn Field in the North Sea. Here pressure management is to be achieved by regulating the choke opening and thereby compensating for downhole pressure variations.

Methodologies for automatic choke control during the drilling operation are assessed. A dynamic fluid flow model is used to calculate well pressures for application in the choke control algorithms, and to simulate pressure response in the well. The performance of choke control during drilling operations is evaluated and results from simulations are presented.
The Continuous Circulation System—From Prototype to Commercial Tool
Authors: Calderoni A. , Brugman J. D. , Vogel R. E. , Jenner J. W.
Published: December 2007

This paper follows the evolution of the Continuous Circulation System (CCS™) from the prototype to the first models available for commercial application. It reviews the mechanical and control system changes introduced following the prototype trials to make the CCS more user friendly and mechanically reliable. It also discusses the approach of the constructor to the introduction of the system to the drilling industry and its determination to provide reliable and fit for purpose equipment.

Utilisation of the CCS could significantly change the way that drilling operations are carried out in certain "difficult to drill" formations. The ability to maintain uninterrupted circulation while making connections with jointed drillpipe is of considerable benefit when drilling formations where there is a narrow margin between fracture pressure and pore pressure gradients. With continuous circulation a steady ECD can be maintained and the positive and negative pressure surges, associated with making a connection under normal drilling conditions, avoided. Improved hole cleaning and the elimination of connection gas kicks can also be achieved.
Performance Appraisals of Gas/Oil Separation Plants
Authors: Kokal S. , Al-Ghamdi A.
Published: December 2007

Produced crude oil is typically processed at wet crude handling facility (WCHF) or a gas oil separation plant (GOSP). Most of the crude is commingled with water and produced in the form of emulsions that are separated at the GOSP using demulsifiers. In general, the emulsions at the inlet of Saudi Aramco GOSPs are tight and no free water is observed in the feed stream. In spite of the tightness of the emulsions, the demulsifier costs per barrel of produced oil in Saudi Aramco are one of the lowest in the world.

This paper describes the performance appraisal of several Saudi Aramco GOSPs. It also discusses the evaluation of these facilities and the efforts undertaken to reduce and optimize the costs of oil-water separation. The most important effort was the characterization of emulsions from various fields. It shows the relative tightness of emulsions and the associated causes of tightness. It has become a diagnostic tool in the quest to understand the causes and treatment of emulsions. The inlet emulsions were characterized by conducting field tests at each of the GOSPs using fresh emulsion samples. The factors associated with the tightness of emulsions include the amount of fine solids such as asphaltenes and scales in the crude, watercuts, temperature, brine chemistry, and shear. Another aspect of oil-water separation investigated was the effect of processing equipment and vessel retrofitting. These included the conversion of two-phase (gas-liquid) separators into three phase (gas-oil-water) separators, installation of coalescer packs, demulsifier injection strategies and use of online analyzers. An innovative approach to optimizing oil-water separation is described. The paper provides invaluable operational experience and many ‘lessons learned’ are applicable to other crude oil treating facilities.
Technical Specialists or Business Managers: The Choice Being Made by Young Professionals at the Beginning of the New Millennium
Authors: Tealdi L. , Etkind J. , Bruni T.
Published: December 2007

Survey results indicate that the majority of todays young professionals (YP's) are keen to consider cross-disciplinary moves within their company and look forward to a future in management positions. They often perceive the "technical professional" career as second class with respect to the managerial one. This is a significant obstacle to the optimum functioning of any organization considering that a solid technical background is at the heart of any successful career in any technical business, especially in the E&P sector. New oil and gas reserves are becoming more and more challenging to discover and the basins in which the discoveries are occurring are geographically isolated, environmentally sensitive, and require technology that has yet to be developed. At the same time, the industry technical leaders who drive these projects forward against all odds are aging and are expected to retire within the next ten to fifteen years. As the next generation of E&P industry workers strive to maintain technical focus while harboring managerial aspirations, the industry itself is struggling to define its development expectations for them.

This paper reviews various historical efforts to equalize the technical and managerial career tracks such as the dual career ladder. Three surveys of young professionals working around the world are presented, analyzed and discussed. YP's aspirations are juxtaposed against corporate and industry needs to highlight their incongruity. This paper highlights the importance of greatly enhancing the attractiveness of the technical career track in order to bring the industry workforce goals back in line with corporate goals and provides the next generation of industry workers with some insightful career advice.

Finally, strategies will be proposed to restore balance and possibly erase the perceived distinction between managers and technical professionals with the final objective of maximizing companies' performance over the long term.
Removal and Mitigation of Calcium Carbonate Scale in a Sandstone Reservoir in Saudi Arabia: Long-Term Field Monitoring
Authors: Nasr-El-Din H. A. , Al-Saiari H. A. , Al-Ruwaily A. A.
Published: December 2007

Calcium carbonate scale was detected in several vertical wells in a sandstone reservoir in Saudi Arabia. The scale was found downhole, plugging gravel-pack screens and the intake of submersible pumps. Scale build-up caused decline in oil production from this field. The sandstone reservoir is water-sensitive and has a bottom-hole temperature of 160°F.

An emulsified-type scale inhibitor (phosphonate-type) treatment was designed to mitigate scale formation in this field. The treatment was successfully applied in more than forty-five wells. Some of these wells were de-scaled before the treatment, while others were treated before scale detection. Moreover, some of the wells were subjected to two scale mitigation treatments.

The main objective of this paper is to assess the long term outcome of the scale squeeze treatment based on field data. A second objective is to determine the actual minimum inhibitor concentration (MIC) and treatment lifetime. In addition, the impact of the second squeeze will be investigated. Samples of produced water following the scale mitigation treatment were collected and analyzed over the last five years.

The emulsified scale squeeze treatment was successfully conducted in wells with water-cut that ranges from 3–80 vol%. No operational problems were encountered during the first and second scale inhibitor squeeze treatments. The inhibitor return following the second squeeze treatment was similar to that noted following the first treatment. Lower scale inhibitor return in term of phosphorous was noted after re-squeezed treatments than that of the first squeeze. The volume of the scale inhibitor was affected the levels of the inhibitor in well flow back samples. Most of the treated wells have lifetime more than two years and the actual MIC in Field H was found to be nearly 0.9 mg/l.
Pricing of Long-Term Oil Service Contracts and Financial Risk Management
Authors: Lyadina-Saville E.
Published: December 2007

Pricing of long-term oil service contracts assumes projection of many components of business environment into the future. Since volatility of business, financial, and political factors have recently dramatically increased, the intelligent quantitative analysis of financial risks and their incorporation into bid/offer price curves, became of primary importance.

In this paper, we describe a commercial model for pricing long term contracts based on term-structure approach and incorporating effects of various types of financial risk, including interest rate risk, currency exchange risk, credit risk, legislation risk etc. We present a generic model of a long-time contract, and methodology of initial valuation of at-market contract, and its re-valuation during the term of agreement.

The model is applicable to a broad range of strategic marketing decisions, when effects of various types of financial risks and the duration of the contract are taken into account.

We discuss how a long-term contract may act as a tool for asset-liability management, creating a preferable risk exposure profile, and for exchange of risks between parties in a mutually beneficial manner, thus creating a ‘win-win’ business situations for both operator and service company.
An Integrated Approach to the Design and Evaluation of Hydraulic Fracture Treatments in Tight Gas and Coalbed Methane Reservoirs
Authors: Aghighi M. A. , Valencia K. J. , Chen Z. , Rahman S. S.
Published: December 2007

This paper presents a comprehensive approach to the design of hydraulic fracture treatments which takes into account anisotropic stress conditions, rock properties and the effect of pore pressure changes due to production in tight gas reservoirs. This has allowed us, among others, to design a re-fracture treatment. Our poroelastic model is also coupled with a production optimization scheme to optimize the design parameters for hydraulic fracture treatments.

In this paper, we present the results of a study carried out in a tight gas reservoir. Our study has shown that the fracture treatment can be successfully optimized to increase the NPV and/or ultimate gas recovery. We also demonstrated through this study that a second fracture treatment can be carried out after a period of production from the same treated interval to maintain production without drilling additional wells.
Case Study of Permeability, Vug Quantification, and Rock Typing in a Complex Carbonate
Authors: Gomaa N. , Al-Alyak A. , Ouzzane D. , Saif O. , Okuyiga M. , Allen D. , Rose D. , Ramamoorthy R. , Bize E.
Published: December 2007

This case study demonstrates a new method to compute continuous permeability and estimate reservoir rock type from logs in a complex, heterogeneous, Middle Eastern carbonate reservoir. The 795 ft conventionally cored interval consists of interbedded limestones and dolomites with anhydrite cement and features a wide variety of textures. In some intervals the depositional textures are preserved, in others they are highly altered by diagenesis. Vugs are developed in several intervals. Computation of permeability from porosity alone yields scatter of a factor of 700. Rock typing using only conventional logs was unsatisfactory due to the poor permeability estimation.

The effect of geological complexity on the log based prediction is overcome by including pore size distribution data from a combination of NMR and borehole electrical image logs. This data is sufficient to partition the porosity according the pore size, compute permeability and assess the rock types, independently of mineralogy, facies, and other variables. The results are validated by comparison to core derived properties and formation tester mobilities. Incorporation of the pore size information into the log based interpretation reduces the scatter in computed permeability to a factor of less than 10. The assumptions and principles of the log analysis method were validated in the lab through extensive characterization of the pore system over a range of scales. Data from a variety of methods including MICP, lab NMR, BET surface area, thin section analysis, continuous vuggy porosity analysis from the core slab, minpermeametry and other advanced research methods are included.

A key result of this study is that a relatively simple method for log derived permeability and rock type analysis in carbonates, first developed in high porosity limestones, can be successfully applied in this lower porosity (10 – 20 p.u.) carbonate. This gives us confidence to project that the method could be applicable to many other carbonates worldwide.
Well Location Selection from Multiple Realizations of a Geomodel Using Productivity Potential Maps–A Heuristic Technique
Authors: Guerra N. Y. , Narayanasamy R.
Published: December 2007

Heuristic technique may be called as an "intelligent guess", which reduces the search for the right answer of a usually complex problem. Such techniques are aimed to dramatically reduce the time required to solve a problem. This paper examined the Productivity Potential Map (PPM) technique as a heuristic approach tool in assisting the reservoir engineer to choose optimum well locations for field development planning. Eleven well locations were selected using PPM technique and compared with the same number of wells located using conventional STOIIP based methodology.

The exercise used information from six vertical wells in Field A, Otter Sandstone Formation (Sherwood Group). It is a discontinuous fluvial system with highly variable permeability patterns which poses a significant challenge for selecting well targets.

A comparison of simulated flow performance showed that well locations selected using PPM technique exhibied consistently better performance and minimum variance. STOIIP and PPM techniques resulted in two totally different templates for the selection of well locations. PPM technique was coherent with the expected geological trend of the area than the trend showed by the STOIIP technique.

The exercise showed that the PPM technique is a valuable method in delineating reservoir regions with favourable production potential for well placement, especially in complex sedimentary environments.
Coupled Pressure-Transient Behavior and Geomechanical Deformation in the Near-Borehole Region of Unconsolidated Clastic Rock Formations
Authors: Lee H. , Torres-Verdín C. , Sepehrnoori K.
Published: December 2007

We describe the development and successful testing of an axial-symmetric simulation algorithm that couples geomechanical deformation with pressure-transient analysis in a stressed vertical borehole. The objective is to quantify the sensitivity of two-phase flow properties of unconsolidated clastic sediments to presence of wellbore stress. We consider the situation in which the mechanically stressed rock formations are probed with a dual-packer formation tester to assess petrophysical properties. The simulation takes into account the mechanical deformation of the rock due to in-situ stresses as well as by wellbore stress imposed by overbalance mud circulation and by the dual-packer itself. Mechanical deformation of the compressible rock causes variations of the porosity and permeability in the near-wellbore region that are evidenced by the pressure transients measured with the dualpacker pressure probes.

The processes of multi-phase flow in the near-wellbore region due to mud-filtrate invasion and fluid pumpout are simulated with an IMPES finite-difference formulation that assumes axial-symmetric petrophysical properties and fluid distributions around the axis of a vertical borehole. On the other hand, mechanical deformation is simulated with a finite-element code that assumes 2D axial-symmetric linear deformation. The latter simulator assumes a pre-stressed initial condition due to mud overbalance and computes the incremental deformation due to fluid pumpout with the formation tester. Coupling of mechanical deformation with porosity and permeability assumes a staggered-in-time loosely coupled volumetric model that is enforced by the time-marching IMPES formulation. Sensitivity studies for the case of unconsolidated clastic formations indicate that relative variations as high as 15% in porosity and as high as 13% in permeability can ensue in the near-wellbore region due to overbalance mud pressures of 700 psi and wellbore pressures of 6500 psi applied by the inflatable packers. Such spatial variations of petrophysical properties can significantly bias the corresponding pressure-transient measurements performed with the dual-packer formation tester.