bluuebunny/crossref_metadata_2025 huggingface dataset:
Characteristics of Microgels Designed for Water Shutoff and Profile Control
Authors: Feng Yujun , Tabary René , Renard Michel , Le Bon Christel , Omari Aziz , Chauveteau Guy
Published: December 2007

Two microgel samples were prepared by crosslinking an acrylamide-based terpolymer solution with a non-toxic zirconium crosslinker under controlled shear flow. The characteristics of these two microgel samples were determined by using different laboratory techniques in order to evaluate their performances for water shutoff or profile control operations. The microgel size was measured by Photon Correlation Spectroscopy (PCS) in dilute regime and at small scattering vector. As predicted by our theoretical model, microgel size decreases as the -1/3 power of applied shear rate. The size of these microgels is almost independent of pH, salinity and temperature in the domain investigated. Their mechanical and thermal stability is also satisfactory. In addition, such microgels can be easily injected into porous media without any sign of plugging. All these results suggest that these microgels should be good candidates for water shutoff and profile control operations. However, a further investigation is required to optimize their preparation to obtain the desired properties for a given application.
Novel Scale Inhibitor Polymers with Enhanced Adsorption Properties
Authors: Davis K. P. , Fidoe S. D. , Otter G. P. , Talbot R. E. , Veale M. A.
Published: December 2007

A new range of polymeric scale inhibitors has been developed combining exceptional scale control activity with enhanced adsorption properties. The polymers are stable up to at least 200ºC and have high activity against barium sulphate and calcium carbonate scales. By incorporating novel end-capped technology, it is now possible to produce scale inhibitors with improved adsorption properties which provide significantly extended squeeze lifetimes relative to conventional technology.
PWRI: Scale Formation Risk Assessment and Management
Authors: Mackay E. J. , Collins I. R. , Jordan M. M. , Feasey N.
Published: December 2007

The injection of seawater into oilfield reservoirs to maintain reservoir pressure and improve secondary recovery is a well-established, mature, operation. Moreover, the degree of risk posed by deposition of mineral scales to the injection and production wells during such operations has been much studied. However, the current drive within the North Sea to reduce the environmental burden of production chemicals and to reduce oil discharge to the environment has focused attention on the challenge of produced water management and has introduced new challenges for scale management involving produced water re-injection.

This paper will outline the risk assessment process required prior to undertaking produced water re-injection. The factors that will be considered are the location of scale deposition around fractured and unfractured injection wells, formation damage potential and impact, and retardation effects on injected scale inhibitors.

The paper will draw upon computer modelling techniques, laboratory generated coreflood data, and field results that will demonstrate the impact of the following factors on long term water injectivity: viz, scaling tendency, suspended solids content, suspended oil content, injection temperature, reservoir type, and completion type. Furthermore, scale control measures currently being employed (e.g., scale inhibition, hydraulic fracturing, drag reduction, and solvent cleaning) will be assessed and reviewed against the risks identified. Finally, this paper will outline in detail the particular scaling issues associated with produced water re-injection for both platform and subsea facilities.
Development of a Novel Water in Oil Microemulsion Based Scale Inhibitor Delivery System
Authors: Miles A. F. , Bourne H. M. , Smith R. G. , Collins I. R.
Published: December 2007

Water in oil (w/o) formulations containing a range of scale inhibitors have been prepared for squeeze application. Depending on their composition these have been found to be either microemulsions or weakly structured mixtures.

A particular feature of the materials described is the type and concentration of surfactant used. High concentrations of surfactants are traditionally required to generate and stabilise conventional microemulsions. However, the back-production of the surfactants following a squeeze may cause undesirable process upsets. To minimise these upsets and to maximise the performance of the delivery technique, novel complexing agents, which, when combined with suitable scale inhibitors, form semi-stable species capable of stabilising w/o systems have been developed.

A detailed investigation of the properties of selected materials has been performed and experimental measurements including phase behaviour, reservoir condition coreflood tests and inhibitor desorption data are presented. A new technique which provides data in-line with core performance tests is also described.

The possibility to utilise the phase behaviour of these materials to increase squeeze life is also explored. Data for Miller Field conditions, showing an increase in squeeze life, are presented.
Conditions For Scaling In Pipelines – Ph In Glycol Solutions
Authors: Seiersten Marion , Dugstad Arne , Gulbrandsen Egil
Published: December 2007

If a glass electrode calibrated in aqueous pH standards is used to measure H+ concentration in aqueous glycol solutions the result will be in error due to the large change in solvent properties. Based on strong acid – strong base titrations in glycol solutions it is possible to calibrate glass electrodes. The titration does not only give the calibration constant for the electrode, but also the autoprotolysis constant for the solvent can be determined. The calibration method makes it possible to determine acid constants in glycol by potentiometric titration.
Barium Sulphate Precipitation In Porous Rock Through Dispersive Mixing
Authors: Woods A. W. , Harker G.
Published: December 2007

We describe the reaction which occurs when formation fluid containing Ba in solution is displaced by and mixes with injected water, containing sulphate, to form BaSO4. The model is based on the conservation of mass of both the barium and sulphate, assuming that each species is advected with the flow, and that at the interface between the two fluids, dispersive and diffusive mixing of the fluids leads to precipitation. The model equations are solved numerically, and a simple asymptotic model for the reaction, valid at long time, is developed. This identifies that in a linear geometry, the mass of solid which forms when the front has distance x from the source, decays at a rate proportional to 1/x½. The modelling approach may also be used to describe injection into a radial geometry, leading to an analogous asymptotic model for the decay of solid precipitate with distance from the injector well.
Scale Formation in Iranian Oil Reservoir and Production Equipment During Water Injection
Authors: Moghadasi J. , Jamialahmadi M. , Müller-Steinhagen H. , Sharif A. , Ghalambor A. , Izadpanah M. R. , Motaie E.
Published: December 2007

This paper presents the mechanism of scale formation by water in oil fields and suggests an accurate model capable of predicting scaling phenomena in Iranian Oilfield operations due to mixing of incompatible waters or change in thermodynamics, kinetics and hydrodynamic condition of systems. A new and reliable scale prediction model which can predict scaling tendency of common oilfield water deposits in water disposal wells, water-flooding systems and in surface equipment and facilities is developed and present. The development of the model is based on experimental data and empirical correlation, which perfectly match Iranian oil fields conditions. Furthermore the simultaneous deposition of oilfield scales and competition of various ions to form scale which is common phenomena in oil fields are reflected in the development of the model allowing the effect of each scale on the others to be taken into account. The new model has been applied to investigate the potential scale precipitation in Iranian oilfields, either in onshore or offshore fields where water injection is being performed for desalting units’ water disposal purpose or as a method of secondary recovery or reservoir pressure maintenance.
Rejuvenation of Matured Oil Fields in South Sumatra, Indonesia
Authors: Aprilian Salis , Kurnely Kun , Novian Kiagus
Published: December 2007

Pertamina DOH SBS located in South Sumatra, Indonesia, operates the largest area of oil fields under Pertamina own operations. It has 55 fields mostly discovered and developed fifty years (even for some more than a hundred years) ago. The common problems encountered in the old oil fields are lack of data; old facilities; artificial lifts requirement, depleted in pressure and reserves; and high water cut problems.

This paper reviews a comprehensive study on rejuvenation of the matured fields in Pertamina DOH SBS by employing a cross function synergy team (multidiscipline team) and project management approaches. The teams consist of geophysicists, geologists, reservoir engineers, operation/ production and facility engineers, and professionals from supporting department such as finance, logistics, HSE, HRD, IT, etc. The project called Production Enhancement Projects (PEP) was established in 2001 and divided into phases.

The first phase of PEP that was assessing detailed subsurface and surface facilities data has been done successfully resulting in 45.6 MMBO of additional oil reserves within 12 selected existing matured fields. Besides, the upside potentials are identified as a surprising spill over of the study.

Plan of further development for each field has been proposed including the evaluation of economics and environment aspects by considering in-depth GGRP (geophysic-geology-reservor-production) study and intensive discussion among team leaders, team members, and management. After prioritizing the proposed work plan, several implementations of well work (such as: reopening; re-perforating; reparation; sidetracking, twin drilling; etc.) show some successful results. At least two wells will be drilled this year (2002) to prove the upside potentials of oil located in deep zones of the existing fields.
An Integrated Sand Control Method Evaluation
Authors: Samsuri Ariffin , Sim S. H. , Tan C. H.
Published: December 2007

A numerical model has been developed that is able to predict the onset of sand production and evaluate the performance of sand control, should sand production becomes unavoidable. The simulation of perforation stability was carried out first using a two-dimensional, two-phase finite-element model. This is a coupled geomechanical and fluid flow model. The rock was assumed to be heterogeneous and the pores were completely filled with fluid. The deformation condition is considered as plane strain and either the Mohr-Coulomb or Drucker-Prager yield surface was used to designate perforation failure. The model enables the study on the effect of perforation pattern and density on wellbore stability. Simulation runs on a sample model indicated that the lowest pore pressure, the greatest shear stress and minor principle stress were found close to the perforation tip. The greatest major principle stress occured around the center of perforation roof. In other words, the perforation was always surrounded by high stress concentration. In those events when sand production is a certainty, it is necessary to evaluate the performance of sand control methods to be used. A finite-difference flow model was used to calculate the additional pressure drop from the well boundary to the sand control screen. The Forchheimer equation was used in place of the more conservative Darcy equation so that the effect of high-velocity flow to the well performance could be considered. The result of several sample runs indicated firm relationship between total additional pressure drop and the flow rate imposed, where a larger flow rate will cause greater pressure loss. Also, the well productivity showed improvement with more shots per foot. The results suggested that the majority of well pressure drop was caused by the casing-cement tunnel.
Improved Oil Recovery through the Use of Horizontal Well in Thin Oil Column: A Case Study from Platong Field, Gulf of Thailand
Authors: Maroongroge Vichai , Sandarusi Kamal A. , Schmalz Arlen , Schut Gerard , Nucharoen Panaratn
Published: December 2007

This paper presents a case study of analysis that leads to the decision to drill the first horizontal oil well (G-21) in the Platong field in the Gulf of Thailand. The application of horizontal well technology in this field is a challenge because of low seismic resolution, small-sized reservoirs, and stacked reservoir systems. Successful use of horizontal well technology requires an integrated team approach that incorporates all available data to justify a business case for drilling the well.

The 37B sand in the Platong field has a 30-foot oil column, a small gas cap and a large underlying aquifer. Well G-18 is a vertical producer in the 37B sand that penetrates the oil column and aquifer with only 11’ of net pay. The well has produced over 500MSTB. However, because the completion lacked a means of artificial lift, flowrates were restricted once water production began. Eventually, the well was only capable of intermittent flow. A material balance analysis indicated the minimum original oil in place (OOIP) of 4.5 MMSTB with a strong water support. This volume estimate was also supported by seismic analysis and geological correlations. A reservoir simulation study was conducted with an aim to improve the oil recovery by investigating several production strategies. Since there is a free source of CO2 gas available, an evaluation of CO2 miscible flooding was also conducted. Results show that the minimum miscibility pressure (MMP) is much higher than the reservoir pressure and miscible gas injection is not suitable for this reservoir. The presence of a small gas cap and a strong bottom water drive led to the decision to drill a horizontal well. Simulation shows that a 1,000' long, horizontal well optimally placed in the gas cap is the simplest and best strategy to recover more oil from this reservoir. The estimated incremental oil recovery is 1.2 MMSTB.

Performance results after drilling show that the well is an economic success and also proves that the same integrated team approach can be used successfully in the development of other analogous reservoirs with similar geology. The economic success of this well also shows that there is a potential for additional oil reserves in the shallow zones above the current pay window. To date, as many as 40 additional prospects have already been identified for horizontal well candidates to further the oil development for the field.
In-House Design & Modifications Improve Sour Gas Processing in an Indian Offshore Gas Field – A Case History
Authors: Shankar Ravi , Kumar Adesh , Gupta V. P.
Published: December 2007

BXY field is the largest gas field of India, located in offshore, 80 km from Mumbai city. The field produces about 32.5 MMscmd sour gas using two process complexes BXA & BXB. The field was put on production in September’1988 with initial gas production of about 2 MMscmd. The field attained a gas production of 10 MMscmd during 1994 and this was the period when some operational problems were observed at one of the process complexes i.e. BXA.

The sour gas processing (H2S >100 ppm) at BXA involved cooling of well stream fluids (from 95 to 43 °C) in shell-tube type well stream coolers, three phase separation of well fluid and finally transportation of gas & condensate to shore terminal at a distance of about 230 km. Initially each complex was designed for lesser capacity which was upgraded to 15 MMscmd in 1995-96 after progression of field development. No problem was observed in BXB complex. In BXA complex, the processing temperature exceeded the normal temperature of 43 °C. This resulted in rising trend of moisture content in sales gas, high consumption of TEG (2-3 times more than normal value) in dehydration unit and increased load on operational staff for monitoring. Frequent failures of pipe & fittings of gas cooling system were observed. Well stream coolers had problem of air locking & cooling water flow across coolers came down to half quantity. Overall, severe operational problems were observed in the plant.

An in-house analysis was carried out to resolve these problems. The analysis of total processing system viz. gas cooling system, gas dehydration system, condensate stabilization system was made. Based on analysis, it was found that gas cooling water system is the bottleneck. The various components including material of construction of various equipment of this unit were analyzed and causes of operational problems resolved. A new cooling water system known as "cooling water segregation system" was conceived, designed and installed at BXA complex & other suitable measures undertaken. These efforts have streamlined the operating conditions of plant and are now processing 16.5 MMscmd gas without any problem.

The present paper describes stepwise identification of problems, design, review, installation of newly designed system and other issues to resolve the operational problem in this major processing complex. The improved design on implementation resulted in smooth operations in the plant and is working since then without any problem.
Case Analysis on Hydrocarbon Alternative Gas Miscible Flooding in PuBei Oil Field
Authors: Guo Ping , Wang Zhonglin , Tan Guangtian , Yang Kailei , Liu Bin , Lun Yukai , Zhang Maolin
Published: December 2007

PuBei oil field is the first sand oil reservoir to perform hydrocarbon miscible flooding in china. It has integrated, good connecting formation with undeveloped cracking system and permeability of 110.5*10−3 μ m2.It is a typical volatile oil reservoir .MMP is 33Mpa.Injection gas is the by-produced gas. After systematically plan design and research, field production stared. Though lad experiment showed that oil recovery by primary gas injection is higher than primary water injection, there were still some controversies. Thus, the field was developed by primary water injection at east and primary gas injection at west, keeping formation pressure at 35 Mpa. At early exploration time, there were seven injection wells and eight production wells. Now, there are nine production wells and two gas injection wells, seven water injection wells. The velocity of oil production is 44t/d, gas injection is 14.55*104m3/d, water injection is 144 m3/d. it has developed for three years till October 2001; the oil recovery is 19.05%, the synthetic water saturation is 3%. There are certain increases of GOR in some production well but no obvious gas breakout. Primary water injection well cannot change to gas injection since gas cannot be injected after water injection, so cannot perform GAW in east area. This paper introduces general geometry character, basic experimental study, exploration performance, and existing problem of the reservoir and gives some proposals, which is helpful in exploration the similar oil reservoir by miscible flooding.
Angsi Waterflood Management and Surveillance - An Integrated Team Approach
Authors: Othman Mohamad , Salleh Zaimi , Redmond John , Jakobsson Nils M. , Yunus A. Rahman , Abu A. Kamarolaili
Published: December 2007

The Angsi field is a new oil and gas development in its early production phase. The field is operated by PETRONAS Carigali Sendirian Berhad (PCSB), Peninsular Malaysia Operations (PMO). Waterflooding is being used to improve oil recovery. The waterflood is expected to yield close to a three fold increase of the oil recovery compared to a scenario without injection. The production from waterflood reservoirs contributes 90% of the overall Angsi oil production. It is imperative that the waterflood is managed in a prudent way to ensure its full potential is realized. An instrumental element of prudent management is a well-planned and well-executed surveillance program. The Angsi waterflood project, as many other waterflood projects, is significant in scope and multi-disciplinary in nature. It was determined that the adoption of an integrated team approach would be the optimal way to facilitate prudent management and surveillance of the Angsi waterflood project, and consequently that it would be an essential key to a successful waterflood.

The purpose of this paper is to discuss the integrated team approach adopted for the Angsi waterflood project. The paper describes how the team was built and how it has functioned during its first year. Included in the paper is a discussion on the Angsi integrated waterflood management and surveillance program. The program was developed by the team and now serves as a guideline for all Angsi waterflood related activities.

Adopting an integrated team has provided the necessary forum for open and inter-disciplinary exchange of ideas and experiences on waterflood related matters. As a result, it has aided the fostering of cooperative actions and the capturing of synergism, all to the benefit of the Angsi waterflood project.

Thus far, the integrated team approach has resulted in a timely commissioning of the water injection plant, and a high plant uptime and water injection availability.
Resolving Development Strategy by Integrating Geophysical, Geological and Pressure Transient Test Data: A Case Study of Heterogeneous Lower Eocene Sand of Upper Assam Basin, India
Authors: Lama Tshering , Phukan Jayanta , Neog Pankaj Kumar , Rath Satchidananda
Published: December 2007

A multi-disciplinary approach had been adopted to resolve the exploitation and development strategy for Deohal and its extension oilfield having mainly the deep Eocene clastic reservoirs which is geologically complex, over pressurized stack of thin sands [by 30-40 Kg/cm2 (assuming 0.1 Kg/cm2/m hydrostatic gradient] interbedded with shale/ carbonaceous shale. An accurate delineation of individual sand in such reservoirs is beyond the resolution of seismic as these occur at a depth of 3600 to >4000 m and its thickness vary from 2 to 4 m only. The Lithostratigraphic correlation based on well log is often unreliable/ difficult due to thin and extreme heterogeneous nature of the sediments. Moreover, areal extent of reservoir as a single unit is difficult to ascertain. The petrophysical properties viz. porosity and permeability substantially deteriorate with increase in depth i.e. below 4000 m.

Initially 3D seismic data was showing a broad faulted anticline with fault 500 m to 800 m away from the crestal part. Analyses of pressure transient data showed barrier nearby and reinterpretation of 3D seismic data confirmed the presence of minor faults having limited extension.

The Paper presents how transient well test data in conjunction with static 3D seismic data, wireline log and dynamic pressure-production data have helped to workout development strategy for a geologically complex and heterogeneous Lower Eocene thin sand reservoir in one of the oilfields in Upper Assam Basin, India.
A New Method for Predicting Interwell Remaining Oil Distribution in Multilayer Sandstone Reservoirs at High Water Cut Stage
Authors: Qinglong Du , Bingyu Ji , Xiaoguang Lu , Lihua Xie , Yubo Lan , Lihong Zhu
Published: December 2007

Since the remaining oil distribution is characterized by scatter and complex in multilayer sandstone reservoirs at high water cut stage, a new method is put forward in this paper to predict interwell remaining oil distribution by using cores, logging data, geologic model and production testing data. Firstly, the interwell sandbody prediction model are set up to predicte interwell sandbody thickness and sedimentary microfacies by using geostatistics and stochastic modelling methods. Secondly, the remaining oil prediction models of various reservoirs are set up by combining the expert system and neural network based on the comprehensive analysis of the relationship between watered-out degree and influential factors in various layers of inspection wells and separated layer testing wells. These factors include sedimentary microfacies, sandstone thickness, structural pattern, communicating states of sandbody with surrounding water injection wells, and injection distances, intensity of water injection, injection-production relationship.The above-mentioned models are used to predict the interwell remaining oil distribution of each layer. This method has been successfully applied in predicting the remaining oil distribution before drilling the tertiary infilling wells in Xing 1-3 area of Daqing oilfield. About 100 layers are studied in this pilot area and maps of remaining oil distribution in each layer are worked out. In addition, the distribution map of remaining oil sandstone thickness in this pilot area is also drawn up and the potential area of remaining oil is pointed out. This method has been used in 28 infilling adjustment areas in Daqing oilfield and good results have been received. By checking 208 layers of 3 newly drilled inspection wells in these development blocks, coincidence rate of single layer predicting remaining oil is at the range of 81%~84%.This paper explores an effective way to study interwell remaining oil distribution in multi-layer sandstone reservoirs.
Practical E&P Waste Minimization Opportunities: Moving Up the 5R Hierarchy
Authors: Hoffmann Robert E. , Koesoemo Budi R.
Published: December 2007

As a production-sharing contractor to BP-Migas, PT Caltex Pacific Indonesia (CPI) is Indonesia's largest oil producer. CPI employs approximately 6,500 people and contracts an additional 25,000 people in its operating area throughout Riau Province on the island of Sumatra. The distances between CPI's producing fields, limited waste management infrastructure, and the evolving nature of Indonesia's waste management regulations complicate waste management efforts. CPI's activities generate both domestic waste as well as conventional E&P waste.

E&P waste management initiatives often focus exclusively on treatment and disposal. The 5R strategies of source reduction, re-use, recycle, recover and replace offer greater potential environmental and financial benefits for many common E&P wastes.

As part of CPI's integrated waste management initiative, practical 5R strategies have been identified for several waste streams: seismic shot, excess cement, empty drums and containers, construction and demolition material, oil-based drilling mud, batteries, consumable IT products, used tires, paper, cardboard, and used oil.

Development of these strategies is underway. Eventual implementation will minimize waste management costs and benefit the environment.
Storable Slurries and Their Use in Oil and Gas Well Cementing
Authors: D'Almeida Arnaldo Rodrigues , de Miranda Cristiane Richard , Campos Gilson
Published: December 2007

This paper presents the concept of the Storable Slag Slurry, a zonal isolation system which can be prepared in advance, stored and transported to the rigsite at anytime, without setting time concerns.

The compositions contain blast furnace slag to be used in water-based fluids as the hydraulic material, in the absence of set inhibitors. The slurry can be stored in liquid state from 3 days up to several months, at room temperature, depending on its composition.

There are two basic methods of preparing the Storable Slag Slurry. In both it is possible to avoid using the single batch (a so-called batch-mixer) saving money and to maintain good homogeneity of the slurry, and consequently, the uniform physical properties (density, compressive strength, etc.) in all its volume.
Numerical Simulation and Screening of Oil Reservoirs for Gravity Assisted Tertiary Gas-Injection Processes
Authors: Ren W. , Cunha L. B. , Bentsen R.
Published: December 2007

Corefloods and field investigations confirm that a large amount of incremental tertiary oil can be recovered from dipping water drive reservoirs using gravity assisted tertiary gas injection processes. These processes include the Double Displacement Process (DDP) and the Second Contact Water Displacement Process (SCWD). The DDP consists of injecting gas into waterflooded oil zones. The SCWD process consists of submitting these gas-flooded zones to a new water displacement process.

Reservoir simulations performed with an adaptive-implicit simulator were applied to investigate the macroscopic mechanisms of the two processes. The effects of several important parameters on the performance of the DDP were studied to optimize the oil production of the process and to develop a set of screening criteria for selecting candidate reservoirs for the process. Moreover, the SCWD process was simulated to investigate its feasibility. Furthermore, the two processes were simulated physically in a micromodel – transparent cell.

The results have shown that both processes are efficient methods for recovering the residual oil to water. A good representation of the laboratory results was obtained through the simulations. It was confirmed that oil film flow plays a very important role in achieving high recovery efficiencies in the DDP. In the SCWD process, trapped gas reduces the possibility of the residual oil being trapped in the center of pores in the secondary water invasion. Consequently, residual oil can be recovered quickly by a second water flood. Therefore, the SCWD process is suitable for application in situations where the source of gas is not sufficient, and where the formation has a high irreducible gas saturation.
A Case Study in the Design and Execution of Subsea Production Development Wells in the Captain Field
Authors: Rae G. , Hampson J. , Rennie M. , Morrison A. , Ramsay D.
Published: December 2007

This technical paper outlines the challenges presented and solutions chosen to allow execution of the well construction design for the Captain Area ‘B’ subsea development. It is intended to give an overview of how a blend of proven and emerging technologies can be applied to develop such fields in innovative ways in order to meet performance metrics.
Upscaling of Relative Permeability Curves for Reservoir Simulation: An Extension to Areal Simulations Based on Realistic Average Water Saturations
Authors: Crotti M. A. , Cobeñas R. H.
Published: December 2007

Special core analysis laboratories generally obtain relative permeability curves through frontal advance theory developments. The outer face of the sample, where production rates are measured, is usually selected to perform calculations. As a result, relative permeability curves are reported as function of point fluids saturations and not as function of average saturations. In spite of this procedure, numerical simulators perform their calculations using the average water saturation within every cell. Although point and average saturations are expected to be the same at infinitely small grid sizes, this is not the case with real application grids.

As previously shown by the authors1, relative permeability curves as a function of average water saturation could be used to overcome numerical dispersion and drastically reduce the number of grid cells needed for linear numerical simulation situations.

In this paper a series of experimental tests were performed to extend the methodology to 2D (areal) displacement. On this geometry, an additional issue should be taken into account that does not impact the linear cases. A geometry effect appears as a consequence of flow leaving the grid cells in a direction perpendicular from where it enters. As in the previously studied linear situation, water-cut as a function of produced oil was analyzed. The history was matched using a numerical simulator and relative permeability curves defined as a function of point saturations and average water saturation for different grid sizes. Representative relative permeability curves were previously determined through routine laboratory explicit computation based on linear unsteady state displacement. It is shown that only curves taking into account average saturation values and geometry considerations give reliable data, and a general methodology to obtain the proper relative permeability curve for every cell is examined.
A New Tool to Uphold Spatial Reservoir Heterogeneity for Upscaled Models
Authors: Idrobo E. A. , Jimenez E. A. , Ospino A. A. , Arroyo E. A.
Published: December 2007

The weakest characteristic of most scaled reservoir models is the incompetence of describing accurately the reservoir heterogeneity. This limitation has a strong impact in the adequate match of existing historical data, usually resulting in unrealistic predictions. The scaled reservoir model validation is a fundamental step toward developing a successful reservoir simulation model. The results achieved from an imprecise simulation model can be more harmful for reservoir management decisions than not having a simulation model at all.

In this paper we present a quick and efficient application designed to meet specific needs to preserve, in scaled models, the reservoir heterogeneities represented in high-resolution geostatistical realizations. The developed tool works in a systematized architecture where multi-attributes as geological, petrophysical and reservoir objects are stored in a dynamic hierarchical platform. The validation procedure, which works as a 3D visual interactive platform, includes optimization methods and transmissibility definitions using vertical windows.

We have applied the proposed tool to Dina Cretaceos and Palogrande Fields, Valle Superior del Magdalena Basin in Colombia, South America. The Dina Cretaceos Field is estimated to contain over 180 million barrels of oil in place of which 26% has been produced. The Palogrande Field is estimated to contain over 230 million barrels of oil in place with a recovery of 20.5 %. Departing from high-resolution geostatistical reservoir images, scaled models for simulation purposes were built up and validated with our tool. The flow capacity tuning procedure, a strong stratigraphic constraining, and a detailed control of sand to sand connections reduced the risk of oversimplifying the scaling up process. Therefore, a much better reservoir heterogeneity representation was achieved and a suitable history matching were possible without manipulating, deforming, or even losing the physical sense of the model.
Exact Solution of Two Layer Reservoir with Crossflow under Constant Pressure Condition
Authors: Sun HeDong , Liu Lei , Zhou Fangde , Gao Chengtai
Published: December 2007

The max effective hole-diameter mathematical model describing flow of slightly compressible fluid through two-layer reservoir with crossflow is solved rigorously. The model considers all layers open to a single well that flows at a constant wellbore pressure. The effect of formation damage is included in the model. The exact solutions are expressed in terms of ordinary Bessel functions by using the method of Laplace transform. The numerical computation of these solutions is made by Stehfest numerical inversion method. The new model is numerically stable when the skin is positive and negative. The effect of the reservoir parameters such as permeability, vertical permeability, skin, outer boundary conditions and storativity on the layer production rate and total rate were investigated. These results can be used to analyse unsteady flow test of production under the constant pressure condition.
In-Situ Stress State Eastern Cordillera (Colombia)
Authors: Torres M. E. , Gonzalez A. J. , Last N. C.
Published: December 2007

Knowledge of the regional state of in situ stress direction and magnitude is required to delineate stress provinces, to analyze intra plate earthquakes, to optimize petroleum recovery and for the development of civil projects in rock masses. This paper on rock mechanics and reservoir geomechanics studies the stress state including the pore pressure that operates in the rock mass and the mechanical behavior of the rock, to create an integrated model to study the in situ state of stress in the Eastern Cordillera, Colombia. Several measurement techniques were used, which include strain-relief overcoring, hydraulic fracturing techniques, shear fractures in the walls of the boreholes knows as breakouts, leak off test and induced drilling tensile fracture in the walls of the boreholes. Rock mechanics properties are required for the application of these methods and laboratory tests were carried out to find elastic constants. The orientation of the maximum horizontal principal stress σHmax is parallel to that of tensile failures (tensile wall fractures) and perpendicular to that of compressive failures (breakouts). The magnitude of the minimum principal horizontal stress σhmin is determined from leak off tests (LOT) and hydraulic fracturing, while the magnitude of the vertical stress σV is simply calculated based on the density data collected in several representative wells in the Cusiana field. From recent tectonics results are clear that the region in the Eastern Cordillera is characterized by an active strike-slip / thrust faulting regimen. The actual regional state of stress found means that the minimum principal stress σhmin (0.65 psi/ft to 0.77 psi/ft) oriented in a NE-SW direction, is less than the vertical stress (1.07 psi/ft), and the maximum principal stress σHmax (1.2 psi/ft to 1.7 psi/ft) in NW-SE compressional direction is significantly greater than the vertical stress, which therefore is the intermediate principal stress.
Bioremediation of Oil-Based Drill Cuttings under Tropical Conditions
Authors: Chaîneau Claude-Henri , Vidalie Jean-François , Hamzah Udi Syahnudi , Suripno Suripno , Asmaradewi Gayatri , Najib Muhammad
Published: December 2007

Onshore drilling operations may generate oil-based waste like the drillcuttings. These wastes are composed of mineral matter mixed with the drillingfluid. They are usually disposed of in a variety of methods including thermaland physico-chemical treatments. Over the last ten years, bioremediation hasbeen considered as a possible alternative to "classical" treatments since ithas been well established that hydrocarbons are prone to be biodegraded bymicroorganisms. This paper presents the results of a large-scale industrialbiotreatment of drill cuttings in Indonesia. A 12-mo field experiment was setup following a petroleum drilling operation. Resulting cuttings were treated inwindrows on a dedicated area. Periodical mixing, fertilisation andmicroorganisms seeding allowed the biodegradation of hydrocarbons.Concentration and chemical composition of hydrocarbons, nutrientsconcentrations, microbial counts were periodically determined. Gaschromatographic analyses demonstrated the metabolism of alkanes. Microbialcounts increased during the biotreatment. After treatment, the cuttings werespread on a dedicated area to allow a cover by vegetation. This publicationaims at demonstrating that oily waste can be depolluted by bioremediation.
A "Top Down" Approach for Applying Modern Portfolio Theory to Oil and Gas Property Investments
Authors: Faulder D. D. , Moseley F. L.
Published: December 2007

Petroleum companies commonly use a "bottom up" approach for constructing and evaluating their petroleum portfolios, i.e. the "fill the data cube approach." Extensive information for each well is coded into the economic software including but not limited to rock and fluid properties, production profiles, operating and capital costs and then aggregated to fields, business units and finally the total petroleum asset base. This approach requires a significant commitment in technical, managerial and computer resources "to fill the data cube;" seriously limiting portfolio analysis to companies willing to commit to those resources.

An alternative to the "bottom up" approach is the "top down" approach. Financial fund managers on Wall Street use this "top down" approach for the construction of financial portfolios. The financial analysts are first involved in making forecasts for the economy, then for industries and finally for companies. This same concept and process can be applied to the petroleum industry, greatly reducing the effort to prepare for and conduct portfolio analysis.

One of the touted benefits of the "bottom up" approach is that it preserves the uncertainty in reservoir and economic properties and this uncertainty is included when conducting portfolio analysis. However, at some point in the analysis, one must realize all that is being manipulated are aggregated distributions of properties. The central limit theorem suggests that these aggregated properties all tend toward a normal/lognormal distribution. The "top down approach" recognizes and uses this insight in constructing portfolios.

This insight is combined with advanced production decline curves methods to generate a production profile consistent with theoretical reservoir response. The advanced production decline curves include oil and gas phases for both radial and fractured flow regimes, thus assuring the modeled responses are based on sound reservoir engineering principals using probabilistic reservoir properties. The production response when combined with probabilistic economic calculation creates an integrated stochastic reservoir and economic model. These models can be combined to create a replicating portfolio of a company's asset base. Portfolio analysis is performed on this replicating portfolio, examining the current asset performance, as well as acquisition and divestiture candidates. Using this methodology significantly simplifies the process, reduces the staff and computing resources required, dramatically speeding the process. An asset class is further de-aggregated into subsets and portfolio analysis conducted on an expanded description of a company's asset portfolio for additional detail as required.
Technical Competencies for Geoscience Professionals
Authors: Fattahi B. , Murer A. S. , Myers G. A.
Published: December 2007

In today’s fast paced business environment, our attention is continually occupied by measuring ourselves against increasing expectations. The life cycle of our skill sets grows shorter as the information age revolutionizes our workplace. We wonder if we can continue to prove our worth to the organization, or we lose ground. These are important questions that are also asked by organizations to determine our value. Often the answers to such questions determine the fate of our careers. It is then highly important to have clear technical competency measures by which such expectations are defined and understood.

In the late 1990’s, having recognized the importance of defining standard-setting measures, the Society of Petroleum Engineers developed guidelines for minimum technical competence for many of the industry’s engineering disciplines. This paper proposes complementary guidelines for geoscience professionals. Similar to the previous work, the required competencies have been identified in terms of breadth and depth. An attached timeline completes the formation of a competency matrix and identifies the expectation time frame for acquiring various skills and competencies.
Global Warming and Petroleum Production
Authors: Khilyuk Leonid F. , Chilingar George V. , Al-Hamdan M. R.
Published: December 2007

The writers show that recent global warming of the Earth’s atmosphere is not due to increase in the man-induced carbon dioxide emission but rather to the long term global factors (such as increased solar activity). Rising global temperature drives very large volumes of CO2 from the ocean water to the atmosphere. The human contribution to the increase in CO2 content in the atmosphere is negligible in comparison. Thus, there will be no need to cut petroleum production and consumption in the near future.
Enhanced Oil Recovery Possibilities For Pembina Nisku C-Pool
Authors: Mungan N. , Nelson D.J. , Wing B.M. Lee
Published: December 2007

West Pembina is being regarded as the most significant oil discovery in Canada since the Rainbow Field was discovered in 1966. Six different recovery processes have been studied to arrive at the best strategy of oil recovery from one of the pinnacle, reef pools in West Pembina, the Pembina Nisku C Pool. It was concluded that bottomwater injection, with the reservoir pressure being maintained above the bubble point pressure was the best process, recovering 4528MSTB of oil (i.e., approximately 44.8% of the original oil-in-place) in 28.4years. It is anticipated that this recovery could be increased further by optimum design of waterflood operations.

Introduction

The Pembina Nisku C Pool was discovered with the drilling of Well Home Pembina 01-32-050-10W5M. The well encountered 64 ft of net oil pay in the Niskumember, of the Devonian Period. A subsequent well, Home Pembina 05-33-050-10W5M, was drilled and encountered 71 ft of net oil pay in the Niskumember. The oil zone is underlain by an aquifer 145 ft thick. Figs. 1 and 2 show the location of the Pembina Nisku C Pool and structural cross-section of the Pool, respectively.

The Nisku C Pool had an original reservoir pressure of 3,809 psig, at adatum of 5,648 ft subsea. Reservoir fluid study showed the bubble-pointpressure to be 2,492 psig at the average reservoir temperature of 183 °F. Asummary of the average reservoir and fluid data are given in Table 1.

The objectives of the present study were to determine the performance and ultimate recovery under various depletion mechanisms with a view of identifying the best recovery process for the pool. The following six studies were carriedout using a three-phase, three-dimensional reservoir simulator:primary depletion - no pressure maintenance,primary depletion with injection of produced gas - partial pressure maintenance,bottomwater injection -pressure maintained above the bubble-point pressure,bottomwater injection- pressure maintained below the bubble-point pressure to create a trapped gas saturation,crestal miscible gas injection, andcrestal miscible gas injecton followed by bottomwater injection.

Reservoir Characterization

The reservoir description for the Pembina Nisku C Pool was developed from petrophysical evaluation of logs from the two wells, 01-32-050-10W5M and 05-33-050-10W5M, and from the core analyes data of Well 05-33-050-10W5M. Coreanalyses data were also available from the discovery well located in Lsd.01-32-050-10W5M, but were not used because the data had been scrambled such that depths for the data were not known. A careful evaluation of the logs from the two wells showed no apparent layering. By analogy to similar reef reservoirs elsewhere in Alberta, it was decided that the most appropriate technique to generate the reservoir parameters was to use a random distribution of properties.