bluuebunny/crossref_metadata_2025 huggingface dataset:
Mineral Scale Control in a CO2 Flooded Oilfield
Authors: Yuan M. , Mosley J. , Hyer N.
Published: December 2007

This paper presents a case study of improving scale inhibition treatments in the Sharon Ridge Canyon Unit (SRCU), West Texas in response to the increased scaling conditions that has arisen from carbon dioxide (CO2) injection into the oil reservoir.

In anticipation of increased scale deposition, a proactive approach was taken by carrying out a comprehensive field system analysis and scale survey prior to the commencement of CO2 flooding at SRCU. This analysis/survey was intended to assess the new situation and come up with a cost effective scale treatment program. A laboratory evaluation of a number of scale inhibitors was then carried out. Based on our understanding of the problem and the lab evaluation results, a new scale inhibitor and a new chemical treatment program were developed and implemented in the field.

This paper describes the system analysis/scale survey and highlights its importance in understanding the changing situation and the new challenges in scale inhibition arising from CO2 flood. The laboratory evaluation for identifying the most suitable and cost-effective inhibitor is then briefly described. The paper then discusses the new scale inhibition treatment program and scale monitoring program. The field results from implementing the new treatment program are presented and discussed. Owing to the proactive approach and the improved inhibitor and treatment, the field production system and water re-injection system have not been troubled with scale deposition.
A Novel Self-Diverting-Acid Developed for Matrix Stimulation of Carbonate Reservoirs
Authors: Chang Frank , Qu Qi , Frenier Wayne
Published: December 2007

A Self-Diverting-Acid (SDA) using a Visco-Elastic Surfactant (VES) has been developed. The viscosity of the solution does not develop until the acid reacts with carbonate in the formation. The increases in Ca2+ ions and pH due to the HCl-carbonate reaction cause in situ gelling of the acid. The high viscosity temporarily blocks the wormholes formed in the rock matrix, allowing the acid to cover the un-acidized area. The viscosity of the gelled acid can be completely reduced by post flush of solvent or by the hydrocarbon in the formation during flow back. Unlike the polymer based gelled acid systems, the new material does not leave any residue once it has broken. Multi-Core flood testing incorporating a post acidizing Computed Tomography (CT) scans showed that the VES based Self-Diverting-Acid successfully diverted acid from high permeability section into lower permeability sections. The rock face remained clean without any trace of residue. Rheology measurements showed the consistency of the viscosity development by the gelled acid upon reacting with carbonates.
Crosslinked Emulsion To Be Used as Fracturing Fluids
Authors: Kakadjian S. , Rauseo O. , Márquez R. , Gabay R. , Tirado Y. , Blanco J.
Published: December 2007

A new crosslinked oil-in-water emulsion system has been developed for hydraulic fracturing treatments. The external phase contains polysaccharide which acts as thickening agent. Different polymers have been evaluated in order to obtain a stable emulsion. The oil phase contains a refined petroleum fraction such as gas oil or paraffin oil. A mixture of surfactants has been used to provide a stable emulsion in the preferred volume ratios of the oil and water phases.

The emulsions have been crosslinked using borate salts and pH controllers to obtain viscosity up to 400 cP @ 170 s−1/170 °F which allows proppant transport up to 15 lb/gal. Polymer loading in the emulsion system has been lowered to 18 lb/1000 gal which would give excellent regained conductivity in comparison to high polymer loading commercial systems at the same conditions.

The system has been broken using conventional oxidizer breakers, lowering the viscosity below 40 cP @ 170 s−1/140 °F after 2.5 hours of rheological evaluation. Qualitative tests in sealed bottles have shown that one of the advantages of the crosslinked emulsion is that once the system is broken, the solids are dispersed into the emulsion. This phenomenon is crucial for reducing formation damage caused by the stimulation treatment and maintaining the original proppant conductivity.

This fluid would fulfill the requirements of fracturing fluids of having good fluid loss control during fracturing and being capable of suspending and transporting proppant for better fracture packing.
Development of an Ecofriendly Scale Inhibitor for Harsh Scaling Environments
Authors: Fleming N. , Bourne H. M. , Strachan C. J. , Buckley A. S.
Published: December 2007

The recent advances in drilling and completion technology have led to the development of more complex reservoirs including high pressure, high temperature, and high salinity (HP/HT/HS) fields. A combination of high calcium and barium concentrations in the produced water, coupled to high reservoir temperatures presents a particularly harsh scaling environment which dictates the need for high concentrations of exotic scale inhibitor chemistry for effective downhole scale control. These high levels of inhibitor, typically 10–200 ppm, are particularly difficult to sustain over long production periods leading to a relatively short squeeze life and thus, high well intervention frequency and deferred oil costs. In addition, increasing environmental regulations have made the development of green chemistry a high priority.

A number of scale inhibitor chemistries have been shown to be thermally stable and effective at controlling scale deposition under harsh conditions, however, their retention characteristics are less than ideal, leading to short treatment life. In addition, some of these chemistries do not have favourable environmental properties.

To meet the challenges presented by the more severe water chemistries and producing environments a new chemistry was developed. The new chemistry contained vinyl sulphonate monomer species, which were expected to provide the polymer with a high level of thermal stability, calcium tolerance and effective barium inhibition properties. The incorporation of a phosphorus containing monomer was expected to provide good retention properties and relative ease of detection. In addition, the use of the novel phosphorus containing monomer offered the opportunity to increase the biodegradation characteristics of the developed polymer.

Laboratory studies have suggested that the new inhibitor combines significantly improved thermal stability, calcium tolerance, and barium inhibition with superior retention and environmental properties. Nine squeezes with the new inhibitor have been completed in the North Sea, which have already achieved a significant increase in squeeze life1.
Improved Horizontal Well Placement and Performance Using a Bit Inclination Measurement Tool
Authors: Muritala Lateef , Onwuazo C. , Adewumi Femi , Aibangbe Osaretin
Published: December 2007

Accurate geological placement of a lateral in the sweetest portion of the reservoir plays a major role in optimizing production rates and increasing recovery from horizontal wells, particularly for complex reservoirs with heterogeneous features. Horizontal wells have thus been routinely steered both geologically and geometrically using evaluation measurements from conventional bottom hole assemblies with sensor points some 50 feet away from the bit. This implies that correction runs and it's effective response time and footage will be dependent on directional drilling personnel proficiency and tool performance relative to formation type. It is not surprising thus, that a sizeable part of the reservoir is drilled sub-optimally, and in some cases the eventual well bore undulation has caused impossible completions, developed water sumps and have also given birth to speedy breakthroughs of gas and water. All of these have impacted production negatively, and caused unnecessary oil deferment, early work-over and associated cost overrun on budget.

The ideal option would thus be to minimize the undulation while geo-steering the lateral along the sweetest portion of the reservoir in an attempt to minimize attendant production problems and hence allow efficient and early completions.

A tool has been developed which measures well bore inclination 1 foot away from the drilling bit. Shell West Nigeria introduced the At bit Inclination measurement tool to horizontal well drilling on the Opukushi 26 well in March 99. This was to complement multiple depth propagation resistivity and quadrant density-neutron measurements while drilling utilized in horizontal evaluation, to enable full wellbore geologic steering with optimized response time for correcting changes in the desired direction. The result is a significant improvement in the ratio between actual versus predicted production figures as compared to previously drilled wells executed without the combination measurement. It also aided geosteering decision, improved directional performance and enhanced delivery of better quality well.

This paper therefore reviews the SPDC horizontal wells experience in identifying the impact of deviation profiles and lateral placement with respect to production performance, and how the use of the near bit inclination tool along with the formation evaluation measurements has resulted in noticeable improvement.
Integrated Fractured Reservoir Characterization: A Case Study in a North Africa Field
Authors: Gauthier B. D. M. , Zellou A. M. , Toublanc A. , Garcia M. , Daniel J-M.
Published: December 2007

In fractured reservoirs, data directly related to fractures are scarce and uni-dimensional (i.e. cores and image logs). Other types of data are better distributed and have proved to be related to fracturing but only indirectly (e.g. lithology or large scale structure).

In such reservoirs, however, one has to understand fracture distribution and behavior at the field scale. A methodology has been developed within TotalFinaElf to define the relationships of all sources of data to fracturing and to integrate them and compared to another independent published method. To that end, a systematic work flow which goes from 1D to 2D and from static to dynamic data has been defined and various technologies tested.

A field case in North Africa is taken to illustrate this methodology. In this field, fracture data from image logs have been related to: 1) production data; 2) 3D seismic attributes (coherency, amplitude, structural curvature) and fault interpretation and strain; 3) log data such as porosity, thickness and lithology index. The former type of data is used to understand the contribution of each fracture set to flow. The latter two types of data are used to better map fracture distribution at the field scale. Ultimately, this mapping is calibrated with the production data of the other wells where fracturing data are not available and is then used to validate the specific role of fracturing in this field.

A better reservoir simulation and infill well planning can be subsequently achieved.
EOR Screening for Ekofisk
Authors: Jensen T. B. , Harpole K. J. , Østhus A.
Published: December 2007

An investigation of alternative EOR processes having potential application in the giant Ekofisk chalk field is presented. Technical feasibility, process readiness, oil recovery potential, and related uncertainties and risks of five selected EOR processes, namely hydrocarbon (HC) WAG, nitrogen (N2) WAG, carbon dioxide (CO2) WAG, air injection and microbial EOR (MEOR), are assessed for possible application at Ekofisk. The objective of the screening study was to evaluate and rank the EOR alternatives and to select the most attractive process(es) on which to pursue further work toward possible field pilot testing. The focus of the paper is on the technical assessment of the relative oil recovery potential of each process, and on the importance of identifying critical operational and logistical considerations for implementation of an EOR processes in the offshore North Sea operating environment.

Estimates of potential EOR incremental oil recovery for the Ekofisk field can be quite significant. However, key project development and implementation issues and additional cost elements must be weighed equally with oil recovery forecasts in any EOR process ranking. Some of these issues (e.g. injection gas supply, facilities requirements, and the impact of EOR on chalk compaction, subsidence and wellbore integrity) may be significant enough to eliminate a process from further consideration.

In addition, there are significant differences in the quantity and quality of key laboratory and field data supporting the viability of the various EOR processes being considered. Only a limited amount of field-specific data are available to calibrate the performance predictions for some of the processes. There is also a wide variation in the technical readiness of each process to begin field pilot design studies. Table 1 summarizes the state of technical readiness for field implementation of each process and identifies some of the major risk elements and remaining work required to progress these EOR processes at Ekofisk.

Table 1 Technical Readiness of EOR implementation at Ekofisk.
Design Methodology for Selection of Horizontal Open-Hole Sand Control Completions Supported by Field Case Histories
Authors: Bennett C. , Gilchrist J. M. , Pitoni E. , Burton R. C. , Hodge R. M. , Troncoso J. , Ali S. A. , Dickerson R. , Price-Smith C. , Parlar M.
Published: December 2007

Reservoirs requiring sand control pose a major challenge for selection of a suitable completion method. Horizontal open-hole completions have been successfully utilised in such reservoirs to eliminate sand production, while maximising productivity/injectivity and well deliverability throughout the expected life of the completion and minimising risk and complexity.

Although horizontal open hole sand control completions have been applied widely in the last decade, ranging from preperforated/slotted liners to gravel packs, and many case histories have been discussed in the literature, a systematic methodology for selecting these completion methods remains to be documented. It is the objective of this paper to propose such a design methodology by unifying the broad experience and understanding from a global and technically integrated perspective.

The paper first discusses a generalised and unified methodology for determining when to install sand control, what to install for sand control and how to install sand control in horizontal open-hole completions. Specific factors recognised as affecting "when" are in-situ stresses and pore pressure decline (sand prediction), expected well life, production rate, hydrocarbon and well type, gross product value, sand tolerance capacity, environmental limitations and intervention capabilities, whilst the integration of all these factors have an impact on the overall risk analysis. In addition to many of the previous factors, critical drivers affecting "what" are identified as wellbore architecture, reservoir lithology and petrophysical properties, and sandface equipment reliability. Additional parameters impacting "how" are reservoir drilling fluid, displacement and cleanup methodology, screen type, operational implementation/assurance (risk management, operational timing and location logistics), torque and drag analysis, and gravel placement simulations.

Secondly, examples of this methodology are presented in detailed case histories pertaining to different types of horizontal openhole sandface completions including slotted liners, standalone screens (including expandable) and gravel packs as well as various integrated cleanup methods, along with a summary of lessons learnt by each company.
Best Practices and Methods in Hydrocarbon Resource Estimation, Production and Emissions Forecasting, Uncertainty Evaluation and Decision Making
Authors: Jonkman R. M. , Bos C. F. M. , Breunese J. N. , Morgan D. T. K. , Spencer J. A. , Søndenå E.
Published: December 2007

On behalf of a group of sponsors consisting of the Norwegian Petroleum Directorate (NPD) and most E&P companies active in Norway, a workgroup was set up to author a report on the Best Practices and Methods in Hydrocarbon Resource Estimation, Production and Emissions Forecasting, Uncertainty Evaluation and Decision Making. The workgroup is part of Norway's forum for Forecasting and UNcertainty (FUN).

Following a detailed data acquisition and interviewing phase to make an inventory of the current practice of all sponsors involved, the workgroup postulated a relationship between a company's practices and its economic performance. A key distinguishing factor between companies is the degree to which probabilistic methods are adopted in integrated multidisciplinary processes, aimed at supporting the decision making process throughout the asset life cycle and portfolio of assets.

Companies have been ranked in terms of this degree of integration and best practices are recommended. In many companies a gap seems to exist between available and applied technology. Data and (aggregated) information exchange between Governments and companies is also discussed. A best practice based on their respective decision making processes is recommended.
Successful Field Application of Chemical Flow Improvers in Pipeline Transportation of Highly Paraffinic Crude Oil in Kazakhstan
Authors: Zettlitzer Michael
Published: December 2007

In autumn 1998, an international consortium started the continuous production of highly paraffinic crude oil in a newly developed field in Central Kazakhstan. Due to the crude´s high pour point and the related high viscosity at low temperatures, intensive laboratory investigations had to be carried out before production start-up to find an effective method for flow improvement in winter conditions. Duly considering technical and economic aspects, it was decided to use chemical flow improvers for transportation through the 60 km pipeline to the neighbouring oil field and from there to the refinery 700 km away.

Out of 18 flow improvers tested in the laboratory, only a handful proved to be suitable for this specific crude. The pour point was lowered from +17 to −5°C and viscosity at 10°C was reduced from several thousand mPa*s to about 14mPa*s. In spite of the significant flow improvement, yield stress remained high (≍60Pa), even for properly inhibited oil whenever the crude was cooled down statically, whereas, after dynamic cooling, yield stress was nearly negligible. Thus, special precautions had to be developed for potential phases of export stops.

Field application of the selected flow improver fully confirmed the encouraging lab results: the measured pressure drop across the pipeline – under laminar as well as turbulent flow conditions -very closely coincided with the values derived from calculations based on lab viscosity (and yield stress) measurements. Furthermore, pour point could be permanently kept far below zero. Regular pipeline pigging provided, uninterrupted production could be achieved without major technical problems even at surface temperatures of well below −20°C.

A special task not yet fully mastered is the adaption of flow improver implementation to the standards and test procedures of the Kazakh authorities and pipeline organizations. This is especially true of pour point and viscosity measurements.
Trends in the Development of Environmentally Acceptable Additives for Zonal Isolation Applications
Authors: Reddy B. R. , Vijn Pieter , Chatterji Jiten , Dao Bach , Wilson J. Michael , Caveny William J.
Published: December 2007

For the past 20 years, there has been increasing global emphasis on development of environmentally acceptable materials to replace chemicals that are considered to be either toxic to flora and fauna or otherwise to pose a long-term hazard to the natural environment. However, globally accepted definitions for unacceptable toxicity or environmental hazard do not exist. Likewise globally accepted protocols for testing methods to evaluate these hazards do not exist.

The Oslo-Paris Commission (OSPARCOM) was inaugurated in 1992 for the protection of the marine environment of the Northeast Atlantic. In 1998, OSPAR Conventions were ratified by Belgium, Denmark, the Commission of European Communities, Finland, France, Germany, Iceland, Ireland, Norway, Portugal, Spain, Sweden, the United Kingdom of Great Britain and Northern Ireland, Luxembourg, and Switzerland.

The goals of the OSPARCOM are to prevent and eliminate pollution from land-based sources, dumping or incineration, and offshore sources, and to assess the quality of the marine environment.

To this end, the OPSARCOM has initiated a series of stringent testing protocols that are used to evaluate chemicals that may be detrimental to the marine environment. Additionally, the Harmonised Offshore Chemical Notification Format (HOCNF), which must be completed on all chemicals to be registered for offshore use, has unified the reporting format.

Elsewhere around the globe, the regulations on use of chemicals in the offshore environment are not as highly structured, and, generally, are less strict. For example, chemical discharges offshore in the Gulf of Mexico are based on oil- and grease-extraction tests and static sheen. Aquatic toxicity testing is usually required before discharge is allowed in the Gulf waters. However, these restrictions are rapidly changing and may become much more structured in the near future.

This paper summarizes Halliburton's research efforts over the past several years to comply with, and preferably exceed, the diverse global regulations and guidelines in the areas of environmentally acceptable cement dispersants, retarders, viscosifiers, foamers, defoamers, fluid-loss additives, and spacer-blend additives.
Applications of Singular Value Decomposition to Determine Streamline Distribution for Sectionally Homogeneous Reservoirs
Authors: Guevara-Jordan J. M. , Rodriguez-Hernandez F.
Published: December 2007

This paper presents an original extension of a new numerical method, recently developed by Marathe et al.1, to determine the streamline distribution in a sectionally homogeneous reservoir with an arbitrary shape and well configurations. It combines the singular valued decomposition algorithm2 and the classical method of images3 into an efficient numerical scheme which computes semianalytical solutions for pressure and Darcy's velocity. These solutions are used to obtain the streamline configuration in two dimensional reservoirs for single phase incompressible flow. Very general test problems and numerical examples show that the new method has, in some cases, substantial reduction in CPU times in comparison with the finite5 and boundary4 element techniques.
Single-well Sonic Imaging: High-Definition Reservoir Cross-sections from Horizontal Wells
Authors: Coates R. , Kane M. , Chang C. , Esmersoy C. , Fukuhara M. , Yamamoto H.
Published: December 2007

The limited resolution of conventional seismic surveys often results in challenges to successful reservoir development. Reservoir structure and thickness may not be determined from the seismic to the level of detail necessary, affecting the placement of the horizontal well. We describe a new sonic imaging technique that resolves these features. In addition the position of the well in relation to the reservoir perimeter can be determined with great accuracy

Single-well sonic imaging places the acoustic transmitter and receivers in the same well, analogous to recording a micro-scale seismic reflection survey downhole. Using modified sonic logging technology, sound is broadcast into the formation and reflections are converted into a two- or three-dimensional spatial image of the zone around the borehole. Acoustic reflectors such as the top of the reservoir, calcite stringers, or fractures are mapped at distances of 10-15 meters from the well with resolution on the order of one-half meter. We show several examples of surveys conducted in horizontal wells to illustrate applications of the technique.
Using Real-Time Fibre Optic Distributed Temperature Data for Optimising Reservoir Performance
Authors: Laurence O. S. , Brown G. A.
Published: December 2007

A new approach to reservoir monitoring using permanent sensors is outlined which employs the use of optical fibre preinstalled on the completion across the intervals of interest. Using optical fibre it is possible to obtain an accurate measurement of well temperature every metre along the producing interval at regular, sub-hourly, time intervals over the producing life of the well. Although temperature is not, in itself, a direct measurement of flow, well performance, water cut or gas breakthrough all do produce quantifiable thermal responses. These responses, combined with continuous monitoring allow identification of producing zones and rapid evaluation of production variations without the need for well intervention.

The paper will outline how optical fibre can be installed into a range of completions and well types. Real well examples are used to illustrate how distributed temperature monitoring can be used to for reservoir monitoring. These illustartions include monitoring gas lift mandrels, cross flow on shut-in, water breakthrough and monitoring flood rates in watered out intervals using the temperature of injected water as a thermal tracer.

The results demonstrate that pre-installed optical fibre is an effective real time method for monitoring wells and thus facilitates the optimisation of reservoir performance.
Horizontal Drill-in Fluid Reclamation for Re-use or Waste Minimization Field Trial
Authors: Bernardi Tony , Ives H. Russell , Lanier Gary , Cole Terry
Published: December 2007

Horizontal Drill-in Fluid Reclamation for Re-use or Waste Minimization Field Trial for Shell Auger Project

Due to the high cost and logistical concerns of drilling open holes in the geopressured arena, Shell began looking at ways facilitate this option. Most horizontal drill-in fluids, regardless of density, are discharged if they meet environmental regulations. In the geopressure fluid densities, these fluids have a lot of value residing in the base brine which can be comparable to, or even more valuable than the base for synthetic fluids. This practice is not only costly, but in the heavier fluids, they have environmental implications as well. Working closely with Reclamation Solutions and MI Drilling Fluids we came up with a process that would both reduce environmental impact give us back a fluid that could be reused. The new process has been developed that incorporates both conventional and new technologies to reclaim these types of fluids back to original specifications which have value to both Shell and MI. This process is known as CENTRIFLUX. Depending upon the solids content and/or characteristics of the waste fluid, a mechanical pretreatment phase involves both decanting and high speed disc centrifuges that jointly remove solids above 1-5 micron. The ultrafiltration phase removes the remaining suspended solids above 0.1 micron by circulating the fluid through a SCEPTER stainless steel membrane module. This ultrafiltration removes both polymer and starch residue which have been a problem in the past. The solids removed by the CENTRIFLUX process are transferred for disposal and the quality of the reclaimed base fluid meets or exceeds original specifications and can be used again.
Effects of Water Coning on the Performance of Vertical and Horizontal Wells-A Reservoir Simulation Study of Hassi R'mel Field, Algeria
Authors: Recham R. , Osisanya S. O. , Touami M.
Published: December 2007

Generalized empirical correlations have been developed to predict, (1) critical oil rate, and (2) water breakthrough time in vertical and horizontal wells. Water coning is a serious problem in many producer wells, which increases the cost of producing operations, and reduces the efficiency of the depletion mechanism and the overall recovery.

A numerical simulation was used to analyze the most relevant fluid and reservoir parameters that affect water coning using a 3-D radial vertical well model and a 3-D Cartesian horizontal well model. The method of determining the average oil column height below perforations at breakthrough (hwb), was developed from a stepwise procedure. First, a number of simulation runs was made to investigate the coning performance at different reservoir and fluid properties for both vertical and horizontal wells. Then, for each simulation run, water oil ratio (WOR) was plotted against of average oil column height below perforations (hbp), on a semi-log scale, from which (hwb) was determined. Once the (hwb) data was obtained for all the simulation runs, regression analysis was then used to define the relationship between (hwb) and various reservoir and fluid properties.

An extensive parametric sensitivity analysis of water coning was made to provide data for developing a predictive correlation of calculating breakthrough time and breakthrough height as a function of various reservoir and fluid properties. The simulation outputs are used to develop empirical water coning correlations to predict critical oil rate, and water breakthrough time for vertical and horizontal wells. The parameters were grouped together based on the basic flow equations and the grouping was confirmed by regression analysis. Several field examples from CTH1 area of Hassi R’mel field in Algeria will be discussed.
Impact of Skin Damage on Horizontal Well Flow Distribution
Authors: McMullan John H. , Larson Todd A.
Published: December 2007

One of the common applications of horizontal wells is the development of thin oil columns underlain by bottom water and/or overlain by a gas cap. Vertical wells are not suited in this situation due to the rapid coning of water or gas at reasonable production rates. Horizontal wells correctly positioned in the oil column, however, can produce at high flow rates with very little drawdown. The small drawdown significantly delays the breakthrough of water or gas at flow rates much higher than the flow rates possible from a vertical well.

The flow distribution in a horizontal well designed to develop a thin oil column can be significantly impacted by friction losses in the wellbore. The impact of friction results in a higher drawdown at the heel as compared to the toe of the horizontal well. While this impact is insignificant in lower permeability systems, it can lead to premature water or gas breakthrough at the heel of the well in high permeability systems produced with low reservoir drawdown.

Skin damage is normally undesirable due to its detrimental impact on well productivity. In high permeability systems developed with horizontal wells, however, well productivity is normally not a problem. Skin damage actually diminishes the detrimental impact of friction in horizontal wells by improving the flow distribution. This study investigates the intentional inclusion of mechanical skin damage in a high permeability, North Sea horizontal development. Reservoir simulation was used to justify and design a limited entry completion that was shown to improve flow distribution and oil recovery, at a significantly lower completion cost. The desired uniform flow rate distribution was confirmed by a PLT run in the first well, and through reservoir simulation and history matching.
Performance of Horizontal Wells Completed with Slotted Liners and Perforations
Authors: Tang Yula , Ozkan Erdal , Kelkar Mohan , Sarica Cem , Yildiz Turhan
Published: December 2007

This paper presents a comprehensive study on the productivity and flow efficiency of horizontal wells completed with slotted-liners or perforations. The study is based on a semi-analytical model that couples the flow equations in the reservoir and wellbore. The reservoir model takes into account the 3D convergence of flow around perforations and slots. The wellbore flow model considers the pressure losses inside the horizontal well and the effect of axial influx at the perforations and slots. A new, experimental apparent friction factor correlation is used for horizontal wellbore flow computations with perforations and slots. The model is capable of incorporating the effects of selective completion and non-uniform skin distribution.

The results of this study indicate that software based on detailed semi-analytical models can provide a powerful tool to design, predict, and optimize horizontal well completions. It is also shown that horizontal wells deserve genuine guidelines to optimize their completions. For example, horizontal wells are shown to require significantly lower slot and perforation densities to accomplish optimum PI compare to vertical wells. Similarly, in horizontal wells, the effect of slot or perforation phasing becomes more important as the anisotropy of the formation increases.
Successful Implementation of Shared Learnings and New Technology to Develop a Thin Oil Column With Horizontal Wells in the Mahogany Gas Field, Offshore Trinidad.
Authors: Mackow H. Michael , Ali-Nandalal Jo-Ann , Hassanali Hamid , Staines Michael
Published: December 2007

Horizontal oil well drilling, completion and production techniques have continued to advance through the use of shared learnings and new technology as applied in the most recent BP Amoco field development in Trinidad. The Mahogany field is being developed to supply gas to the Atlantic LNG plant in Trinidad. The 21 Sand reservoir in this field has a 60 foot oil column overlain by a 400 bcf gas cap and underlain by water. As with other fields in Trinidad that have thin oil columns horizontal well technology was selected as the preferred method to develop the Mahogany 21 Sand oil leg. During the front end loading design phase of the Mahogany field development an extensive review of evolving technology and recent world wide experience was undertaken. As well, the front end loading involved a review of the BP Amoco Immortelle (Trinidad) horizontal well program which was in its third phase as the Mahogany front end loading was being completed.

The critical success factors that emerged from the front end loading review were well placement within the oil column, avoid drilling poor quality reservoir, avoid undulating wellbores, the need to understand well performance with very low drawdowns, the need to land the well in the right place and at the right angle. All of these issues were addressed in the Mahogany horizontal well designs and have been successfully implemented.

The front end loading work and continuing optimization of the well designs has resulted in a highly successful 21 sand oil development which is expected to deliver economic results superior to the authorized metrics.
Use of a Chemical Equilibrium Computer Code To Analyze Scale Formation and Corrosion in Geothermal Brines
Authors: Shannon D.W. , Morrey J.R. , Smith R.P.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Introduction

The probable size of U.S. geothermal energy reserves indicate we are in the beginning phase of the birth of a new industry. It is easy to visualize 50 to 100 geothermal power plants scattered all over the western United States involving all the electric utilities serving these regions. The development of geothermal energy on such a scale in the next 20 years will require considerable investment. Geothermal power plants will cost $25 to $100 million each. plants will cost $25 to $100 million each. Before such investment in geothermal energy can be justified, a number of questions must be answered including, "Can we assure reliable plant operation over the 20- or 30-year amortization period?" An important part of answering this question hinges on the effects of mineral scaling and corrosion on the performance of geothermal wells and power performance of geothermal wells and power plant components which come into contact with plant components which come into contact with geothermal fluids, and the subsequent plant degradation in electric output and maintenance expense.

Under sponsorship of the Electric Power Research Institute (EPRI), Battelle-Northwest Laboratories (BNW) has undertaken research programs which are aimed at answering some programs which are aimed at answering some of the very complex questions relating to scaling corrosion and power plant performance.

The major part of the material for this paper is drawn from our EPRI work which is paper is drawn from our EPRI work which is about 50% complete. Thus, this paper will concentrate on the problems we see, approaches we are taking to solve them, and some of our initial results.

A prerequisite for the analysis of scaling and corrosion rates in geothermal systems is a comprehensive data base on geothermal brines, and an understanding of which brine components are important. Knowledge of the kinetics of scaling and corrosion processes must be accompanied by an processes must be accompanied by an understanding of the equilibrium conditions of complex, multicomponent brines and associated minerals. Numerous references exist in the geochemical literature for the calculation of equilibrium conditions and the alterations of equilibrium states due to temperature changes. Unfortunately, these studies are inadequate when one considers the extremely rapid changes of state that occur as a geothermal brine passes through a power plant. Supersaturation effects and slow nucleation and growth of crystals an change scaling rates by orders of magnitude during the short residence time of brines in geothermal plant components.
Chemical Movement in Micellar Flooding: Determination of Sulfonates and Polymers by Liquid Chromatography
Authors: Suffridge Fred E. , Taggart Davis L.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Now liquid chromatographic procedures, column solvent systems and equipment used to determine petroleum and/or synthetic sulfonates and water-soluble polymers in micellar fluids are described. These new procedures are used to determine sulfonate and/or polymer in formulations and in core test effluent polymer in formulations and in core test effluent fluids. Procedures developed have been or will be automated. With automation about two man hours are required to perform 100 sulfonate analyses in a 24-hour period. Analyses have shown that monosulfonated fractions of sulfonates are usually selectively lost (adsorbed) in laboratory core tests.

Introduction

Micellar flooding is one of several improved oil recovery techniques currently being studied by the petroleum industry. By nature it is a complicated multiple fluid bank, chemical process. A typical tertiary micellar flooding process includes injecting a micellar fluid and following it with a mobility-control drive fluid. Most micellar fluids currently used by the industry contain brine, cosurfactants, and petroleum or synthetic sulfonates. Frequently, chemical tracers, water-soluble polymer, and/or solubilized hydrocarbons may also be present. Mobility-control drive fluids typically contain water-soluble polymers (polyacryla-mides or Xanthan gum biopolymers) dissolved in fresh water. Chemical tracers, biocides, and oxygen scavengers may also be present.

As these fluid banks (micellar and mobility control) propagate through cores in lab testing, or through reservoirs in field testing, they are retained and mix with one another and with in-place brine and oil. The propagation and mixing behavior of these fluid banks is studied by collecting samples of injected/produced fluids and analyzing these samples for chemical content. Analyses of produced fluids are compared to injected fluids to study adsorption, interaction, and propagation properties of the chemicals in a propagation properties of the chemicals in a given micellar flooding process.

Chemical costs make up a significant portion of the total cost of a micellar portion of the total cost of a micellar flooding process. Chemicals showing low adsorption in a reservoir environment (actual or simulated) are the most desirable chemicals for micellar flooding. Analyses used to determine the specific components in micellar fluids must be accurate, specific for adsorbed components, and relatively free from interference from other materials present in the samples.
Flow Equation for Foam Flowing Through Porous Media and Its Application as a Secondary Recovery Fluid
Authors: Alizad Tanweer , Okandan Ender
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

A theoretical and experimental study of the flow of aqueous foam, of homogeneous and fine bubble size, through unconsolidated porous media is described. An equation was developed to describe the flow of non-Newtonian fluids through porous media and is confirmed experimentally using foam. In the light of the equation, the rheological properties of foam are studied experimentally. Externally generated foam, of known quality, was injected continuously into a porous medium. Both flow rate and pressure drop were measured. Foam is shown to behave as a single-body pseudoplastic fluid in unconsolidated porous media, With the help of experimental data, foam's apparent viscosity was calculated and is found to be increasing with the increase of foam quality.

Experiments also were conducted to displace oil from unconsolidated linear sand packs using foam of different qualities. Foam's ability to displace oil from porous media was observed and was found to be better as compared with water. High-quality foam displaces oil at a relatively lower rate than low-quality foam. Compared with low-quality foam, less high-quality foam is required to displace the same amount of oil.

Introduction

In recent years, the aqueous foams have gained popularity in various petroleum operations because of their specific properties. Apart from enjoying application in oil wells as aerated drilling fluid and in workover and remedial well operations, foams, because of their flow-impeding nature, have potential use as a remedial fluid to combat coning and as corrective fluid to improve sweep of fluid injection processes in heterogeneous reservoirs. They also have been suggested as a way of preventing gas leakage through the cap rock of storage reservoirs. Foams have been used as a means of treating wells to reduce water or gas inflow during oil production. They are being used also as fracturing fluid for the stimulation of oil-bearing formation.

Consideration of factors that operate to limit the recovery of oil by conventional mechanisms led to the development of secondary or tertiary oil recovery methods. The foamdrive method is one of them. Prompted by the known properties of foam, like its high apparent viscosity, attempts have been made in this study and by others to use foam as a secondary recovery fluid.
The Use of High Resolution NMR Spectroscopy for Characterizing Petroleum Sulfonates
Authors: Hsieh W.C. , Shah D.O.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Natural petroleum sulfonates and synthetic sulfonates were characterized or "finger-printed" using high resolution NMR spectroscopy. Natural petroleum sulfonates are produced by sulfonation of a selected petroleum fraction. Synthetic sulfonates petroleum fraction. Synthetic sulfonates are produced by sulfonation of alkylated benzenes or naphthalenes of the proper equivalent weights. Petroleum sulfonates usually contain unreacted oil, water, and salts in addition to the active petroleum sulfonate. Therefore, the quality and composition of similar petroleum sulfonates may be different if one considers the supply of a petroleum sulfonate at different time intervals petroleum sulfonate at different time intervals or pooling of similar petroleum sulfonates obtained from different suppliers. Characterization of petroleum sulfonates generally includes (1) the average equivalent weight, (2) percentage of unreacted oil, water, and salts, (3) percentage of active sulfonate, (4) pH and solubility of oil or water. A rapid and informative analysis or "fingerprinting" of petroleum sulfonates can be done using high resolution NMR spectroscopy. The relative amount of water, the relative amounts of aromatic and aliphatic protons, the fine structure of the polar group and hydrocarbon chains can be determined by this method. About 20 different types of petroleum sulfonates were analyzed using high resolution NMR spectroscopy.

Introduction

Petroleum sulfonates are widely used as surface active agents in the injection fluid (detergent solution) to lower the interfacial tension between oil and formation water in the tertiary oil recovery process. It was found that a low interfacial tension (LIFT) in the order of 10-2 dynes/cm or less is necessary for the injection fluid to displace the trapped oil after water flooding. Further, it was found that the LIFT can be achieved only if the contacting oil phase is compatible with a given injection fluid. This obviously leads to the suggestion that the molecular structure of petroleum sulfonates is vital to the achievement of LIFT for a given oil.

Natural petroleum sulfonates are generally mixtures of alkyl-aryl sulfonates which also contain unreacted oil, water and electrolytes. It is difficult to identify the individual components in the natural petroleum sulfonates unless each of them is separated. However, a rapid and informative analysis or "finger-printing" of petroleum sulfonates is highly desirable.
Geochemical Equilibrium Codes: A Means of Modelling Precipitation Phenomena in the Salton Sea Geothermal Field
Authors: Miller D.G. , Piwinskii A.J. , Yamauchi R.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

We have used the Helgeson-Herrick geochemical code to predict which minerals will precipitate from Salton Sea Geothermal Field precipitate from Salton Sea Geothermal Field brines. The code's predictions of sulfide-amorphous silica precipitation from the Magmamax No. 1 brine are in good agreement with field tests of scaling, although the observed silicate scale matrix is in amorphous form, rather than the numerous crystalline forms predicted by the code. The code's predictions predicted by the code. The code's predictions of scale precipitation from wells with different brine compositions are also in good agreement with field tests. The code appears to be a useful screening tool, despite reservations about the use of purely thermodynamic predictions in systems with important kinetic predictions in systems with important kinetic constraints.

Introduction

A major goal of the LLL geothermal project is to develop a total flow concept for converting to electric power the thermal energy of high-temperature, high-salinity brines-found in the Salton Sea Geothermal Field (SSGF). LLL's approach to the total flow process calls for passing the entire wellhead product through stationary, specially designed nozzles to form high-velocity jets. These jets then turn an axial-flow impulse turbine that generates electricity. Unfortunately, as the high salinity brines cool and flash (i.e., are made to do work), large quantities of sulfides and silicates precipitate, producing a ubiquitous scale on precipitate, producing a ubiquitous scale on pipes, nozzles, and turbine blades. pipes, nozzles, and turbine blades. The brines are complicated by both the large number of species present and by the complexity of the chemical reactions occurring. Table 1 presents representative analyses of brines from the Sinclair No. 4 and Magmamax No. 1 wells. The brine solutions are very concentrated (4–5 molal, ionic strength 5–6), containing mostly NaCl. There are also significant amounts of Ca+2 and K+, as well as H4,SiO Fe+2, Cu+2, Pb+2, Mn+2, M9712, S-2, CO2, and H2S. Clearly, the precipitation of silica and metal sulfide scale is of special interest because of the scale's harmful effect on plant materials and its unbalancing effect on the turbine.

Precipitation equilibria can be studied by thermodynamic equilibrium calculations (both those done by hand and by computer code) and by experiment.