bluuebunny/crossref_metadata_2025 huggingface dataset:
Why Does Scale Form in ASP Flood? How to Prevent from It?--A Case Study of the Technology and Application of Scaling Mechanism and Inhibition in ASP Flood Pilot Area of N-1DX Block in Daqing
Authors: Wang Yupu , Liu Junde , Liu Bing , Liu Yingping , Wang Hongxing , Chen Gang
Published: December 2007

ASP(alkali surfactant polymer) flood was initiated on March 15, 1997 in N-1DX block in Daqing oilfield; its main slug was completed on June 12, 1999. By September 23, 1998 pump malfunction occurred with a scale thickness of 1cm over in well bore. By the end of 1999, a serious scale was found in surface gathering and delivery system, with a 0.3cm of scale thickness found in single well pipes, gathering pipes as well as in heating furnace, this unfavorably affected current production.

In terms of this problem, we performed study of scale removal and inhibition. Analytical study over scale content, scale forming mechanism and regularity.Chemical agent study of scale inhibition.Study of physical scale prevention method, and we performed comparison test on different well respectively, using coated nickel, three layered compound coated pipes and ordinary pipes.We used hydro-electrical scale preventing unit, magnetic scale preventing unit in oil gathering pipes.

Through tests of the above methods in different wells, we obtained a satisfactory effect, the chemical agent method prolonged the pump check period from 30 days to 109 days; the coated pipe scaled slightly or didn't scale, and the scale was physically loosen. With these methods combined, scale prevention performed a good effect in well bores, single well pipes, oil gathering pipes and heaters. It ensured a conventional production in tested area. This paper presents the study of scale forming methods, the process of scale inhibition and the ideal effect we obtained.
Soap Sludges: Aggravating Factors and Mitigation Measures
Authors: Gallup Darrell L. , Star Jacquelyn
Published: December 2007

Greenish-brown soap sludge is formed in significant quantities during production of oil from the Serang field, offshore East Kalimantan, Indonesia. The sludge forms upon cooling of oil in subsea pipelines and onshore terminal storage tanks. This interfacial sludge is comprised of entrained free oil, water and solids, and is stabilized by an acyclic "metal carboxylate" soap. In the absence of fluid treatment, removal and disposal of the sludge is tedious, expensive, and represents significant un-recovered oil. The soap also adversely affects discharge water quality.

The sludge has been characterized to understand its formation mechanism, so that remedial actions can be taken to mitigate its deposition.1 A variety of analytical methods indicated that the "soap" emulsion consists of about 30% water, 50% oil, and 20% of C28 – C30 carboxylate salts in sodium form. The "soap" is stabilized by fatty acid-Na-HCO3 complexation, and results from the reaction of long chain fatty acids in oil with sodium bicarbonate-rich waters containing significant volatile fatty acids.

Laboratory and field tests have demonstrated that the sludge can be dissolved by low dosages of commercially available sludge dissolving agents containing combinations of acids. An acid demulsifier, consisting of acetic acid in an aromatic solvent mixture, and a non-acid demulsifier, consisting of ethoxylates and alcohol, have been injected into Serang produced fluid arriving at the onshore Santan terminal since August 2002. The demulsifiers have significantly reduced sludge deposition in oil storage tanks and water-handling facilities. In addition to "dissolving" sludge, incremental oil is recovered, which offsets chemical treatment and sludge disposal costs. Existing sludge is treated with chemicals and hot centrifuging to minimize waste and optimize oil recovery.
The Role of Electrolyte Simulation in Understanding the Failure of Shearwater Process Pipework
Authors: Webb Philip J.
Published: December 2007

Corrosion of metallic well and process materials can be caused by water that is co-produced with oil and gas. The corrosion processes involve electrochemical reactions that are dependent on the composition of the produced water. Variation of the produced water composition during oil and gas production can be investigated using electrolyte simulation tools that model the chemical reactions (chemical equilibria) that control the composition of the produced water. This paper describes how electrolyte simulation was used to investigate the failure of 2205 duplex stainless steel (UNS S31803) process pipework on the Shearwater installation, operated by Shell Exploration and Production, in the Central North Sea.

The failure of the 2205 duplex stainless steel (22Cr) involved stress corrosion cracking (SCC) initiated from both the outside and inside of the pipework. Cracks initiated from the outside were attributable to a known chloride SCC failure mode of 22Cr. The mechanism involved a high degree of evaporation of seawater on the pipework surface. However, the mechanism that initiated cracks from the inside was unusual because oxygen was not present. Electrolyte simulation tools were used to establish the chemical environment associated with the cracks initiated from the inside. It was demonstrated that evaporation of produced water, resulting from a 90 bar to 15 bar pressure reduction at ~136°C, had created brines with very high calcium and magnesium chloride concentrations. The resulting "exotic" brines had not been anticipated and were outside the range of environments for which the process materials had been qualified. Subsequent laboratory materials testing replicated the field failure in the presence of these brines.

This study highlights the need for materials selection to include rigorous evaluation of steady state and transient process environments using both electrolyte and hydrocarbon simulation tools. Special attention should be given to projects that apply materials and processing concepts in novel combinations. The failure illustrated that surface wetting of pipework can initiate corrosion failure even at very low water volume fraction (< 0.5 vol%).
Heavy Oil Development: Summary of Sand Control and Well Completion Strategies Used with Multilateral Applications
Authors: Cavender Travis W.
Published: December 2007

Multilateral drilling technology has been used in many heavy-oil developmental projects to achieve maximum reservoir exposure from a single surface location. The wellbore geometry and completion strategies for multilateral wells are planned and customized to fit the known reservoir characteristics and sand distribution qualities. Typically, heavy oil reserves are found in unconsolidated sandstone reservoirs that require some form of sand exclusion strategy across the reservoir as well as at the lateral mainbore junction interface. In heavy-oil sand, effective sand-control strategies must be carefully planned since one of the difficult problems to address in heavy-oil targets is their natural tendency to suspend formation solids, often referred to as Basic Solids and Water (BS&W) solids. An effective sand control strategy should allow these solids to be produced to surface and separated by the production facility. The remainder of the solids can be controlled, based on the sand-distribution qualities. If the formation sand is uniform, liner-only completions can be used for effective sand exclusion without sacrificing rate. If the formation sand is non-uniform, gravel packing will be required. For this reason, regardless of the well scenario, the gravel pack or liner only completion should allow BS&W solids to pass through and be produced to the surface.

Most heavy oil development areas use artificial lift such as PCP and ESP pumps. All multilateral completion strategies must always consider the lift strategy, the ID requirements for pump deployment as well as necessary sand exclusion requirements for the pump.

The paper examines successful multilateral completion strategies used in heavy-oil development projects in Canada, Trinidad and Venezuela. It will also explore new synergistic technologies that will impact future development strategies.
Steam Generation with High Tds Feedwater
Authors: Elias R. , Johnstone J. R. , Krause J. D. , Scanlan J. C. , Young W. W.
Published: December 2007

Generating steam with an oilfield water containing a high concentration of total dissolved solids (TDS) was tested in the North Midway Field, Kern County, California. Conventional zeolite and weak acid cation exchange softeners were used for feedwater treatment, and steam was generated in a small scale oilfield boiler. Feedwaters with TDS concentrations up to 22,500 parts per million were successfully softened to "zero" hardness levels and converted to 70% quality steam at 2300 psig. Results show that it is not necessary to have relatively fresh water for use in conventional oilfield steam generators. Furthermore, water treatment costs are economic.
Hydrocarbon-Steam Processes for Recovery of Bitumen from Oil Sands
Authors: Redford David A. , McKay Alex S.
Published: December 2007

The use of hydrocarbons together with steam was investigated as a means for improving recovery and other operating parameters in the interwell vertical steam-stimulation process for recovery of bitumen from oil sands.

A total of 42 experiments were conducted using a two-well, 18-inch diameter, three-dimensional elemental physical simulator operating at conditions close to those anticipated in the oil sands area of interest. The results of 20 of these experiments are presented.

A range of hydrocarbons from methane through ethane, propane, butane, pentane, natural gasoline, naphtha, to synthetic GCOS crude were investigated. The results of many of these experiments are presented and a number of observations and conclusions drawn. A proposed recovery process based on this work is presented.
The Effect of Dispersive Mixing on Scaling Laboratory Micellar Floods
Authors: Gash Bruce W. , Griffith T. David
Published: December 2007

For economic reasons, only a limited slug of a relatively expensive micellar fluid (followed by a polymer-water mobility bank) can be injected to displace oil with the current micellar flooding process. Once a micellar slug is injected, its composition does not remain the same; instead the composition changes as the slug propagates. Scaling the micellar flooding process can be thought of as using laboratory tests which consider the compositional changes that occur as the slug propagates to determine the minimum size slug necessary for effective displacement of oil throughout the swept portion of the reservoir.

Previous work has shown that surfactant retention is an important cause of compositional change which results in loss of displacement efficiency with a micellar slug. Dilution of a micellar slug (due to dispersive mixing) can be an equally important cause of poor displacement efficiency. In scaling a micellar flood, the dispersivity of the reservoir must be estimated from tracer tests. The ability of the micellar fluid to recover oil when it is diluted is a critical design criterion when reservoir dispersivity is large. Laboratory tests in short reservoir cores can be appropriate to simulate performance in a reservoir when the reservoir dispersivity is greater than the dispersivity of the reservoir cores. Berea sandstone which has very low dispersivity is not an appropriate porous medium in which to study the scaling of a micellar flood.
Steamflood Performance in the Kern River Field
Authors: Greaser Gary R. , Shore R. A.
Published: December 2007

The Kern River Field is a large, shallow, heavy oil reservoir located five miles northeast of Bakersfield, California. Both reservoir and fluid characteristics are very favorable for thermal recovery methods. The unconsolidated oil sands exhibit high permeabilities of 1-5 darcies (1-5 μm2) and porosities of 28-33%. Reservoir pressure is low, averaging 100 psig (690 kPa). Oil viscosities average 4000 cp (4 Pa.s) at reservoir temperature and drastically reduce at elevated temperatures.

Previous articles1,2,3,4 have been published concerning steamflood pilot design and behavior in the Kern River Field. This paper updates previous articles with a review of 263 steamflood patterns started in 1970 and 1971. The effects of sand thickness, completion interval and heat injection rates on steamflood recovery will be analyzed. Effective project evaluation through the use of temperature observation wells, coring, casing blow measurement and production from wells completed solely in the steamflood interval is emphasized. Problems of evaluating steamflood performance in a multi-zone reservoir are discussed and two field tests for improvement of steamflood sweep efficiency are also presented.
Scaling of Non-Equilibrium Phenomena in Surfactant Flooding
Authors: Hirasaki George J.
Published: December 2007

Laboratory core floods are not conducted with the same time scale as field projects. Consequently, it is possible for non-equilibrium phenomena to be significant in laboratory core floods but be insignificant in field projects. The purpose of this paper is to analyze some non-equilibrium phenomena to determine scaling groups and qualitative behavior. Scaling groups were estimated for diffusion controlling and sorption rate controlling mass transfer. Further measurements are needed to quantify interfacial resistance controlling mass transfer and intraphase rate dependent phenomena.
New Approach to Log Simulation in a Horizontal Drain – Tambora Geosteering Project-Balikpapan, Indonesia
Authors: Le Turdu Caroline , Bandyopadhyay Indrajit , Ruelland Philippe , Grivot Patrick
Published: December 2007

This paper is presenting a workflow applied successfully during the summer 2003 on the Tambora Field in East Kalimantan, Indonesia. The combination of a modeler (PETREL) together with a geosteering application (INFORM) in real time was a new approach to generate scenarios of tool response to formation changes in a horizontal drain. The aim of this paper is to share our experience and describe the workflow, which came as a real help to geosteering as events can be anticipated with a certain reaction time.

The first steps of the project consisted in preparing the 3D model, incorporating all geophysical and geological information to get a complete overview of the distribution of the petrophysical properties through the field. Once the drilling started and before entering the reservoir, the model was updated with the new picks and eventually new horizon interpretation. The GR and Resistivities were modelled and a set of synthetic logs along the well trajectory was exported from the 3D modeler into a geosteering application. Then a series of simulations of expected logs were run giving the asset team a set of possible scenarios to foresee possible situations during drilling and prepare contingency plans beforehand thereby enabling efficient geosteering.

The geomodeler enabled to build a 3D Earth model, which can be easily updated with real time data: it was also seen as a good communication tool.
A New Method for Analytical Modelling of Chemical Flooding
Authors: Shapiro A. A. , Bedrikovetsky P. G. , Pires A. P.
Published: December 2007

Compositional models with adsorption describe polymer/surfactant flooding with varying salinity. It is shown that the concentration "part" of the solution for 1-D multicomponent polymer/surfactant flooding is completely defined by adsorption isotherms and is independent of relative permeabilities and phase viscosities. We introduce potential coordinates allowing for the compositional model splitting into a thermodynamics auxiliary system and one transport equation. The number of auxiliary equations is less than the number of equations of the compositional model by one. Explicit projection and lifting procedures are derived. The splitting is valid for either self-similar continuous injection problems or non-self-similar slug injection problems.

With respect to 3-D flows, splitting takes place only for the case of constant total mobility. For the general case of the total mobility variation, mixing between fluids that enter different streamlines occurs, and splitting does not happen any more.
Methods for Delineation of Fractured Oil Bearing Conglomerate Reservoir
Authors: Liang Xing Ru , Lu Chuan Bing , Du Xin Jiang , Yuan Ke Feng
Published: December 2007

A few conglomerate oil bearing reservoirs were discovered at the northwest end of Langgu sub-depression, a local lacustrine sub-depression of the famous North China's Bohaiwan Basin. Among them, Tong 43 block is complicated in pore spaces, according to core analysis and FMI log pictures, both matrix pores and fractures occurred in this reservoir. 5 wells have been drilled so far. The oil productivity and the degree of fracturing of the reservoir of each well are of great variation. Therefore, the nature of fractures and their distribution must be clearly understood prior to production drilling program.

Two types of analysis have been applied in this study: 1) geologic analysis on genetic conditions of fractures, including studies of structural features, sedimentary facies and deformation of faulting; 2) seismic techniques, to discover the relationship between fractures and anomaly of seismic attributes, and azimuthal seismic anisotropy, thus outlining the distribution of fractures based on seismic data processing.

Through this study, three sets of fracture detecting techniques have been effectively established: 1) techniques based on genetic analysis; 2) techniques based on seismic attributes analysis, where analysis on discrepancy between different post stack attributes has been applied; and 3) pre-stack seismic techniques based on amplitude and frequency analysis on 3D seismic volume processed with varied azimuthal gathers. In this analysis, azimuthal seismic anisotropy analysis on P wave seismic data played an important part in fracture interpretation about orientation and intensity. The results of the fracture detection of each technique were reevaluated by comparing with well data and geologic conditions. The properties of oil bearing Tong 43 conglomerate bodies were evaluated in greater detail afterwards, and rich oil bearing zones were located. This study not only provides guidance for production drilling program of Tong 43 block, but can be a reference for similar reservoir delineation as well.
A New Method of In-Depth Profile Modification for High-Temperature and High-Salinity Reservoir
Authors: Tang Xiaofen , Liu Yuzhang , Qin He , Cai Lei , Jiang Ruyi
Published: December 2007

Reservoirs in Tarim Basin, China west, were geologically formed in marine environment with high temperature (over 140) and high salinity (up to 25% TDS and 1% Ca2+ + Mg2+). After 10 years of development by water flooding, unwanted water production become a big problem. This is caused by uneven water sweep due to severe reservoir heterogeneities. Unfortunately, there are no in-depth profile modification agents that can stand such harsh reservoir conditions.

To address the problem, a novel process is developed which takes advantage of the multi-valence cations concentrated in both the formation and injection water and injects a compounded silicate to react with the cations to form gel, so the method is cost effective. Bulk gel or disperse gel can be formed depending on the proportion and concentration of the silicate and multi-valence cations in the water. Beaker test shows that the gel has desired properties of HT/H Salinity resistance and long-term stability. Core flood tests verify that, by slug injection, the process can gradually build long lasting residue resistance factor (RRF) for water flow in high permeability streaks indicating a "layering" or "coating" mechanism. To investigate the possibilities of gel adherence to tubing, slim tubing physical simulation is also performed.
Formation Damage Mitigation in High Pressure High Temperature Gas Field
Authors: Hamid Pauziyah Abdul , Yaakub Mohd Azriyuddin , Ganesan Nadeson , Kasim Selamat
Published: December 2007

During a workover campaign in one of the high pressure gas field offshore Peninsular Malaysia, several wells have been identified as potential to provide additional gas production. One well in particular, was suspected to have severe formation impairment in which the project team believed could be removed through the use of demulsifying wash agent and mineral complex dissolver.

During the drilling campaign of the well, production zone was drilled with 14 ppg OBM. After perforating the well, the brine system used (11.6 ppg CaCl2) was unable to contain the pressure. It was then decided to revert to OBM since higher brine weight was not sufficient to secure the well. The well was then completed with the same. However the well was producing below performance and was not doing any better with acidisation.

Following that, a laboratory assessment was conducted to evaluate the extent of the damage and to investigate the performance of a demulsifying wash agent and minerals complex dissolver in mitigating the formation impairment.

This paper described the laboratory assessment and field implementation of the chemicals in mitigating formation impairment that occurred in the reservoir. The results from laboratory assessment on compatibility analyses, corrosion test and core flow test were presented and discussed. In addition, the results from field implementation were also presented and discussed.
Characterizing Permeability for the Fractured Basement Reservoirs
Authors: Li Bingjian , Guttormsen Joel , Hoi Tran V. , Duc Nguyen V.
Published: December 2007

Permeability is one of the major controls for production in fractured basement. It is critical to be able to identify and characterize permeable zones in the basement reservoirs not only for evaluating well producing potential but also for designing perforation, well completion and injection. Even though geoscientists and reservoir engineers have made considerable effort over the years to better characterize the permeability profile in fractured basement, it is still very challenging to achieve this objective.

This paper presents a newly developed approach aimed at better understanding the permeability profile. The technique was developed based on case studies from wells in two different basement fields located offshore in the south of Vietnam. Traditionally, fractures have been characterized using core and borehole image data. In this study, borehole image data were integrated with other open-hole logs to derive a permeability curve. The result was calibrated with core data and then validated with dynamic data i.e. production log data, well testing data, mud losses, gas shows. As demonstrated in the case studies, it is believed that the permeability in the basement could be reasonably evaluated using this method. However, in a zone where fractures are cemented or partially cemented with conductive minerals, the log-derived permeability needs to be calibrated with the degree of cementation.
Thermal Desorption of Oil from Oil-Based Drilling Fluids Cuttings: Processes and Technologies
Authors: Stephenson Ralph L. , Seaton Simon , McCharen Robert , Hernandez Edgardo , Pair R. Benson
Published: December 2007

Proposal

This paper presents the results of a study of processes and technologies for the thermal desorption of oil from oil-based drilling fluids cuttings for both onshore and offshore applications. A field investigation of available technologies designed to separate oil from oil-based drilling fluids cuttings by thermal desorption was conducted. In addition, some technologies that perform separation by physical-chemical means were also investigated; however, all commercial processes presently available use thermal desorption.

The mechanisms of desorption of oil from cuttings were investigated. Process parameters and theoretical concepts for thermal desorption by distillation were developed using proprietary computer simulation programs for the distillation of hydrocarbons. Theoretically ideal temperatures for the process were calculated for various conditions and for various oils. The impact of moisture and oil content on the heat balance was calculated. The recoverability of the oil under various conditions was investigated.

Nineteen companies were contacted for information on their desorption technology. Twelve company sites were visited to determine the developmental stage of their technology and to determine how well the technology functioned in the field. The technologies were evaluated for air emissions, liquid emissions, safety, oil content of processed material, space requirements, utility and chemical requirements, and other operating and design factors. Applicability of the technologies for offshore use was evaluated. Safety and environmental issues for each technology and the recycling of oil are also addressed in this paper, along with future work needs in this area.
Screening Methodology for Downhole Sand Control Selection
Authors: Farrow Chris , Munro David , McCarthy Thomas
Published: December 2007

The Sand Management Strategy for existing North West Shelf (NWS) fields involves reactive downhole sand control in the event sand is produced above acceptable limits. Sand face completions for new wells consider well and system risks over the life of the development.

A screening methodology has been developed to evaluate and rank the available sand control techniques for NWS conditions. Published criteria are used in a systematic manner, allowing a consistent, balanced and transparent view of benefits and risks across the different ‘system’ aspects.

The methodology incorporates a combination of a flowchart and sand control matrix, where each selection criterion is evaluated according to a likelihood × consequence ranking. In this way all relevant information and its relative importance are included in the decision making process.

This paper describes the methodology and its application for conceptual design across a number of NWS high rate gas well case studies. These range from existing, near-vertical platform wells to new, horizontal subsea wells.
A Plastic Pre-Coated Gravel For Controlling Formation Sand (February 1980)
Authors: Underdown David R. , Day Jon C. , Sparlin Derry D.
Published: December 2007

Results of field tests and laboratory evaluation have shown that a plastic pre-coated gravel system is a successful method of sand control for both non-thermal and thermal wells. Significant improvements in this process have been made which provide higher compressive strengths, increased quality of coating, greater chemical and thermal stability and higher permeability of the consolidated gravel. These results have been obtained by using higher quality gravel, an improved coating process and improved placement techniques.

Full scale pumping tests and actual field results indicate that this system provides a consolidated gravel pack capable of controlling sand production without impairing fluid production. The use of this type of material even prior to the improvements has provided good sand control in both injection and production wells in the offshore Gulf Coast region for over a year. Field results in the San Joaquin Valley, California have demonstrated that it is also well suited for sand control in moderate temperature thermal wells. Wells using both steam drive and huff-and-puff methods of stimulation which have employed this improved plastic coated gravel have increased production and virtually eliminated bailing of sand.
Methane Pressure Cycling Process with Horizontal Wells for Thin Heavy Oil Reservoirs
Authors: Dong Mingzhe , Huang Sam , Hutchence Keith
Published: December 2007

The methane pressure cycling process is an enhanced oil recovery scheme intended for application in some heavy oil reservoirs either after termination of primary, or waterflood, production. The essence of the process is the restoration of the solution gas drive mechanism. The restoration is accomplished by re-injecting an appropriate amount of solution gas (mainly methane) and then re-pressuring the gas back into solution by injecting water until about original reservoir pressure is reached. This, aside from the replacement of produced oil by water, re-creates the primary production conditions. This novel recovery technique is being developed to target the considerable portion of heavy oil resource located in thin reservoirs. Primary and secondary methods have managed to recover at best 10% of the initial oil-in-place. Heat losses to overburden and underburden or bottomwater zones make thermal methods unsuitable for thin reservoirs.

Coreflood tests in 30.5 cm (length) H 5.0 cm (diameter) sandpacks were carried out for oils with a range of dead oil viscosities from 1,700 to 5,400 mPa.s. The results showed that the pressure cycling process could create a favorable condition for recharged gas to contact the remaining oil in reservoirs. This restores the situation whereby substantial amounts of gas are in solution for further "primary" production. The effects on the efficiency of the methane pressure cycling process of cycle termination strategy, oil viscosity, and mobile water saturation were investigated. Simulations were conducted to investigate the methane pressure cycling process in three heavy oil reservoirs in Saskatchewan, Canada. The effects on the process of infill wells, oil viscosity, gas injection rate, and the presence of wormholes in reservoirs were studied.
Using Intelligent Well Technology to Define Reservoir Characterization and Reduce Uncertainty
Authors: Paino Wan-Faisal , Tengah Noorilmee H , Woodward Myles I. , Snaith Nigel , Salleh Hadizah , Browne Mark
Published: December 2007

A three-hole appraisal campaign was conducted in 2002 with objectives to reduce the in-place volumetric uncertainties, reservoir connectivity and deliverability uncertainties of the Bugan oil/gas field, offshore Brunei. Bugan-6 and Bugan-6st1 were drilled to address volumetric uncertainties. Bugan-7 was drilled and completed from the nearby Iron Duke facility. The well was an early development/appraisal well in four separate oil rims. A three zone intelligent completion was installed with the specific objective of assessing compartmentalization and deliverability uncertainties before full field development.

The intelligent well components consisted of three surface controlled internal control valves (ICVs), a distributed temperature sensor fibre (DTS) and six downhole pressure gauges (PDHG).

The ICVs has enabled each of the zones to be tested individually without incurring deferment or intervention costs. In addition to acquiring productivity data on each of the individual zones, the ICVs have enabled downhole shut-ins to be performed and corresponding permeability data and skin data to be obtained.

After six months of production, an increase in GOR was observed. The DTS data showed gas breakthrough has occurred in a thin sand in the lower producing zone. Early identification of this high permeability sand has enabled refinement of the simulation model and adjustment of future well designs to minimize impact.

Accurate zonal production and pressure data has allowed a preliminary material balance to establish the minimum connected volume to the well. This information has discounted the highly compartmentalized reservoir scenario.

Installation of the intelligent completion has enabled a significantly better reservoir model to be developed with a reduction in the uncertainty ranges. This will enable optimization of future wells in the field and significantly increase the value of the field.
The Use of Drilling Cutting in Measuring Permeability, Can This Be Done?
Authors: Talabani Soran , Thamir Falah
Published: December 2007

The current available equipment used in the laboratory to measure core sample permeability is limited. Special core size is needed for the equipment, core faces are always damaged while cutting, and samples cannot be oriented to measure vector permeability.

The right way to measure absolute permeability is by using a non-damaged core sample by chipping it off from the rock. This is difficult though.

A new design is particularly made so that a piece of cutting can be used to measure permeability. This can accommodate for different drilling cutting size, minimum size is needed though.

The benefits of using cutting samples are; measurement of vector permeability, cutting faces are not damaged hence, more realistic measurement, and this measurement is made instantly in the field.
A Practical Approach to Solids Control Through Economic Evaluation of Mechanical Equipment
Authors: Conyers J. C.
Published: December 2007

A good solids control program is essential in order to attain the goal of an optimized drilling program. Proper application and utilization of mechanical solids removal equipment enables the driller to maintain the desired drilling fluid properties which in turn makes it possible for the drilling operation to be carried out in an efficient and economical manner.

Drilled solids have a direct and pronounced effect on the drilling fluid. Since the drilling fluid is itself so closely related to a wide range of factors which determine both daily and total drilling costs, it is obvious that there exists a strong relationship between the control of drilled solids and the control of drilling costs.

This paper will present methods to calculate the mechanical efficiency of solids control equipment on site during drilling operations and will demonstrate from case histories a method of determining the economic justification for the use of mechanical equipment.

Data presented in this paper is based on information gained in the field evaluation of various types of solids control equipment, including sophisticated fluids processing systems, under a wide variety of weather, geographic and geologic conditions.
Underwater Communication, Navigation and Positioning in the Waters of Tomorrow
Authors: Elson Scott , Mann Jim , Stuart Ross
Published: December 2007

Today the offshore industry requires more from its navigation and positioning technology: more accuracy, more integrity, more range or depth and more data. With the advent of super fast wireless communications in the home and office, it is often the case that the physical limitations of the environment in which we work underwater is less well understood, especially when you combine the demands for "More" with those of "Less" from the purse holders. This paper will deliver an insight into a technology that is being used by ROV, AUV, DP Vessels, Ships and the Subsea Production Hardware to, not only position and navigate underwater, but also to communicate, without the use of cables It will include details of recent implementations of these technologies including the "Underwater GPS" and "Wireless Control System". Applications and experience with 21st Century Acoustic Technology will set the audience thinking of the other possibilities open to them.
Subsea Multiphase Boosting - Maturing technology Applied for Santos Ltd's Mutineer and Exeter field
Authors: Grimstad Haakon J.
Published: December 2007

The paper presents the state of art in subsea multiphase boosting. This includes the subsea pump, subsea integration, power and control system, umbilical, and intervention.

Further, the typical applications and characteristics for subsea multiphase boosting systems will be addressed. The benefits to the users are normally related to reduced investments and even more important, increased and/or accelerated oil production. There are also several examples of subsea multiphase pumps as production enabling equipment. Typical reference projects and field experience will also be presented.

Although multiphase pumps in most cases are used as independent systems there may be a significant potential in combining this solution with other artificial lift technologies. They may be used in combination with gas lift or downhole pumps to offer integrated systems with premium reliability and economics.

The second part of the presentation will be related specifically to the subsea multiphase pump system recently selected for Santos LTd's Mutineer and Exeter field offshore NW Australia. The overall subsea system architecture will be presented with particular focus on the subsea multiphase pump system. Considerations, advantages and expectations to this solution as seen by the operator, will be addressed.
Modifying a Pipeline Corrosion Management Strategy to Changing Conditions
Authors: Russ Paul R , Rainsford Christopher
Published: December 2007

Internal corrosion in pipelines is an industry-wide problem. Papers have been written describing inspection tools and smart pig findings, but few focus on how to modify a corrosion management program to halt corrosion once an affected pipeline is identified. This paper discusses actual field data obtained from Esso Australia's main oil pipeline, and presents the corrosion management changes that were necessary to control further wall loss.

This paper demonstrates that a broad, disciplined approach to monitoring and sampling is required to control pipeline corrosion as conditions change. Differentiation between export and inter-platform pipelines is made and the different types of corrosion inhibitor to use in these lines are considered. The effect of platform upsets and ways to mitigate the impacts of additional water to pipeline are discussed, as is the development of a comprehensive and meaningful sampling program.

The threat of microbiological induced corrosion (MIC) to pipeline life and mitigation tactics that are being employed is also presented. Comparisons between old and new inspection and monitoring results will be given to demonstrate the benefits of adopting the new corrosion management program.

To effectively prolong the life of an old pipeline network operating in a mature operation, proactive changes to a pipeline corrosion management strategy incorporating field analysis and monitoring are required.
Development Techniques for Abnormal High-Pressure Gas Fields and Condensate Gas Fields in Tarim Basin
Authors: Song Wenjie , Jiang Tongwen , Wang Zhenbiao , Li Ruyong , Feng Jilei , Zhu Zhongqian
Published: December 2007

Tarim Basin is the most hydrocarbon-abundant onshore basin in China. It occupies an important position in "West-to-East Gas Transportation" project. The major force gas fields are of large scale, abnormal high prossure and high productivity of a single well. The condensate gas fields are usually of high formation pressure, high condensate oil content and high pressure of dew point. Through deepening study on the development mechanism and development technologies of the gas fields and condensate gas fields, a series of development technologies in the super-deep and high-pressure gas fields and condensate gas fields in Tarim Basin have come into being in the development practice. The technologies not only have helped to build up Yaha Condensate Gas Field with the largest condensate oil productivity in China, but also have been extensively applied in the early-stage development eveluation of several gas fields in "West-to-East Gas Transportation" project and the comprehensive adjustment of Kekeya Condensate Gas Field. A new model has been created to develop super-deep and high-pressure gas fields and condensate gas fields.
Field Cases to Demonstrate Application of through Tubing Inflatable Anchoring Packer to Selectively Stimulate Vertical Dump Water Injector Wells with Cross Flowing Zones
Authors: Al-Dubais A. M. , Kharari A. H. , Jemmali M. , Al-Hadyani F. S. , Wilson S. , Samuel M.
Published: December 2007

There are few methods to acid stimulate cross-flowing zones in dump water injector wells. Traditionally these wells are stimulated by bull-heading acid from surface or pumping it through Coiled Tubing (CT). The dilution and contamination of the acid while being injected into the formation resulted in no increase in dumping injection rates. Poor post stimulation results are confirmed by spinner survey logs done before and after the conventional acid treatments.

Through Tubing Inflatable Anchoring Packer (TTIAP), a new zonal isolation tool conveyed by coiled tubing was successfully used to selectively acidize the targeted zone by isolating the non-desired zones. TTIAP has an effective and reliable high pressure sealing properties at large inflation ratio. Its chemical resistance makes it ideal for selective placement of treating fluids, such as acid stimulation and water shut off fluids.1,2

A non-polymeric Viscoelastic Surfactant based Self Diverting Acid (VES-SDA) system was successfully used to divert and effectively stimulate these vertical dump water injector wells by achieving uniform acid coverage across the whole perforated interval. The VES-SDA is a single stage fluid that has the capability to stimulate and divert in one step.

This paper discusses the successful application of TTIAP as a mean of mechanical diversion in the well-bore area to isolate between the "S" aquifer and the "R" reservoir, while VES-SDA acid was used as a mean of chemical diversion inside carbonate formations. The injection evaluation logs showed significant injection rate increase after the new stimulation method.

This study marks the first time such a combination was used to stimulate dump water injector wells with crossflowing zones in Saudi Arabia.
Hydraulic Fracturing of Polymer Injection Wells
Authors: Yan Wang , Demin Wang , Zhi Sun , Changlan Shi , Gang Wang , Desheng Li
Published: December 2007

Polymer flooding is of strategic importance to Daqing Oil Field. At present, the oil production by polymer flooding is more than 12 million tons per year. However, some problems still need to be solved; fracturing in polymer injection wells is one of these problems. After fracturing more than 40 polymer injection wells by conventional methods, the results show that the effective period of fracturing is less than 3 months. This paper focuses on the reasons of this phenomenon (short effective period), how to solve this problem, what is the best operation procedure in the field and does it suit water injection wells also.

From lab tests, it was found that under high injection pressure, the proppant in the fracture can propagate forward (especially when injecting high viscosity fluids), thereby causing the fracture near the well bore to close and the frac job to fail in a very short time. Lab and well site tests show that using resin coated sand (the proppant is adhesives together in the fracture to form a very porous pancake and cannot propagate forward) can greatly increase the effective period of the frac job in polymer injection wells (from 3 months to 30 months). The results in the field of 97 polymer injection wells fractured by this method are analyzed by using injectivity index curves and compared to that of conventionally fractured injection wells. The results of 13 water injection wells are also analyzed, showing that they are very good also, the effective period of the frac job increased from 6 months to more than 24 months. Now, most of the frac jobs on injection wells (both polymer and water injection wells) in Daqing are stimulated using the method described in this paper. This method should also be of reference value to injection wells that have a short effective period to a frac job.
Fracture Propagation Prediction in an Openhole Horizontal Injector Well: An Applied Geomechanic Study
Authors: Chavez J. C. , McCurdy P. , Morgan L.
Published: December 2007

Understanding and predicting fracture propagation behaviour in a geotectonically complex, layered reservoir presents major challenges. In particular, an accurate prediction of vertical fracture extension in horizontal injection wells is fundamental to the overall waterflood injection performance assessment.

Water injection in an open hole horizontal well in a low permeability formation may generate one or multiple fracture planes depending principally on the orientation of the well with respect to the in situ stress field, as well as the combined effects of high injection rates, low injectivity and stress reduction due to thermal effects.

Conventional fracture generation prediction in horizontal sections considers predetermined areas where the fractures will propagate. In an open hole environment, the number of fractures that will be generated over time is often too complex to allow accurate prediction.

A novel methodology, based on a fracture energy dissipation approach, has been developed to overcome the problems associated with conventional models in horizontal open hole sections. This strategy integrates the field geomechanical model with a commercial transient fracture simulation model. The simulation model was used to predict the vertical extension of the fractures by studying the energy dissipation that takes place under specific injection conditions.

A relationship has been found between the initiation area, injection flow rate and the non-dimensional vertical propagation factor that can be used to predict (and ultimately control) vertical fracture growth even in heterogeneous sand-shale sequences. The introduction of selective initiation areas along the horizontal well section will radically improve the control of fracture vertical extension.

Using this methodology, it is possible to design and evaluate completion strategies, which optimise fracture energy dissipation and fracture containment performance in open hole horizontal injection wells in low permeability formations.
Wellbore Stability of Extended Reach Wells in an Oil Field in Sarawak Basin, South China Sea
Authors: Tan C. P. , Yaakub Mohd Azriyuddin , Chen Xi , Willoughby D. R. , Choi S. K. , Wu B.
Published: December 2007

The development plan of an oil field in the Sarawak Basin, South China Sea includes extended reach wells. Drilling experience in exploration wells highlighted the issue of wellbore instability in the region. A wide range of wellbore instability-related problems has been experienced, ranging from tight hole (remedied by reaming) to overpull and stuck tool, and a range of drilling fluid designs has been implemented. There was considerable concern regarding wellbore stability, including coal bed instability, its effect on drilling performance and the potential for this to severely impact both schedule and budget. Subsequently, a wellbore stability study, with an emphasis on extended reach wells planned for the field development, was conducted. The aim of the study was to develop a strategy to maintain mechanical and time-dependent stability of the extended reach wells to ensure the well construction encounters minimum wellbore instability-related problems. With the availability of additional well data and the need to push the technical limit of the drilling campaign, a follow-up review study was conducted and the additional information was used to refine the critical mud weight contour plots for a range of wellbore enlargements.

This paper describes the outline of the study, the approach adopted in the development of the strategies and the utilisation of the results from the two studies to develop recommendations for the mud weight programs. The drilling experience, material properties, typical in-situ stresses and formation pressure in the field are presented and discussed. Based on the gathered drilling experience, composite logs and laboratory tests conducted on downhole core materials, dominant failure mechanisms for the key formations and coal beds were identified. An empirical approach was adopted for the prediction of lower bound mud weights for wellbore enlargements ranging form 10% to 40% of wellbore diameter. Examples of critical mud weight contour plots and pore pressure change tables which form part of the strategy for designing optimal drilling fluid program are presented.