bluuebunny/crossref_metadata_2025 huggingface dataset:
Reinventing the Wheel - Reducing Friction in High-Angle Wells
Authors: Mason Colin J. , Williams Larry G. , Murray Geoff N.
Published: December 2007

Extended Reach (ER) wells have usually been proven the world over to provide an exceptionally cost effective means of field development. For example, in one particular instance, adoption of ER drilling resulted in +/− 50% savings compared with a sub-sea completed well. Additionally, intervention costs were dramatically reduced since the substantial cost associated with mobilizing a "floater" into the relatively remote area was averted (1).

Frictional losses due to torque/drag (T/D) are a primary limitation in extending the reach of many high angle wells. This paper specifically considers T/D problems associated with current well designs and presents roller-based tool technology as a solution for reducing mechanical friction losses.

Also considered are some of the other merits of roller type technology that are not immediately apparent. They include decreased likelihood of differential sticking; an important consideration given the significant 4D seismic created interest in in-fiII drilling. The drilling tools can also have an impact on drilling performance by helping to reduce axial and rotational stick/slip, thus prolonging bit life, increasing rate of penetration (ROP), and potentially avoiding a trip to replace the bit.

Field trial results, case studies and laboratory tests will demonstrate that roller-based tools are an effective solution to combating mechanical frictional losses.

An important point is that since roller-based tools function almost independently of drilling fluid type, they should enable operators to use lower-cost drilling fluids, such as water based muds that comply more easily with local environmental legislation.
CO2 Flood Potential of California Oil Reservoirs and Possible CO2 Sources
Authors: Jeschke P. A. , Schoeling L. , Hemmings J.
Published: December 2007

Carbon Dioxide (CO2) has been used to enhance oil recovery for several decades in both miscible and immiscible floods depending on the type of oil and class of reservoir. Numerous CO2 floods are presently active in four countries with the majority in the Permian Basin of the U.S. where both naturally occurring CO2 and pipeline infrastructure exist and where over 50 million barrels of incremental oil per year are produced. Estimates indicate that additional billions of barrels of oil could be produced in the U.S. alone with CO2 flooding if CO2 could be economically delivered to the producing states' oil fields. California has the second highest potential of any state to produce oil with CO2 flooding but has no naturally occurring deposits of CO2 or CO2 pipeline infrastructure. This paper presents the results of a study of the CO2 flood potential of California oil reservoirs and the possible sources of CO2 for California enhanced oil recovery projects.
Experience of IOR Practices from Large-Scale Implementation in Layered Sandstones
Authors: Wang Demin , Cheng Jiecheng , Li Qun , Jiang Youlin , Sun Yingjie , He Yixin
Published: December 2007

Daqing Oil Field has produced more than 11 billion barrels of crude oil and is still producing at a rate of more than one million barrels of oil per day. In its development, it has extensively implemented numerous IOR methods. The results are very good, total oil production from the IOR methods is more than 700,000 barrels oil per day and it has more the doubled the recoverable reserves of the oil-field (from 8 billion barrels to about 18 billion). Also, much has been learned from the above large-scale IOR practiced, some of which are: The major aim of IOR methods is to increase the volumetric sweep efficiency, displacement efficiency and decrease the water cut (on condition that corrosion, sand, casing damage and environmental issues are not major problems in the field). Results of IOR methods should mainly be measured by a) the total incremental recovery and b) the ratio of the increase in recovery to its costs. To obtain good overall results, large scale implementation on most of the wells in a field is recommended. Otherwise, there will be an increase in production in wells but un-significant increase in recovery of the total reservoir;The results of different IOR methods are mainly dependent on the heterogeneity and water cut of the reservoirs and the IOR method used. Numerical simulation predictions are given and compared to the actual field results. The comparison is satisfactory;For stacked reservoirs, besides horizontal drilling, most IOR methods obtained very good results;For single layer reservoirs, besides chemical flooding and horizontal drilling, most IOR methods were not satisfactory;The reasons that selective water plugging at producers and in-depth profile modification at injectors are not satisfactory and challenges that need to be met are put forward;Criteria for the cost of incremental oil by chemical flooding to be higher, equal or lower than water flooding are put forward with actual field data:The reasons that in-fill drilling of single layer reservoirs can increase the production rate significantly and also the recovery slightly is explained with numerical simulation data and actual field examples.

The above lessons learnt are all from large-scale implementation and numerical simulation, which makes the conclusions more reliable and should be of reference use in the development of layered reservoirs.
Management Overview of the Integrated Studies of Nine Mature Gas Fields in the Cooper Basin of South Australia
Authors: Bard K. C. , Harrison T. , Meade K.
Published: December 2007

In January 1999 Santos on behalf of the South Australian Cooper Basin Joint Venture (SACB JV) began a detailed Integrated Reservoir Study (IRS) of nine mature gas fields in the South Australian Cooper Basin with a team of Santos staff, supplemented by personnel from a Landmark/Fekete/Halli- burton Consortium. The IRS project was to be completed in eighteen months with the following key objectives:

Business

Technical

The studies were to be comprehensive, and were required to include the following: data preparation, petrophysics, geophysics, 3D geological modeling, reservoir engineering, dynamic reservoir simulation, production engineering, drilling engineering, surface facilities and economics, with the final product being a fully documented field development plan for each field. This paper will discuss the key elements to the success of this project.
Modelling Phase Behaviour Including the Effect of Pressure and Temperature on Asphaltene Precipitation
Authors: Kohse Bruce F. , Nghiem Long X. , Maeda Haruo , Ohno Kenji
Published: December 2007

This paper describes a procedure for matching PVT data of a typical oil that includes asphaltene precipitation data. The fluid PVT data are from constant composition expansion, differential liberation and separator test experiments. The experimental precipitation data consist of measurements of precipitation onset pressures at different temperatures.

The PVT data are validated for consistency using Hoffman plots, and matched with the Peng-Robinson equation of state1. A pure solid model is used to model the asphaltene precipitate2,3,4. The equations describing effect of pressure and temperature on the solid model are given. The parameters of the solid model are adjusted to match the asphaltene precipitation data.
Field Application of Multi-Dimensional Diagnosis of Reservoir Rock Stability Against Sanding Problem
Authors: Doi Manabu , Murakami Takahiro , Ueda Yoshiaki , Ohkuma Hiroshi
Published: December 2007

In the studied oil filed, the sanding problems have been recognized to intensify in 1990s when water production has become substantial. It is predicted that water production will increase due to the driving mechanism and its reservoir fluid and rock characteristics. It is important to study and analyze the formation's sand production potential at this stage of the reservoir development, and formulate a sand control strategy in order to optimize the field operation.

In sand prediction, one of the most indicative parameters is UCS (Unconfined Compressive Strength) of reservoir rocks. In order to improve the estimation of UCS profile in the target sandstone interval, we employed a back-propagation neural network which relates the rock strength and well log responses. The errors in the UCS estimation were examined by changing structure of the network, combination of reference well log types, and selection of the actual UCS learning data. Some combinations of the well logs with sonic log generated a high accuracy estimation of UCS data.

Using the UCS data thus estimated, the stability of perforation cavities under anticipated production condition was investigated with a FEM numerical model. Based on the sensitivity of the operational conditions, the results demarcated the reservoir rock conditions into "safe", "manageable", and "catastrophic" regions1 with more confidence than before.

This multi-dimensional diagnosis of reservoir rock stability indicated the practical guideline for the well completion through organized logging programs and perforation design (selective/oriented) to minimize the sand risk. It also suggested the general production constraints of critical draw down in the artificial lift to optimize the production operation. Following the introduction of the study in the first chapter, the second chapter summarizes the formation strength characterization. The formation failure analysis using these rock properties is described in the following chapter. The sand control strategies based on this analysis are briefly summarized as concluding remarks.
Case Study: Coalbed Methane Automation System for River Gas Corporation
Authors: Robertson Steve K. , Pool Mike , Farrens Michael J. , Butts Tammie J.
Published: December 2007

Can an independent producer fulfill a vision to develop and produce a coalbed methane gas field that covers two hundred square miles in a remote desert plateau in the western United States? This paper answers that question as well as provides answers to other pertinent questions such as, "What tools would be available to the operator to efficiently and safely produce the wells?" And, "Would the tools allow for future expansion and/or allow state-of-the-art technologies to be cost effectively incorporated into the system?"

This case study shows how River Gas Corporation successfully implemented an automation system that was jointly developed with an engineering/manufacturing company to efficiently fulfill their needs.

All phases of the project from its inception in 1991 with a 13-well pilot project to a planned 600-well development will be discussed along with the innovative methods that were applied to address the above questions. The resulting system was capable of successfully meeting the continuing changes in expansion and production.
Integration of Computer-Aided High-Intensity Design with Reservoir Exploitation of Remote and Offshore Locations
Authors: Saputelli Luigi , Cherian Bilu , Gregoriadis Karolos , Nikolaou Michael , Oudinot Cedric , Reddy Gopal , Economides Michael J. , Ehlig-Economides Christine
Published: December 2007

Offshore and remote-location hydrocarbon production structures operate in a dynamic (unsteady state) environment where decisions continually have to be made about equipment design, construction, and operation. Such decisions and resulting subsequent actions have a significant and lasting effect on the operation, safety, and profitability of the structure. For example, during the life of an offshore structure, decisions have to be made about the number, placement, and design of separators, dehydration, sweetening or other processing units; switching times from production to injection; timing and location of multilateral branches; etc.

The engineer faced with carrying out tasks such as the above may be substantially aided by suitable computer-aideddesign-and-operation software tools. Use of such tools could streamline or automate design tasks (thus improving repeatability and reliability of task completion, making efficient use of manpower, reducing task completion time, effectively coordinating interdependent concurrent tasks, and cost-effectively approaching optimality) andoptimize operating strategies (thus safely and reliably improving long-term profitability without burdening the engineer with excessive decision making tasks).

This paper introduces the technology of integrated computer-aided design and operations to petroleum production. Current practices in other industries such as oil refining, petrochemicals, and aerospace will be investigated with the intention, first, to modify them for petroleum applications and, potentially, advance the state-of-the-art.
Observed Contaminant Migration from an Instrumented Reserve Pit
Authors: Deuel Lloyd E. , Holliday George H.
Published: December 2007

A 3.3-meter deep fresh water drilling fluid reserve pit was instrumented to determine migration of contaminates from the pit during drilling and after pit closure. The ability to predict impacts from earthen drilling pits has become important, due to the recognized potential for an adverse impact on soil and water resources. The results of the field study allow operators to control chemical composition of pit wastes to prevent contaminants from migrating from an active or closed pit. To the best of our knowledge, no other reserve pit has been evaluated by instrumentation installed a priori to evaluate the environmental impact of reserve pits.

The pit was equipped with neutron probe access tubes, barrel size lysimeters, vacuum extraction moisture cups and gypsum resistively blocks at 4 stations within the pit perimeter. Ground water monitoring wells, and post closure soil borings were used to assess the long-term affects of the earthen pit use and onsite disposal of the pit waste solids on soil and ground water resources.

The soil moisture and chemical data generated during the 2-year field study was evaluated statistically utilizing analyses of variance (ANOVA). Soil water monitoring during pit use showed the soil profile below the pit remained unsaturated under the influence of a 3.3-m head of pit fluid. This demonstrated the clay gels [spud mud] serve as a pit surface sealant and retards percolation of fluids from the pit. Chlorides were retained in the pit by an anion exclusion mechanism. This mechanism remained stable and the exclusion volume functional in pit solids having Saturated Paste Electrical Conductivity [SPEC] of ? 24 mmhos/cm. Post closure data show clean closure of the study pit and no alteration of intended land use (improved pasture) or adverse impact to the natural environment.
Optimization Design for Conformance Control Based on Profile Modification Treatments of Multiple Injectors in a Reservoir
Authors: Liu Y. Z. , Bai B. , Li Y. X. , Coste J-P. , Guo X. H.
Published: December 2007

Within the past 40 years, profile modification has been widely used in China to control excess water production and improve waterflood sweep efficiency. As most reservoirs reach mature stage, single well treatment often becomes uneconomic. Therefore, profile modification treatments of multiple injectors based on reservoir scale have been applied to improve reservoir conformance. In this paper, a method is introduced to optimize the design of the treatment. The selection of the wells and target layers, as well as the chemical agent and injection parameters can be achieved by this method. The selection of candidate wells is based on fuzzy mathematics methods, considering well injectivity, reservoir heterogeneity and offset production well performance. The chemical agent is selected from over 40 formula commonly used in China, according to its compatibility with reservoir characteristics and well injectivity. The volume of treatment is optimized by running numerical simulations. This optimization method has been widely used in many oilfields in China. In most cases, production analysis after treatment shows that the waterflood efficiency is improved, and that the model predictions match well with the actual production data. As an example, a detailed analysis of the treatment performed in the Long 11 fault-block reservoir in Qing Long Tai oilfield is given in the paper.
High-Energy Perforation and Fracturing (HEPF)----Great Revolution of Perforation for 21st Century
Authors: Zhang Tinghan , Zhang Xi , Li Ning , Li Kuan
Published: December 2007

Based on the snalysis of 50-year-long experiences of conventional perforation, this paper presents an innovative perforation techique that two different types of high energy-shaped charge and propellant are being put inside the gun, and these two types of energy would be ignited at the same time but be put in action separately, therefore perforation and fracturing could be combined perfectly, forming high conductine tunnel-fracturing network and greatly increasing percolation area around near wellbore, Surface concrete target test shows length of semi-radial fracture is 2500mm, More than 700 wells application proved that this technique is safely operating, and greatly increasing production and injection. At present, the comprehensive system of apparatus study and manufacture, surface test, operation art, modern downhole test and intelligent software is being composed, which will make progress and revolutionize international perforation.
Parallel Reservoir Simulation on Shared and Distributed Memory System
Authors: Liu Wei , Cao Jianwen , Mezzatesta Alberto , Zhu Peng
Published: December 2007

Computational efficiency is a major subject in large-scale reservoir simulations. Parallel simulation has gained popularity in recent years. Complex geological environments and production management demand new mathematics and science in various computational environments.

This paper presented a parallel simulation algorithm and data processing developed for shared and distributed memory systems. The preconditioned Krylov subspace method with hybrid preconditioner based on domain decomposition was constructed to solve the large-scale linear system resulted from black-oil simulator techniques.

Based on a fully implicit, three-dimensional, three-phase black-oil reservoir simulator, this project focused on the numerical intensive linear solver. The parallel algorithm is scalable and applicable to both shared and distributed memory systems. Numerical tests were performed on both multi-CPU workstations and PC clusters. A message passing interface (MPI) library was adopted for all message passing functionality in both shared and distributed memory environments. Input/output parallelism and localism are presented in these hardware setups.

Numerical results from benchmark models and field application examples are presented for both the multi-CPU SGI Power Challenger and a Linux based Intel PC cluster. Results show that the speedup factor is significant. The simulation performance increases with the number of processors and only decreases due to the limitations introduced by message passing activities.
Development of an Oil-Based Gravel-Pack Carrier Fluid
Authors: Kelkar S. , Parlar M. , Price-Smith C. , Hurst G. , Brady M. , Morris L.
Published: December 2007

Operational problems arise when wells drilled with synthetic/oil-based reservoir drilling fluid (S/OB-RDF) systems are completed using traditional water-based gravel pack carrier fluids. Fluid compatibility, formation wettability and filter cake cleanup have to be addressed, along with the cost of prolonged rig time, for displacements and pit cleaning. There is significant potential for oil-based gravel pack carrier fluids for completing openhole horizontal wells drilled with S/OB-RDFs. Oil-based carrier fluids may minimize compatibility issues, reduce rig time, and provide a means for filter cake cleanup. At a minimum, oil-based gravel pack carrier fluids should:

Carry and suspend gravel at downhole temperatures Provide density up to 13.5 ppg for well control Be compatible with standard oil- and synthetic-based muds and additives.

An oil-based gravel pack carrier fluid with these fluid characteristics has been developed. The fluid system is formulated using a low aromatic base hydrocarbon, a heavy brine formulation (e.g. NaCl, CaCl2, CaBr2, K-formate.) and a surfactant. Results indicate that the fluid system is stable under shear, has good gravel suspension characteristics and has a low formation damage potential. Yard test data demonstrate the feasibility of the fluid system when used in conjunction with shunt screen technology.
Structure and Process Optimization for the Use of a Polymeric Relative-Permeability Modifier in Conformance Control
Authors: Eoff Larry , Dalrymple E. Dwyann , Reddy B. R. , Everett Don
Published: December 2007

For many years, relative-permeability modifiers (RPM's) have received a great deal of attention from the oil- and gas-production industry. Because of the completion techniques used in many wells, it is not always practical or cost-effective to protect the hydrocarbon interval properly during a water-shutoff treatment. RPM's offer the option of bullheading a treatment without zonal isolation, which is designed to decrease water production with little or no decrease in oil or gas production.

This paper describes the laboratory development and optimization of a polymeric RPM. The resulting material can be best described as a brush polymer consisting of a polymeric back-bone grafted with polyethylene oxide (PEO). Various phases of the development will be discussed, such as the optimization of the molecular weight of the backbone polymer and the concentration of grafted PEO. Details of laboratory evaluations will also be provided, including a discussion of the use of multipressure-tap flow cells for permeability-reduction tests, the effect of polymer concentration, and the effect of saturations. These test results show that the RPM polymer should be placed with a systematic approach consisting of proper preflushes and post-flushes for optimum results. Additionally, current theories concerning how RPM's function will be discussed, along with other materials claimed to act as RPM's.
Further Investigations on Two-Phase Flow Property Modification by Polymers: Wettability Effects.
Authors: Elmkies Ph. , Bertin H. , Lasseux D. , Murray M. , Zaitoun A.
Published: December 2007

Adsorption of water-soluble polymers in porous rocks is known to reduce water permeability much more than oil permeability. This effect is often referred to as "Disproportionate Permeability Reduction" (DPR) and can be used in production well treatment to reduce the water cut. This paper deals with nonionic polyacrylamide adsorption on carbonate rocks having different wettability properties. Cores were used first in their native water-wet condition, and after a wettability modification, which was obtained by aging cores saturated with a polar crude oil at 60°C for 6 weeks. Efficiency of the treatment was attested and quantified by strong changes in the wettability index as measured using Amott tests. Drainage and imbibition cycles were performed on these carbonate samples before and after polymer treatment. Polymer adsorption and oil/water relative permeabilities were compared for both media. While the quantity of adsorbed polymer is almost the same on water-wet and on wettability-modified cores, adsorption rates, estimated from viscosity profiles of effluents, are significantly different, suggesting that the polymer slowly restores part of the water-wet character of the native core. All our results indicate that polyacrylamide adsorbs on the rock whatever being the wetting conditions. While disproportionate permeability reduction is always observed, DPR is greater in low-permeability cores.
Productivity Decline of Vertical and Horizontal Wells by Asphaltene Deposition in Petroleum Reservoirs
Authors: Wang Shaojun , Civan Faruk
Published: December 2007

Asphaltene precipitation and deposition models were established and verified by typical experimental data. These models, the porosity and permeability reduction models, and the asphaltene mass balance equation were incorporated into a three-dimensional, three-phase black-oil simulator. Two typical cases involving asphaltene deposition in petroleum reservoirs associated with vertical and horizontal wells were investigated using the simulator. During the three-year period of production, the productivity index declined more than 50 % for both the vertical and horizontal wells. The pattern of asphaltene deposition in the reservoir with a horizontal well was found to be different from that in the reservoir with a vertical well.
Advancements in Paraffin Testing Methodology
Authors: Weispfennig Klaus
Published: December 2007

Predictive methods for wax deposition within pipelines make extensive use of diffusion models to account for the amount of wax being deposited. Laboratory testing methods commonly rely on deposition results from so-called coldfinger devices to assess deposition tendencies. While these experiments are primarily done for testing chemical inhibitor performance, they serve here as the basis for a cross-reference to the often-used diffusion models. An empirical heat transfer model is developed to adequately address the heat transfer within this device. Oil analysis data in combination with thermodynamic prediction routines are used to prepare the necessary n-paraffin solubility charts. While the heat transfer and solubility data are used for a diffusion-type wax deposition, an empirical deposition model is developed to describe the deposition process. It is illustrated how practical information such as deposition tendencies can be gained from these cold finger devices. An assessment of chemical inhibitor performance is made.
Water-Based Muds and Shale Interactions
Authors: Carminati S. , Del Gaudio L. , Del Piero G. , Brignoli M.
Published: December 2007

A simple and robust indentation test has been found to be useful in evaluating shale additive performance, providing results that correlate strongly with those of the much more time-intensive high pressure hollow cylinder tests. This method has been used to evaluate shale inhibitors and many other common drilling fluids additives. Experiments have been carried out with carefully prepared samples of Pierre 2 Shale aged in different formulations. A ranking of shale strength versus mud formulation has been constructed for the following water based fluid additives: glycols (soluble and with Cloud Point), salts (organic and inorganic), gypsum, and polymers (Xanthan Gum, cationic, polyanionic cellulose). Based on the X-ray diffraction pattern analysis of aged shale samples a shape factor has been proposed to identify effective additives.
Laboratory Evaluation of Iron-Control Chemicals for High-Temperature Sour-Gas Wells
Authors: Taylor K. C. , Nasr-El-Din H. A. , Saleem J. A.
Published: December 2007

The objective of this work was to evaluate iron control chemicals used in acidizing systems in high-temperature sour-gas wells.

This work is required because iron compounds that precipitate during acidizing can reduce reservoir permeability in the critical near-wellbore area. Formation damage from fines and precipitated material can be difficult to remove in subsequent remediation treatments.

A high temperature see-through cell was used to investigate the behavior of 28 wt% HCl acid formulae provided by three different service companies. Temperatures up to 300 °F and pressures up to 500 psi were used in this work. This is the first time in the literature that these high acid concentrations have been studied at 300 °F. Previous studies in the industry are available for acid concentrations of up to 15 wt% HCl, temperatures of up to 250 °F, and pressures of 500 psi.

The following conclusions are made:

Nitrilotriacetic acid (NTA) in 28 wt% HCl at 300 °F degrades completely after 5 hours. Therefore, NTA is not effective as an iron control chemical under these conditions. At 250 °F, 77% of the initial NTA remains after 24 hours. It was estimated that the degradation rate of NTA doubles for each 14 °F increase in temperature in the range 250 to 300 °F. Service company acid formulae degrade to produce black precipitates in 28 wt% HCl at 300 °F. These materials contain significant amounts of polyaromatic hydrocarbons and chlorinated aromatics. The acid formulae of two companies oxidize iron (II) to iron (III) at 300 °F in live acids. In spent acid at 300 °F, iron (III) is reduced to iron (II) by all three acid formulae. Both reactions may lead to degradation of acid additives. The acid formula from Company C shows an increase in iron sulfide precipitation in spent acid compared to a control. The acid formulae from Companies A and B show no significant effect on iron sulfide precipitation, when compared to a control. In coreflood tests, iron sulfide precipitates immediately when acid containing dissolved iron (II) and hydrogen sulfide spends on a carbonate rock at high temperature. Iron sulfide accumulates on the injection face, not within the rock itself.

The following recommendations are made:

Reduce total iron concentration in the injected acid to the lowest practical level. Pickle tubing, mixing tanks and lines before the acid treatment. Eliminate the use of NTA at temperatures above 250 °F. Investigate other chelating chemicals and hydrogen sulfide scavengers for control of iron sulfide precipitation at temperatures above 250 °F.
Diffusion Coefficients of Demulsifiers AP Measuring by Isotopic Labeled and Liquid Scintillation Counting Technique
Authors: Jiatai Bu , Wenhai Chen , Yabin Niu
Published: December 2007

This paper will firstly introduce the method of diffusion coefficient measuring in situ. Then the presentation is to be given that the diffusion coefficients of demulsifier AP between toluene and water are measured by isotopic labeled and liquid scintillation counting technique; The affection of NaCl on the diffusion behaves of demulsifier AP211 is also discussedin this paper
Novel Scale Removers Are Developed for Dissolving Alkaline Earth Deposits
Authors: Frenier Wayne W.
Published: December 2007

Scales are minerals that form on a surface due to the saturation of the local environment with an inorganic salt. The major categories of scales are: carbonates (Ca, Mg, Fe(II)), sulfates (Ca, Ba, Sr, Ra), oxides and hydroxides (Fe(II), Fe(III), Mg), sulfides (Fe(II) and Zn) and silicates (Ca, Mg, Al and Na).

The testing and categorizing of various classes of scale removal chemicals is described in this paper. The primary deposits studied were calcite, gypsum and barium sulfate. A variety of solvents, including organic acids and chelating agents were tested. Total capacity tests as well as kinetic tests were conducted to develop improved scale removal formulations.

One result has been the development of solvent formulations based on hydroxyaminocarboxylic acid (HACA) chelating agents. The tests demonstrated that HACAs are better overall complexers and solvents than aminocarboxylic acids or carboxylic acid type chelating agents in many scale dissolution formulations. A major benefit of HACAs are their high solubility in aqueous solutions from pH values <1 to> 12. Thus, an almost infinite number of custom formulations can be constructed. Some of the formulations have dissolution capacities that are equivalent to 7.5% HCl. One of the new materials, hydroxyethyliminodiacetic acid (HEIDA) is completely biodegradable and this contributes to the "greening" of oilfield chemicals.
Iron Sulfide Scale Deposit Formation and Prevention under Anaerobic Conditions Typically Found in the Oil Field
Authors: Przybylinski John L.
Published: December 2007

Iron sulfide deposition is a significant oilfield problem that has been ignored for the most part because of the perceived difficulty in preventing its formation. Usually iron sulfide is allowed to form and the resulting deposit problem remediated by either acid treatment or mechanical cleaning. Neither option is attractive in that acid cleaning is hazardous and mechanical cleaning is expensive.

Iron sulfide is not a single entity, but can exist in numerous forms. This paper discusses the various forms of iron sulfide. It compares the solubilities of iron and other sulfides with the solubilities of other mineral scales typically found in the oilfield and shows that it should be possible to inhibit the formation of ferrous sulfides using threshold inhibitors.

The perceived difficulty of preventing the formation of iron sulfide arises primarily from the very real problems involved in studying it in the laboratory under the anaerobic conditions typically found in the oilfield. These problems and solutions to some of them are discussed. The paper presents laboratory and limited field data showing how the deposition of ferrous sulfides may be reduced significantly.
Move to Environmentally Acceptable Products: How the OSPARCOM legislation affects the Introduction of New Products
Authors: Killaars Janine , Finley Pat
Published: December 2007

The Oslo-Paris Commission (OSPARCOM) has implemented strict guidelines for the use and discharge of chemicals used by oil and oil service companies in the North Sea. The ecotoxicity tests that must be performed according to OSPARCOM guidelines, as well as the country-specific prescreening and the soon-to-be-implemented Chemical Hazard and Risk Management (CHARM) model, have a major impact on the development of new products. In the commercial development phase of oilfield chemicals not only the performance, but also the environmental properties of the product must be taken into account.

This paper describes two examples of products that were successfully replaced with more environmentally acceptable alternatives. The improvement from an environmental point of view is outlined. The following parameters will be taken into account: Why is the product being replaced?Environmental properties (bioaccumulation, biodegradation, aquatic toxicity)Prescreening results in Norway, Denmark, and UKCHARM evaluation results

Comparisons of replacement products with the original product will be given, based on the above mentioned parameters. The replacement products that have been introduced are environmentally more acceptable. Due to the fact that regulations will become stricter, oil and oil service companies will have to put increasing effort into compliance with environmental legislation.
Simultaneous Matching of Production Data and Seismic Data for Reducing Uncertainty in Production Forecasts
Authors: Guérillot D. , Pianelo L.
Published: December 2007

Matching procedures are often used in reservoir production to improve geological models. In reservoir engineering, history matching leads to update petrophysical parameters in fluid flow simulators to fit the results of the calculations with observed data. In the same line, seismic parameters are inverted to allow the numerical recovery of seismic acquisitions. But these inversion processes are made separately and are poorly constrained.

The idea of this original work is to simultaneous match both the permeability and the acoustical impedance of the reservoir for an enhancement of the resulting geological model.

Comparison of the coupled matching with the two separated conventional ones realized on a 3D case demonstrates the practical efficiency of our method.

This work is an important step in a way of data integration. It allows to use simultaneously the available hard and soft data, as the knowledge of the depositional environment, seismic, and/or dynamic information.
Decision Analysis for Integrated Reservoir Management
Authors: Evans Robin
Published: December 2007

Decision analysis (DA) is presented as

A tool for carrying out a thorough and logical evaluation of alternative strategies, A means of systematically determining the best available reservoir management strategy with the objective of maximizing the net present value of the asset and the company.

Decision analysis is a framework for conducting integrated reservoir management. It is possible to integrate reservoir engineering, environmental regulations, environmental impact assessment, geochemistry, geological studies, process design, risk analysis, QC and financial appraisals with the aim of maximising the return on investment.

The value of decision analysis is not only in helping to structure information and thinking, but also in providing a vehicle for communication between different groups and technical disciplines. A complex decision problem is decomposed into separate components, often in the form of a decision tree, on which perceptions of options, uncertainties and values can be explicitly represented. Decision analysis is an ideal tool for decision making in an environment of risk and uncertainty.

The selection of a strategy for produced water handling and disposal is presented as an example of an application of decision analysis involving the integration of a variety of disciplines.
Improved Integrated Reservoir interpretation using the Gas While Drilling (GWD) data
Authors: Kandel D. , Quagliaroli R. , Segalini G. , Barraud B.
Published: December 2007

The acquisition of gas in mud data while drilling for geological surveillance and safety is an almost universal practice. This source of data is only rarely used for formation evaluation due to the widely accepted presumption that they are unreliable and unrepresentative. Recent developments in the mud logging industry to improve gas data acquisition and analysis has led to the availability of better quality data. Within a joint ELF/ENI-Agip Division research program, a new interpretation method has been developed following the comprehensive analysis and interpretation of gas data from a wide range of wells covering different types of geological, petroleum and drilling environments.

The results, validated by correlation and comparison with other data such as logs, well tests, PVTs etc, enable us to characterise:

lithological changes, porosity variations and permeability barriers, Seal depth, thickness and efficiency, Gas diffusion or leakage, gas/oil and hydrocarbon/water contacts, vertical changes in fluid over a thick mono-layer pay zone, vertical fluid differentiation in multi-layer interval, biodegradation.

The comparison between surface gas data, PVT and geochemistry data clearly confirms the consistency between the gas show and the corresponding reservoir fluid composition.

The near real time availability, at no extra acquisition cost, of such data has led to:

the optimisation of future well operations (logging, testing, ….), a better integration of while drilling data to the well evaluation process, a significant improvement both in early formation evaluation and reservoir studies especially for the following applications where traditional log analysis often remains inconclusive: very low porosity reservoirs, thin beds, dynamic barriers and seal efficiency, low resistivity pay, light hydrocarbons.

Examples show both wellsite quicklook with simple lithological and fluid interpretations and more complex reservoir and fluid characterisation applications in varied geographical and geological contexts that demonstrate how GWD data is integrated with more standard data sets.
Case Study: Redevelopment of the Ebughu Field
Authors: Clark R. A. , Afemari A. A. , Ezeukwu T. E. , Awi H.
Published: December 2007

The Ebughu field, located offshore in the eastern Niger Delta, has produced from a thin viscous oil rim at very low rates since 1988. Production has run at 10% of platform potential. Following a change in operatorship, the field was successfully redeveloped during 1999 in less than 10 months. From a standing start, the field was reviewed, new wells were drilled and the platform facilities were filled to capacity. The field is now believed to be ten times larger than originally mapped. Key to this fast tracked success was the adoption of a streamlined redevelopment process.

Key results and conclusions are as follows:

The pooling of knowledge from outside contractors, consultancies and operators, has allowed a small integrated project team to review and redevelop a poorly performing offshore field in 10 months. Application of 3D seismic and horizontal well technology has transformed the development of a thin viscous oil rim, with both production levels and STOIIP potential being raised ten fold. Redevelopment of this sparsely explored field was significantly3accelerated through the adoption of an aggressive appraisal-development process. Seven low cost pilot wells were batch drilled up front from two slots and interpreted in real time. This allowed four horizontal development wells to be targeted and drilled in the same drilling program and a successful appraisal well completed for reservoir information. Effective selection of drilling resources reduced drilling costs substantially and resulted in horizontal wells which were among the fastest, cheapest and longest ever drilled in Nigeria. The adoption of the "all-in-one" completion concept allowed an 8,200ft well including a 2,100ft horizontal section to be drilled and completed from a new slot in 9.4 days for US$ 2.1million.
Application of Horizontal Well Technology in Colombia
Authors: Saavedra N. F. , Joshi S. D.
Published: December 2007

To date, 20 horizontal wells have been drilled in Colombia, 16 in sandstone and 4 in carbonate reservoirs. In carbonate, the economical success rate is 50% but in sandstone it is 88%.

In general, wells in Colombia are expensive. The vertical well cost varies from 2 million dollars to 11 million dollars, depending upon the reservoir depth. Horizontal well costs vary from 1.5 to 2.5 times the vertical well costs. Initially, most of the wells were completed with slotted liners. Now, new wells are completed with cemented and perforated liners to control water and gas production. The range of True Vertical Depth (TVD) is between 3000 and 16000 ft.

This paper presents three brief field histories and the lessons learned to date. In cases where production is less than expected the principal causes are: A horizontal well has commingled production from zones of high contrast in permeability, reducing considerably the producing length of a horizontal well.Production of unwanted fluid such as water and gas. With slotted liner completion, it is not only difficult to identify gas and water producing zones but it is also difficult to isolate them effectively.Geological uncertainty which results in drilling a well through a zone which is geologically different than expected.

New horizontal wells are planned as short length wells in high permeability zones and long ones in low permeability zones.

Also, re-entry wells are now used in mature reservoirs to reduce drilling costs.

The method used to analyze the well performance is discussed in the paper. To determine the producing length, gamma ray analysis, log information, production tests and/or PLTs were used. A productivity analysis using analytical equations was also conducted to define if the well was damaged or had a small producing length. Then decline curve analysis was used to forecast rate and reserves and well production histories were matched for rates and cumulative production over time. Depending upon the problem, and considering feasibility and cost effectiveness, a corrective action was designed to improve well productivity.

In summary, horizontal wells in Colombia have been successful and a large potential exists to drill many more wells.
Coiled-Tubing Drilling with Supercritical Carbon Dioxide
Authors: Kolle J. J.
Published: December 2007

High-pressure fluid jet-assisted drilling is attractive for drilling horizontal holes because of the potential for high penetration rate in hard formations using low-cost, small-diameter tools. Unfortunately, the threshold pressure for water-jet erosion of most sedimentary rocks is much higher than the pressure capacity of conventional coiled tubing. Recent experiments have demonstrated that supercritical carbon dioxide (SC-CO2) jets will cut hard shale, marble and granite at much lower pressure than water. SC-CO2 was also shown to enhance mechanical drilling rates. The use of SC-CO2 to drill ultra-short-radius lateral well completions is evaluated here. SC-CO2 is a dense, low-viscosity fluid with excellent hole cleaning capabilities. Conventional under-balanced drilling equipment can be used to control formation pressures while drilling with SC-CO2. SC-CO2 is a non-damaging fluid that should provide enhanced production from completions relative to holes drilled with water-based fluids. The use of SC-CO2 for jet assisted drilling would allow fast drilling of small-diameter, ultra-short radius laterals using low-cost, small diameter coiled tubing equipment.
Use of Networked Geosteering Software for Optimum High-Angle/Horizontal Wellbore Placement: Two U.K. North Sea Case Histories
Authors: Lott Simon J. , Dalton Christopher L. , Bonnie Jos. H. M. , Roberts Martin J. , Cooke Graham P.
Published: December 2007

This paper presents two case histories that demonstrate the effectiveness of an active geosteering approach using computer networking between rig site and operator office. A satellite link was used to update well trajectory and LWD data in StrataSteer™ geosteering software located within the operator’s asset group. This link provided the key advantage of allowing subsurface staff to become an integral part of the geosteering process.

The geosteering software enables a geological / petrophysical model to be created based on offset well log data and seismic profiles. The LWD log responses are modeled along the planned well trajectory and then compared to the actual LWD log responses (gamma, multi-depth resistivity, neutron, and density). The responses are then used to adjust the geological model and take geosteering decisions.

The amended geological situation enabled immediate and enhanced decision-making regarding adjustments to the well path in order to remain within the optimum reservoir zone. Good communication between all parties involved, both onshore and offshore, undoubtedly contributed to the success of both operations.

The two example wells, "A" and "B", present different challenges. In both cases, it was clear prior to drilling that active geosteering would be necessary. Well A was planned as a horizontal oil producer. The vertical thickness of the pay section was estimated at 13 ft, and the bed dip was expected to vary between 0 and 2 degrees in the direction of drilling. Following successful landing of the well, a total of 1300 ft of target reservoir was drilled using the geosteering software to actively guide the well path. Production rates from this well were significantly above pre-drill expectations.

The objective in Well B, a deviated sidetrack, was to drill through four reservoir zones, two on either side of a major fault. Recognition of the fault in real-time was critical due to different reservoir thickness and bed dips across the fault and significant uncertainty regarding the position of the fault. The use of geosteering software enabled the fault to be quickly recognized when it appeared — some 450 ft along hole earlier than expected. The geological model was quickly revised and the well path adjusted to optimize placement in the final two targets.