bluuebunny/crossref_metadata_2025 huggingface dataset:
Application of Decline-Curve Analysis Technique in Oil Reservoir Using A Universal Fitting Equation
Authors: Fekkane Abdelhafidh , Tiab Djebbar
Published: December 2007

The analysis of oil production data using decline curves is a modeling and forecasting technique. Actual production rate and time data are history matched to a theoretical model using specialized graphs known as type curves.

This study begins with a review of the previously developed decline curve construction and analysis methods. It consists of reproducing Arps-Fetkovich type curves and the derivative type curves for advanced decline curve analysis. A Program was developed to generate the dimensionless rate-pressure and time data necessary to construct Fetkovich type curves.

Combining the analytical solution derivative for transient flow based on numerical analysis, and the empirical solution derivative for boundary dominated flow develops the derivative type curves.

The type curves is used to identify the transient versus depletion stages and to estimate reservoir parameters and future decline paths.

Field production data are generally difficult to match with the type curve for this reason a Universal Fitting Equation is proposed as an alternative to manual type curve matching. This equation combines both Arp’s empirical equation and Fetkovich analytical solutions. It equation offer the following advantages: Fitting with the equation is more precise than type curve matching to obtain reservoir dimensionless radius reD, Arp’s exponent b, matching points q/qDd, and tDd/t.The real production data can be fitted directly by the equation without using smoothing techniques.The radial and pseudosteady state regions are determined automatically and easily from fitting.Some production data that were insufficient to be analyzed with manual type-curve matching can be interpreted with the Fitting Equation.

This procedure has been applied to some Real field data from Hassi Messaoud field cases and it has given significant results.
Cased Hole Formation Resistivity: Changing the Way We Find Oil and Gas
Authors: Bartenhagen Keith J. , Bradford Jon C. , Logan Dale
Published: December 2007

In today’s competitive market it is increasingly important to improve production and increase reserves in the most efficient way possible. One alternative is to add new wells, but this can be an expensive and time-intensive endeavor. Another alternative is adding and optimizing production from the thousands of existing wellbores already in place. To do this, the ability to detect and evaluate bypassed hydrocarbons and track fluid movement in the reservoir is vital. Current methods of through-casing saturation determination using nuclear tools are limited because of their shallow depth of investigation.

With the introduction of the CHFR* cased hole formation resistivity technology a new dimension has been added to cased hole evaluation. A deep-reading formation resistivity can now be obtained through steel casing. Although this measurement is analogous to exsisting techniques for saturation determination, it has two distinct advantages: In many cases there is a need to monitor saturation changes in a producing interval. In the past sigma-based interpretation methods were the only option. However, saturation determination in low-porosity reservoirs (<15 pu) using sigma requires a very detailed and accurate lithology description because small errors in the lithology answer have a significant effect on the saturation from sigma. Because many reservoirs in the Permian Basin combine complex lithology with low porosity, answers can be somewhat unreliable. This is often the case in shallow water-flooded carbonates, where the presence of gypsum, anhydrite and salt makes sigma measurements almost impossible to interpret.Cased hole saturation is also needed to detect bypassed pay and occasionally as the primary evaluation method. In these cases, sigma-based measurements fail because of their shallow depths of investigation. Because the zones have not been produced yet, the invading fluid (brine) still occupies the pores around the borehole. This is particularly true in the Permian Basin because no fluid control measures are used during drilling and deep invasion is normal. The CHFR tool reads deep enough to avoid this complication. In fact, it is commonly superior to openhole resistivity since it reads significantly deeper than openhole resistivity tools.

When the CHFR tool is used in conjunction with porosity and lithology tools, run either in openhole or through casing, accurate hydrocarbon saturation can be determined. This methodology can be used to find bypassed pay or to determine the depletion level of producing pay intervals. It has also been used extensively in time-lapse surveys to evaluate the sweep efficiency of secondary recovery, ensuring that no producible hydrocarbons are left behind. This paper reviews the application of this technology in several U.S. basins, including the Permian Basin and California.
Producing The Well In Artificial Lift By a Subsurface Compensated Pump: A New Production Method
Authors: Buchman Smil S.
Published: December 2007

This paper presents a new production method in which the reservoir energy spent to lift the production from perforation-depth to the dynamic liquid level is replaced by surface energy, and consequently the well daily rate and cumulative production is increased by 200 - 250 %. The method can be used in any well at any time.

The paper is based on the analysis of how the reservoir energy generated by the expansion of the reservoir fluids is used to produce the well:PROFITABLE USAGE: Moves the production through the pay zone into the well boreWASTEFUL USAGE: Sends the reservoir energy to:Overcome the liquid friction along the productionflow path.Lift the production from perforation-depth to thedynamic liquid level.

Present production practice recognizes and reduces only the reservoir energy wasted to overcome the liquid friction through the pay zone by using better and cleaner perforations, acidizing, fracturing, and other techniques. When less reservoir energy is used to overcome the frictions through the pay zone, the well performance, in both rate and cumulative production, is increased.

To date all artificial lifting methods are spending surface energy only to lift the production from the dynamic liquid level to the surface. However, the energy needed to lift the production from perforation-depth to the dynamic liquid level, the largest waste of reservoir energy, is now overlooked and has not been recognized as the most important way to significantly increase well performance. The proposed new production method substitutes the reservoir energy by surface energy in order to lift the production from perforation-depth to the dynamic liquid level. Accordingly the well performance in day rate and cumulative production is increased by 200 - 250 % compared to the actual well performance.

The quickest and easiest way to produce the well according to the new production method, is to run a subsurface compensated plunger pump assembled from the API Spec-11AX parts, and work with the same beam pump. A subsurface compensated pump, is a liquid lifting device, which can not be drawn by the well pressure.
Fracturing Fluid Evolution Plays a Major Role in Codell Refracturing Success
Authors: Shaefer Mark T. , Lytle Denise M.
Published: December 2007

Refracturing wells, completed in the Codell formation, has caused a resurrection in activity in the Wattenberg Field of the Denver-Juleseburg (D-J) Basin. HS Resources (HSR) has increased average oil and gas rates by greater than 500% by restimulating over 750 Codell wells. The evolution of applied fracturing fluid technology has played a major role in the success of the Codell refrac program.

This paper will identify and evaluate the benefits to well performance and economics gained from the evolution of fluids used in the Codell refracture program. In this effect, the fluid systems will be compared using treating pressure characteristics, production analysis, fluid properties, and rheological property evaluation via specialized testing apparatus and economic results.
A Type-Curve-Based Spreadsheet Program for History Matching and Forecasting Tight-Gas Production.
Authors: Munoz Juan D. , Chen Her-Yuan , Teufel Lawrence W.
Published: December 2007

This paper describes an Excel™ spreadsheet program for history matching and forecasting production of tight-gas wells. The program is based on a set of recently developed type-curves. This set includes pure- and near-linear flow regimes that are lacking in the original Fetkovich type-curves, but are important for tight-gas production data analysis. The program provides constrained cross-matching between rate, cumulative production, and time to obtain a unique and consistent interpretation regardless of the type of analysis. Main features of data input, cross-type-curve matching, parameter estimations, and forecasting are described using a field example from San Juan Basin (New Mexico) and a numerically simulated example. The spreadsheet program provides a simple method to quickly analyze production data when no other means is available, or when a quick-look is needed before a detailed study. The developed program is for general purposes, however, is most attractive for low-permeability, hydraulically-fractured wells because of the likely occurrence of long-transient, strongly-liner flow.
Impacts of Permeability Anisotropy and Pressure Interference on Coalbed Methane (CBM) Production
Authors: Chaianansutcharit Thotsaphon , Chen Her-Yuan , Teufel Lawrence W.
Published: December 2007

This study analyzes the impacts of permeability anisotropy and pressure interference on CBM (coalbed methane) performance with emphasis on identifying any unique feature that might allow us to diagnose permeability or flow anisotropy. Simulation results indicated that a "dual-peak" behavior in the gas rates arises if drainage boundaries are not influenced at the same time. Examples include anisotropic permeability in a square area and isotropic permeability in a rectangular area. The dual-peak behavior does not present if the drainage area is scaled according to the permeability anisotropy (the "square-root rule"). As noted in the literature, well interference has positive impact by accelerating gas production. The "dual-peak" behavior may potentially provide a methodology to diagnose permeability anisotropy and drainage shape from CBM performance. Further research, however, is needed.
Hydrogen Sulfide Removal from Sour Condensate Using Non-Regenerable Liquid Sulfide Scavengers: A Case Study
Authors: Salma T. , Briggs M. L. , Herrmann D. T. , Yelverton E. K.
Published: December 2007

Hydrogen sulfide (H2S), a corrosive and toxic gas, when present in produced fluids such as condensate, gas and water, poses serious health and operational hazards. Non-regenerable H2S scavengers have been in use for H2S removal from sour gas and condensate for over a decade. Selection of an appropriate non-regenerable chemistry is dictated by the downstream treatment processes that the gas or condensate will be subjected to after H2S removal is accomplished. Successful selection and application of non-regenerable H2S scavengers requires a thorough evaluation of operating conditions such as temperature, pressure, mixing, etc., that affect H2S removal from sour fluids. Most of the applications require on-site optimization to achieve maximum scavenging performance.

This paper presents results and observations from a field trial for sweetening a large volume of sour condensate held in a 70,000 bbl storage tank using a water-soluble triazine-based scavenger. Mode of application of the triazine-based scavenger was found to be one of the most important factors for successful reduction of H2S in liquid hydrocarbons held in large tanks. Another important factor affecting H2S scavenger performance was the presence of sulfide species other than H2S in the sour fluid. Experiences gained from the trial illustrate the importance of a systematic approach required for effective sweetening in liquid hydrocarbons.
Design and Execution of a State-of-the-Art Water Shutoff Treatment in a Powder River Basin Tensleep Producer
Authors: Giangiacomo Leo A.
Published: December 2007

This paper summarizes the literature research on water shutoff treatment technologies, distills the critical elements for designing a treatment in a naturally fractured Tensleep producer, presents the treatment design process, and shares the field operations experiences and treatment results.

The subject well is located in the Teapot Dome Field in the Naval Petroleum Reserve No. 3, Natrona County, Wyoming. The project was funded by the U.S. Department of Energy and the Rocky Mountain Oilfield Testing Center.

The literature and interview research illuminated the aspects of the treatment that are scientifically sound, as well as the areas that are in need of additional research.

The most important factor in treating wells for excessive water production is the characterization of the water production mechanism. This paper outlines some simple graphical techniques used to identify water flowing through a natural fracture system from an underlying aquifer.

Selection of treatment technology, treatment volume, concentration schedule, and quality control issues are discussed. Critical logistics and operational matters are also covered.

An unusual approach to the treatment was taken by stimulating the well with a propellant stimulation treatment prior to the water shut-off treatment. This technique is designed to improve the communication with the natural fractures in the near-wellbore area, and allow the treatment to be pumped at lower pressures with less polymer dehydration problems and more effective treatment placement. It is hoped that the improved placement will extend the life of the treatment.

The job procedure, cost estimate, schedule, and project economics are presented, and compared to the actual job execution.

The treatment had some unexpected pressure behavior during the placement. Ideas are proposed to explain the behavior, and suggestions are made to gather additional data during future treatments to verify the theories and better understand treatment design.

The treatment was performed on October 13, 2000 and three months of production data are used to judge its success. Pre-treatment production rate was 14.1 barrels of oil per day (BOPD) (2.24 m3/d) and 7,817 barrels of water per day (BWPD) (1243 m3/d). Post treatment rates after two weeks were 18 BOPD (2.9 m3/d) and 1,880 BWPD (299 m3/d). After three months, production seems to be stabilizing around 12 BOPD (1.9 m3/d) and 3,150 BWPD (496 m3/d). Problems were experienced with ESP pump sizing following the treatment.
Handling, Treatment and Transportation of Fluids Tailor-Made for Faja Crudes
Authors: Padrón Aaron , Morros Francisco
Published: December 2007

The extensive development of the Orinoco Belt has been supported by the concourse of various worldwide companies with different philosophies. Thus, Exxon-Mobil, Conoco, Phillips, Texaco, Totalfina, Veba Oel, Statoil and PDVSA are participating in the Orinoco Belt development and their participation has been determinant in the operation and design criteria for each of the particular project.

To face the challenge of developing this huge field, with more than 1,2 MMM Bls OOIP, of a crude with extreme characteristics such as 7-9°API gravity and dead crude viscosity between 20,000 and 100,000 cst, as well as the foamy oil and topography effects, it has been necessary to implement the following: Conventional Technologies, such as gas separators, electrostatic dehydration and desalter, heater treater, etc.Advanced Technologies, such as multiphase pumping and measurement.New developments jointly with the suppliers, such as high volume capacity Progressive Cavity Pumps (PCP).

This paper summarizes and compares the different technologies and methodologies utilized by various companies currently involved in the Orinoco Belt such as Petrozuata, Sincor, Ameriven and Cerro Negro, for handling, measuring, treating and transporting crude, water and gas which were tailor-made for the Orinoco Belt crude.
Predicting Permeability From Well Logs in Carbonates With a Link to Geology for Interwell Permeability Mapping
Authors: Jennings James W. , Lucia F. Jerry
Published: December 2007

A fundamental component in the construction of most reservoir performance models is an empirical relationship between permeability as measured in a limited number of cored wells and other petrophysical properties measured in well logs. This paper presents a permeability model specially designed for carbonates. The model relates permeability to interparticle porosity, makes special accommodation for separate-vug porosity, and includes a rock-fabric classification scheme with an important dual petrophysical-geological significance. Methods to estimate the separate-vug porosity from sonic logs and the rock-fabric from initial saturation are presented.

The dual petrophysical-geological significance of the rock-fabric classification is important for providing a link to geological models for use in distributing permeabilities between wells. Porosity and permeability are highly variable and difficult to predict spatially in most carbonate reservoirs, but rock-fabric changes tend to be systematically organized in a predictable manner within a sequence stratigraphic framework.
Evaluation of the Potential of High Angle Wells for the Najmah-Sargelu Reservoirs in Kuwait
Authors: Briggs Peter J. , Gaona Michael T. , Kamal Dawod S. A.
Published: December 2007

The Najmah-Sargelu reservoirs are fractured carbonates and have been penetrated by several vertical wells. Productivity from these wells depends on chance intersection with vertical fracture clusters and as a result has varied from zero to quite productive wells. The chances of intersecting major fracture clusters will be improved if high angle wells are used. This paper investigates and compares the expected performance of vertical and high angle wells based on assumptions about the density of major vertical fracture clusters also, the azimuth, length, width, and rock matrix properties. The analysis tool developed incorporates uncertainty in these parameters using the algorithm below and Monte Carlo Simulation.

Define vertical or HAW well locations. Then, for each Monte Carlo trial:

Select fracture density. 2 Select fraction of fractures in primary and secondary azimuth. Randomly map fractures in reservoir area, sampling length and width distribution for each fracture cluster location. Count intersections of fixed location high angle or vertical wells with fracture clusters. Use cluster intersection statistics to determine the number of multiple fracture clusters connected to each well. Calculate average matrix volume associated with each fracture cluster and compute matrix fracture feed. Calculate OIP and recovery for each well. Sample well costs and perform economics.

The analysis allows the comparison not only of vertical and high angle wells, but also high angle wells with different completion lengths. The method provides a quick and simple method of screening and prioritizing fractured reservoir opportunities for more-detailed analyses.
An Integrated Work-Flow Model to Characterize Unconventional Gas Resources: Part I—Geological Assessment and Petrophysical Evaluation
Authors: Newsham K. E. , Rushing J. A.
Published: December 2007

This paper presents a systematic methodology to describe and characterize unconventional natural gas reservoirs. We have modified the Petrophysical Integration Process Model (PIPM), originally developed at Amoco (Gunter, et al,1,2), for specific applications to unconventional gas systems. Our modified PIPM, which is divided into four discrete analysis stages, integrates data from multiple sources and different reservoir scales. In this paper, we describe each PIPM stage and show how petrophysics can be used as the critical link between geology and reservoir engineering. Although we illustrate the process with examples from a tight gas sand study, the modified PIPM is applicable to other unconventional gas systems. The ultimate goal of this process modeling is to build realistic three-dimensional wellbore and reservoir flow models to predict future performance and optimize field development.
Multi-Criteria Decision Making in Strategic Reservoir Planning Using the Analytic Hierarchy Process
Authors: Gerbacia William E. , Al-Shammari Hanaa
Published: December 2007

The paper describes the use of the Analytic Hierarchy Process in the strategic planning for the development of a series of reservoirs in the same field. A department of the Kuwait Oil Company is responsible for the development of these reservoirs and needed to determine the best order in which to develop these assets. In order to do this it was necessary to make judgements regarding how well any development option met a set of strategic criteria. At the individual reservoir level, it was also necessary to judge which development option best met a set of criteria for the development of specific reservoirs.

A decision hierarchy was developed that reflected the ordering of the criteria and the specific alternatives. Pair-wise comparisons of the various criteria were made in order to determine how well they satisfied the overall objective. These judgments were evaluated using a judgment matrix to determine weights for the criteria. These criteria were applied to decisions to be made at the next lower level in the hierarchy. In this way, the decisions, which were judged to best meet the overall objective, were given the highest priority. This influence cascaded down through the hierarchy to rank the development options. With this structure it was simple to substitute one overall objective for another to determine whether this would cause a change in decision policy.

The sensitivity of the decision outcome was also evaluated for its sensitivity to the range of values of the input factors. Since there were thirty-five factors to evaluate, a statistical design approach was used to evaluate factor effects. It is shown that the planning factors, planning horizon and the demand scenario used for planning purposes were significant in all cases evaluated, and highlighted the importance of testing the assumptions, criteria and objectives in a strategic planning exercise.
Corrosion Consequences of Oxygen Entry Into Sweet Oilfield Fluids
Authors: Martin Richard L.
Published: December 2007

This paper contains the results of laboratory and field tests where the corrosion system was carbon steel exposed to oilfield brines containing dissolved carbon dioxide and oxygen. Both uninhibited and inhibited systems were examined. The results are analyzed and placed in context with previously reported work dealing with related systems.

Oilfields, in general, have less gas pressure as they mature. Ingress of oxygen into well annuli, into the vapor space in tanks, and through pump packing becomes more commonplace as a result. The corrosion consequences of this condition can now be quantified and corrective action can be taken to avoid equipment replacement and production losses.

To the author's knowledge, no report of a systematic treatment of this subject exists in corrosion literature. Quantification of the effects, recognition of duration, and influence of corrosion inhibitor chemical types are among the novel contributions of this paper.

Some of the significant conclusions from the work concern the magnitude and persistency of corrosion acceleration by oxygen in sweet fluids. At common oil well temperatures, acceleration was in the order of 10 to 30 mpy per part per million of oxygen. The concentration of oxygen was not reduced preferentially from these solutions but occurred at approximately the same rate as reduction of dissolved carbon dioxide (undissociated carbonic acid) concentration. Inhibition of corrosion in CO2/O2 systems was more difficult that in CO2 alone but could be accomplished.
Large Scale Field Gathering of Oil-Water-Gas at Temperature Below the Pour Point of Crude Oil Successful
Authors: Wang Demin , Song Chengyi , Gong Xiaohong , Cheng Jiecheng , Li Qun , Wu Di
Published: December 2007

Gathering of Oil-water-gas mixtures in oil fields is usually performed on condition that the gathering temperature is above the pour point of the crude oil or above the paraffin precipitation temperature. Therefore, all the mixtures that are gathered are in a fluid state (liquid and gas). However, when gathering crude oil that has a high pour point and high paraffin precipitation temperature in cold regions, the mixture must be heated to maintain the high temperature and a large amount of energy is consumed.

Daqing Oil Field experimented on a large scale (2,300 wells) in the field the gathering of oil-gas-water at temperatures lower than the crude oil pour point, which means that the mixture is gathered simultaneously as a sticky solid (crude oil), gas and liquid (water). This paper introduces the results in the laboratory of adding a Fluid Phase Conversion Agent into the mixture and the characteristics of the mixture at different temperatures. The paper also introduces the field results of adding a Phase Conversion Agent to the gathered fluid, the problems that arose and how they were solved.

The field results of gathering produced fluids from more than 2,300 wells are very good. The gathering of produced fluids proceeded normally, energy consumption and gathering costs were lowered. At the same time, some actual data on the rheology of simultaneous gathering of a sticky solid, liquid and gas was obtained.
Emulsion Formation in a Model Choke-valve
Authors: Janssen P. H. , Noik C. , Dalmazzone C.
Published: December 2007

A problem in mature oil fields is the large amount of water produced alongside the oil. At the moment that both phases are leaving the wellbore of an oil well, tight water-in-oil emulsions can be formed due to the turbulence in the choke-valve at the wellhead. This flow process was simulated in the laboratory, by pumping crude oil-brine mixtures through a model choke-valve represented by a calibrated orifice. The parameters varied were the water-cut, the production flow rate and the orifice dimensions. The water-in-oil emulsion droplets were encapsulated immediately after formation and the emulsion characteristics, i.e. droplet-size distributions and water fraction were determined by optical microscopy and DSC.

The results of the experiments revealed that water-in-oil emulsions could be formed in the choke-valve if a certain critical value of the average energy dissipation rate was exceeded. This critical value depends on the type of crude oil and on the oil-water ratio. The diameter of the emulsion droplets found in the experiments could be explained in the framework of inertial and viscous break-up theories.

In experiments with a crude oil with little asphaltenes the droplet diameters were in the order of the Kolmogorov length scale and the average diameter Dav of the emulsion droplets decreased with increasing energy dissipation rate ε following a power-law relation: Dav∝ ε n. The value of the exponent n was found to be −0.3 and −0.1 at a watercut of 30 vol.% and 50 vol.% respectively. In experiments with an asphaltenic crude oil, the final droplet diameter was determined by viscous forces, probably due to relaminarising flow conditions.

This paper gives new information with respect to the characteristics of brine-in-crude-oil emulsions being formed in a model choke-valve and can be used to obtain insight in the emulsion formation problematic at the wellhead of an oil well. Additionally, the paper provides data on the size of droplets formed in turbulent and laminar flow at high dispersed-phase fraction.
Multiphase Flow Metering: Current Trends and Future Developments
Authors: Falcone G. , Hewitt G. F. , Alimonti C. , Harrison B.
Published: December 2007

Over the last decade the development, evaluation and use of MFM systems has been a major focus for the Oil & Gas industry worldwide. So far, many alternative metering systems have been developed, but none of them can be referred to as generally applicable or universally accurate. Both established and novel technologies suitable to measure the flow rates of gas, oil and water in a three-phase flow are reviewed and assessed within this framework. Those technologies already implemented in the various commercial meters are then evaluated in terms of operational and economical advantages or shortcomings from an operator point of view. The lessons learned about the practical reliability, accuracy and use of the available technology are discussed. As operators now realise, incorporation of MFM's is an essential step in exploiting marginal fields. A new approach to flow assurance, deep water developments, downhole/seabed separation systems and wet gas fields is foreseen. The paper suggests where the research to develop the next generation of MFM devices will be focused in order to meet the as yet unsolved problems.
Optimization of High-Gas
Authors: Agar Jo
Published: December 2007

This paper addresses the inherent difficulties associated with the proper optimization of High-Gas production. The MultiPhase Flow Meter (MPFM) described allows the in-line measurement of all three phases (oil, water and gas) simultaneously without separation of the production. The paper first defines the inherent difficulties associated with the accurate measurement oil, water and gas using conventional 2 & 3 phase separators. Defines problems associated with MultiPhase flow and its proper measurement. Next, the paper describes the problems associated with Gas-Lift production and its accurate measurement and optimization of the process.

This paper then describes the Multi-Phase technology: its uses and benefits. The Agar Multi-Phase Flow Meter measurement technique is described as well as, solutions to High-Gas multiphase measurement. Finally, the paper shows several multiphase applications and field trial results of those applications.
An Evaluation of Post-Waterflood Depressurisation of the South Brae Field, North Sea
Authors: Drummond A. , Fishlock T. , Naylor P. , Rothkopf B.
Published: December 2007

Depressurisation of waterflooded reservoirs can economically increase recovery and extend the life of mature fields. The process is underway in the Brent Field in the North Sea [1] and is under evaluation in several others [2]. Most of the previous published studies on depressurisation have focused on the critical gas saturation as the crucial factor in determining the recovery potential [3,4]. Recent experiments using reservoir condition, three-phase in-situ saturation measurements have enabled critical gas saturations and gas relative permeabilities to be determined during depressurisation [5]. This work has shown conclusively that conventional external gas drive experiments do not represent the depressurisation process and that actual gas relative permeabilities can be several orders of magnitude lower than conventional data.

This paper describes the modelling of results from an experimental coreflood, and demonstrates the effect of using the resulting relative permeability curves in a full-field simulation of depressurisation in the South Brae field. The results indicate that less hydrocarbons are produced then predicted in earlier field assessments and emphasizes the need for representative experimental measurements when making field development plans.
Application of Thermophilic Microbes In Waxy Oil Reservoirs at Elevated Temperature
Authors: Feng Qingxian , Zhou Jiaxi , Ni Fangtian , Chen Zhiyu , Liu Rulin
Published: December 2007

For the last decade, some specifically selected microbes have been successfully used to improve oil recovery in some waxy or heavy oil reservoirs. The main feature of this new technology is that the applied microbes can degradate heavy oil components to improve oil properties, for example, reduction in oil viscosity or cloud pour point. However, successful application of microbial technology in high temperature reservoirs has been remaining a challenge due to quick disactivate of microbes at elevated temperature. In this work, we present the result of application of self-incubated thermophilic microorganisms that are growing at a reservoir temperature of 73°C.This microbes can self-colony and quickly grow up at the reservoir conditions. The analysis of the crude oil on samples before and after treated with microorganisms showed that (1) oil viscosity decreased by 34%, (2) pour point decreased 3°C, (3) the weigh of heavy oil components decreased significantly, and (4) the interfacial tension between oil and formation water decreased about 31%. In addition, the pH value of the crude oil samples decreased from 7.3 to 5.5. The results from coreflooding tests showed that the oil recovery could be improved by 6.6%(OOIP) by injection the microbes. We also performed a‘ huff and puff pilot test in a production well that having 91% of water cut before the test. The results showed that after the well was stimulated with the microbes, the oil production rate increased from 20 to 40 barrels per day, and the water cut decreased from 91% to 87.8%. The effect of the stimulation with the microbes continued more than 6 months and the total oil incremental was than 2400 barrels.
Deployment of Multiphase Pumps on a North Sea Field
Authors: Leporcher Emile , Delaytermoz Alain , Renault Jean-François , Gerbier Alain , Burger Olivier
Published: December 2007

During the past years, the Oil and Gas industry has invested a lot of resources in the development of the multiphase technology (flow modelling, multiphase production equipment, fluid-related effects). The POSEIDON programme aimed at developing multiphase pumping based on the rotodynamic helico-axial design. This technology has been qualified with two tests on onshore fields. After an extensive comparison with conventional alternatives involving separation, compression, pumping, additional pipeline, it has been decided to install a multiphase boosting station on the offshore DUNBAR field in the North Sea. This paper will present a summary of the qualification tests, the Dunbar field case, the comparison between several export alternatives, the reasons for the selection, the export system over 22 km, the multiphase boosting station (two 4.5MW units) and installation related issues. Field experience after more than a year of operation will be discussed.
Multiphase Pumps for 250,000 bbl/D Field Development
Authors: Pershukov V. A. , de Salis J. , Cordner M.
Published: December 2007

The production from an entire oil field, or a substantial field area can be achieved by using multiphase pumps (MPP), either on their own or in conjunction with some well activation techniques (electro submersible pumps, gas lift, etc). MPP are applied for oil fields with a GOR generally in the range of 100 to 1000 scf/bbl, extending sometimes to higher values.

It can be seen from this paper that MPPs can realistically be considered to represent a viable and proven solution for oil field developments up to about 250,000 bopd. This is due to the development of higher capacity helico-axial pumps which are now capable of handling total volumetric (actual flow at pump inlet: oil, gas and water) capacities in excess of 500,000 bpd (3,300 m3/h).

The use of MPP is especially advantageous for remote fields in inhospitable environments where unmanned facilities are preferred.

The pump is of the barrel casing design with an axially split inner casing, incorporating conventional mechanical seals and bearings. A pressurised seal system (similar to a standard Plan 53 system) prevents gas leakage or solid particles contaminating the bearing area and ensures that a liquid film is always present at the seal faces even when the pump is operating under dry running conditions. An overpressure of approximately 5-10 bar is maintained between the seal fluid circuit and the product side of the mechanical seal.

The inner casing and hydraulic components is generally supplied as a cartridge or pull-out block for A case is described where four high capacity and high power (up to 8,000 HP or 6,000 kW) helico-axial multiphase pumps have been selected to overcome a pipeline capacity restraint at the Priobskoye oilfield in Siberia. This field is operated by JSC Nefteyugansk, part of Yukos.
Application of Wavelet Transform to Analysis of Pressure Transient Data
Authors: Soliman M. Y. , Ansah J. , Stephenson S. , Mandal B.
Published: December 2007

Although the mathematical concept of "wavelet transform" was developed in the early part of the 20th century, it did not receive practical application until the 80's. Wavelet Transform is now used in a wide variety of applications in the areas of medicine, biology, data compression, etc. A significant benefit provided by Wavelet Transform is its capability to provide two functions:

smoothing of the basic signal, and retention or even enhancement of the details.

In data analysis, these characteristics allow the user to quickly recognize hidden signals. In well testing, these capabilities would enhance signals that can be masked by other events or by the data frequency itself. Since the derivative techniques currently used in well testing tend to smooth data and conceal certain events, the use of the wavelet transform to analyze the raw data could prove to be very valuable as a major step in enhancing the techniques of modern analysis of data.

This paper will very briefly review application of the wavelet transform methodology to data analysis in general and will show why its application to well testing data in particular is important. It will also provide guidelines for application of this technology to well testing.

Several field examples are provided to demonstrate the application of the wavelet transform to well testing and how the qualitative and quantitative use of the method determines wellbore anomalies, boundary effects, and other well testing phenomena.
Permanent Downhole Monitoring For Extreme Temperature and Pressure Environments
Authors: El Chiriti Kamal , Moffatt Terrence G. , Bussiere Colin
Published: December 2007

This paper directly addresses a field proven reliable solution for permanent monitoring in high temperature and high-pressure (HT/HP) oil and gas well environments. The petroleum industry has struggled with a solution for monitoring in these environments for years and is continually held back by the limitations of electronics at elevated temperatures.

The development of cutting edge surface electronics has enabled a remote sensor to be queried and the output frequency signal to be interpreted from several miles away. What makes this unique is that electronics are not required downhole. Low-level frequency signals are extracted directly from the sensor via a cable and are directly related to measured parameters. Modern digital signal processing techniques are used to eliminate noise and measure the frequencies to a very high degree of accuracy and resolution. The millivolt level signals, which were once unidentifiable, can now produce pressure and temperature measurements with resolutions suitable for reservoir analysis.

The elimination of the downhole electronics has resulted in the ability to operate many years at temperatures well above the current limitations of electronics. In addition to high temperature operation the elimination of downhole electronics has improved the reliability of permanent monitoring substantially. This increase in reliability is demonstrated from PDVSA’s use of the technology in the Cueta Field located in the southern region of Venezuela’s, Lake Maracaibo. One hundred percent (100%) of the sensors are operational, some of which were installed over four years ago. These results are quite favorable when compared with industry published reliability statistics of less than 55% for electronic technologies at much lower temperatures.

This paper will focus on PDVSA’s experiences in their HT/HP field in South Lake Maracaibo, compared with two recent studies performed on electronic based permanent downhole monitoring (PDM) systems.
Optimizing Miscible Injectant (MI) Composition for Gas Injection Projects
Authors: Lee Sheng-Tai , Moulds Tim P. , Narayanan Ram , Youngren Gary , Lin C. Y. , Wang Yun
Published: December 2007

Many gas injection projects can flexibly design injectant gas compositions through sources of gas and enriching fluids. In such instances, optimization of the injectant composition for project efficiency becomes important and necessary. Based on experiences from BP gas injection projects, we present a procedure to optimize miscible injectant (MI) compositions for field projects. This procedure emphasizes an integrated interpretation and screening from fluid PVT, facility processes, prediction of minimum miscibility conditions to 1-D and field scale compositional model results.

To demonstrate the factors that affect design of an optimal MI, we presented two field processes, which have contrasting mass-transfer mechanisms: one a vaporizing-dominated mechanism and the other condensing-vaporizing.

For a vaporizing-dominated displacement process, slim-tube MMP is not sensitive to MI compositions. However, different MI compositions, having the same MMP (minimum miscibility pressure), do not necessarily have the same field-scale recovery efficiency. Analysis and understanding of the role of each MI component in the slim-tube mass transfer process gives important insight to optimize the MI composition.

Enriching MI above the slim-tube MME (minimum miscibility enrichment) or MMP brings about additional EOR oil in a field process. The key mechanism for the above to occur is through further reduction of residual oil in the MI swept reservoir portions. The additional oil recovery is significant; yet the benefit must be evaluated with respect to MI supply and its utilization.

MI compositions can affect surface oil rate through different mass-transfer mechanisms occurring at facility separations. Such an effect is particularly notable for volatile and light oil systems.

The optimal MI must be assessed in terms of incremental EOR oil recovery, net MI efficiency and MI cost. Considerations from field processes, e.g. facility constraints and effects of reservoir processes, may therefore alter the optimal MI derived from 1-D slim-tube processes.
Numerical Modelling and Parametric Analysis for Designing Propellant Gas Fracturing
Authors: Yang David W. , Risnes Rasmus
Published: December 2007

This paper presents a numerical modelling of propellant gas fracturing processes, which may be used as a quantitative tool for controlling and optimizing the pressure pulses generated by propellant combustion under the down-hole conditions. The model consists of propellant combustion, well fluid compression and movement, fluid drainage through perforations, fracture extention and flow in fractures. By using a proper algorithm, the pressure profile is calculated step by step. The paper also derives the formulae for estimating the productivity increase achieved by multiple fractures. The models have been verified by comparing with lab experiment and field measurements. Besides, the paper also discusses the method of estimating the productivity increase made by the propellant gas fracturing and the main factors of influence.

Based on the numerical model, the paper also discusses the method for designing propellant gas fracturing, including a parametric sensitivity study of propellant charge, well completion, perforation and formation properties, etc.
Successful Hydrajet Acid Squeeze and Multifracture Acid Treatments in Horizontal Open Holes Using Dynamic Diversion Process and Downhole Mixing
Authors: Rees M. J. , Khallad A. , Cheng A. , Rispler K. A. , Surjaatmadja J. B. , McDaniel B. W.
Published: December 2007

Effective stimulation of wells with long, openhole horizontal completions is generally considered a difficult task, especially in low-permeability carbonate reservoirs that require deep penetration with live acid. Because the creation of multiple effective fractures, the opening (etching) of existing fractures, or the creation of extensive wormholes is generally desired, this task becomes even more difficult, time-consuming, and expensive if conventional acidizing processes are used. If the live acid is not channeled properly, it will be spent rapidly at unwanted locations, often greatly enlarging the fluid-entry point. Under such circumstances, creating etched fractures or wormholes of any significant lengths can be nearly impossible.

A relatively new hydrajet fracturing process can be used to solve this problem. This process can be used in two ways: (1) dynamic fluid energy is used to divert flow into a specific fracture entry point to initiate a fracture at the intended location with live acid directed into this fracture plane, (2) high-pressure downhole mixing is used to create foam for high-intensity acid squeezes. This technique typically uses two independent fluid streams, one in the treating string and another in the annulus. The two fluids (if dissimilar) are mixed downhole at a tremendously high energy to form a homogenous mixture.

This paper discusses and compares the results of conventional acid treatments with various styles of hydrajet fracture-acidizing treatments performed in several openhole horizontal wells within two different areas of the same formation. The novel use of the downhole mixing feature is also discussed.
Temperature Effect on NMR Surface Relaxation
Authors: Godefroy S. , Fleury M. , Deflandre F. , Korb J.-P.
Published: December 2007

We present NMR relaxation experiments of water and oil confined in a series of calibrated porous media and natural rocks of different wettability, at various temperatures and magnetic fields. The longitudinal 1/T1 and transverse 1/T2 relaxation rates are interpreted with an original theoretical model which shows that the solid-liquid interactions occurring at the grain surface are responsible for the temperature dependence of the relaxation rates. For instance, 1/T1 and 1/T2 measured on water saturated samples of silica surfaces present an anomalous temperature behavior, contrary to the case of water in porous media with calcium carbonate surfaces. The relaxation rates of oil saturated porous media present always a normal temperature behavior for every surface. The temperature effect is not negligible for high reservoir temperature and should be taken into account or tested when calibrating log data using experiments performed at laboratory temperature.