bluuebunny/crossref_metadata_2025 huggingface dataset:
A Three-Phase Centrifuge to Minimize Waste from Production Tank Bottoms and Sludges: An Economic Analysis
Authors: Polston C. E. , Bretz R. E. , Parkinson W. J. , Graham A. L. , Steele R. D.
Published: December 2007

The performance of a three-phase centrifuge process in separating tank bottoms into salable oil, brine and solids was scaled using the sigma method. The profitability was analyzed for a range of processed volumes for three business scenarios: producer owned, service company and a disposal facility. Centrifuge processes operated at full capacity in these situations may be very profitable investments but any investment decision should be heavily influenced by the annual volume to be processed, the quality of the feed and the price received for separated oil.
Evaluation of A Bacterial Bioluminescence Bioassay as A Predictive Surrogate for Mysid Chronic Estimator Tests with Produced Water
Authors: Korenaga G. L. , Stine E. R. , Henry L. R. , Grimsley J. R. , Daniel D. L.
Published: December 2007

Toxicity limits are appearing more frequently in permits for produced water discharges. A bioluminescent bacteria bioassay has been proposed as a screening tool to predict toxicity in higher organisms, which are more expensive and require longer testing times. Before such a surrogate screen can be used, a correlation must be demonstrated between toxicity in the surrogate and the species of interest.

This paper describes tests comparing produced water toxicity in the biolumnescent bacteria test and in the mysid shrimp chronic estimator test, which is frequently required in Gulf of Mexico discharge permits. Under these test conditions, the bacteria test was not adequately predictive of produced water chronic toxicity to the mysid shrimp.
Implementation and Operation of an Active Permeable-Barrier Trench System for the Containment of Groundwater Contamination
Authors: Ratliff M.
Published: December 2007

This paper is a case study of the implementation and operation of an active permeable barrier-trench system beneath an oilfield service facility in eastern New Mexico. The system was designed to prevent the migration of petroleum hydrocarbon contaminants into the groundwater. Gasoline-range contaminants were discovered during the removal of underground fuel storage tanks at the site.

The active permeable barrier trench system was installed in 1992 and consists of two trenches, which are 128 and 132 ft long and approximately 15 ft deep. Trenches extend approximately 3 ft below the surface of the water table and were installed in three phases. Each trench was lined with a water-permeable geotextile fabric barrier, which was used to keep silt from permeating into the trench, but still allowed water to freely flow through the fabric. Each trench was then filled with 8 vertical feet of 2-in. gravel to increase porosity and permeability within the furrow. The remaining 6 ft of trench was filled with soil and the entire area was capped with asphalt.

Each trench was fitted with an air transmission system, at a depth of 14 ft below grade, to bubble air into the passing groundwater. Air was supplied by a blower at the surface to strip volatile contaminants from the water column and increase the dissolved oxygen content of the groundwater to promote microbial activity. Nutrient feed pipes were set in the trenches at a depth of 12 ft below grade. The feed pipes were used to inject nutrients into the groundwater to promote microbial growth and increase hydrocarbon degradation. Vapor extraction lines were installed at a depth of 8 ft below grade to remove any volatilized hydrocarbons. The vapor extraction system was connected to a passive ventilation system at the surface. The system has been in operation for approximately 2 years with good results.
Geological Model Of The Jurassic Section In The State Of Kuwait
Authors: Yousif Samir , Nouman Ghalib
Published: December 2007

Samir Yousif and Ghalib Nouman

Until the end of the seventies, the knowledge of the Jurassic Geology in the State of Kuwait was very limited, since only one deep well was drilled and bottomed in the Triassic sediments. Few scattered wells partially penetrated the Jurassic sequence.

During the eighties, appreciable number of wells were drilled through the Jurassic, and added a remarkable volume of information. Consequently it was necessary to analyse the new data, in order to try to construct a Geological model for the Jurassic in the State of Kuwait.

This paper includes a number of isopach maps explaining the Jurassic depositional basin which also helps in trying to explain the Jurassic basin in the Arabian Gulf basin. Structural evolution of the Jurassic sequence indicated an inversion of relief when compared with the Cretaceous sequence. In fact, the main Cretaceous arches were sites of sedimentation troughs during the Jurassic period.

This fact marks a revolution in the concepts for the Jurassic oil exploration. One of the very effective methods of the definition of the Jurassic structures is the isopaching of the Gotnia Formation. Najmah, Sargelu and Marrat Formations include the main Jurassic reservoirs which were detected as a result of the exploration activities during the eighties.

Selective stratigraphic and structural cross sections have been prepared to demonstrate and explain the nature of the Jurassic sediments.

Introduction

Since the discovery of oil in the State of Kuwait up to 1975, all oil discoveries were related to Cretaceous and Tertiary reservoirs. Only three wells were drilled to test oil in the Jurassic Formations in Minagish, Sabriyah and Burgan areas. The results of testing these wells were negative.

After nationalization of the oil industry in Kuwait, a number of deep test wells had been drilled and oil was discovered in two reservoirs within the Jurassic section. Consequently, a development plan was set to develop these reservoirs in Minagish, Magwa, Burgan, Umm-Gudair, Abdulyiah and Dharif areas.

This study deals with the regional geology of the Jurassic section in the State of Kuwait, using relevant data from some selective well, which represent the geographical distribution within the main Kuwait area.

P. 231
The Use of the Rima Full Field Simulator as a Field Planning Tool
Authors: Meyer Heiko , Brouwer Gerrit , van Rossem Steven
Published: December 2007

Heiko Meyer,* Gerrit Brouwer,* Steven van Rossem

A full field simulation model is being used to plan future development activities in the Rima field. A development strategy has been defined for the field using this powerful tool as long term planning tool. Future development of the field will be by short horizonta/sub-horizontal infill and flank wells, A second version of this tool is used to optimize individual wells within the framework given by the long-term planning tool, The procedure to optimize new wells is described. Since future development activities will be close to existing wells, the quantification of accelerated production is crucial in the evaluation. Results show that–local kv/kh-ratio,–dip of top reservoir and–completion lengths of existing wells have the biggest impact on optimized horizontal well lengths.

An example of the Rima West flank development is given. Based on simulation results the original field development plan has been changed, leading to development wells with:–reduced drilling costs,–higher Ultimate Recovery (UR) per well and, therefore,–a more cost-effective field development.

Introduction

The Rima field has a STOIIP of 161 million m3. It is producing under a strong bottom water drive from the underlying Haima aquifer with a thickness of several hundred meters. It is expected to provide sufficient pressure support throughout the field's production lifetime.

Although 60% of the field's UR (30% of STOIIP) has been produced already, it is still one of the biggest oil producing fields in Oman with an average oil production of 14,000 m3/d at a 70% water cut from 83 producing wells. Twenty of those wells were drilled as horizontal producers mainly in the flanks of the field and in some crestal areas. 9 of these wells have been drilled in locations with nearby vertical producers. For these wells the exact positioning is crucial to their success. 90% of the remaining 70 well locations are in similar 'tight locations'.

GEOLOGICAL SETTING

The Rima field is located towards the Northern end of the Eastern flank of the South Oman Salt Basin in the concession area of Petroleum Development Oman (fig. 1, see also fig.1 of SPE 29812).

P. 211
The Application Experience of Electrical Submersible Pump (ESP) in Offshore Oilfields, Bohai Bay, China
Authors: Li Kuiyuan
Published: December 2007

Li Kuiyuan

The electrical submersible pump (ESP) was introduced for producing oil in Bohai Bay oilfields of China in wells and they are mainly used in Chengbei Oilfield, SZ36 - 1 Oilfield and BZ428 - West Oilfield, etc. Since then, some experiences have been accumulated. In this paper, ESP well completion, matched running parameters with the productivity of the well, performance diagnosis, extending the running life of ESP unit and preparation of the standby ESP units are discussed.

Introduction

There are six gas & oilfields which have been developed in Bohai Bay area, China. Among which Chengbei Oilfield, SZ36 – 1 Oilfield, BZ428 -West Oilfield have entered the stage of artificial lift development. Widely used technology of artificial lift has become the major technical means for increasing and stabilizing the production. There are mainly three ways of artificial lift applied in offshore oilfields. Namely, they are electrical submersible pump (ESP), jet pump and progressive cavity pump (pcp). Of which ESP is the most widely used and makes up more than 70% of the total artificial lift wells.

Since 1986, the ESP was introduced in Bohai offshore oilfields, good development results and economic benefits have been achieved. And a complete series of technology, such as, unit quality inspection, the design and selection of downhole pump and well, ESP workover, performance diagnosis, pressure surveys of ESP well, downhole safety control production management and repairing of ESP unit, etc. have taken shape. For the time being, ESP wells make up more than 40.7% of the total production wells in Bohai offshore oilfields. The service life of ESP unit prolongs to 556 days comparing with initial 100 days. The longest service life has reached more than 1000 days.

P. 627
Completion Damage and Analysis of Related Factors of the Carboniferous Gas Reservoirs in the East Sichuan Basin
Authors: Chen Liping , Dong Mingsu , Ran Hong , Chen Jun
Published: December 2007

Chen Liping, Dong Mingsu, Ran Hong, Chen Jun

The analysis methods of completion damage of gas wells are presented in this paper by making use of transient testing and gas productivity index. we studied the impact of percolation capability, formation pressure, pressure coefficient, over-balanced pressure, and soak time on the completion damage. Meanwhile, we also researched completion damage of different reservoirs with high, medium or low permeability and gas deliverability.

Introduction

Petroleum geologists, drilling engineers and reservoir engineers all over the world have paid a lot of attention to reservoir protection. During the 7th five-year program in our country, drilling technology in protecting reservoir became key national project. In the process of studying the subject "drilling and completing technology in protecting gas well of carbonate reservoirs, Sichuan" sponsored by SPA*, transient testing technology was applied to analyze gas well impairment. That is, we succeeded in using "GDT" well test software to study and evaluate formation damage, and quantitatively forecast acidizing effectiveness.

However, it is difficult to obtain the steady data of pressure buildup after completion, owing to engineering, economic and other reasons. So it is necessary to develop new approaches to research and evaluate formation damage.

Based on the above situation, according to the test data after completion and treatment, we also succeeded in calculating and evaluating formation damage by making use of gas productivity index.

FEATURES OF THE UPPER CARBONIFEROUS GAS RESERVOIRS

The Upper carboniferous gas reservoirs in the Huanglong Formation (C2hl) are the major production formation in the East Sichuan, and even Sichuan. The discovered reserves account for 75 percent in East Sichuan, and 40 percent of Sichuan. Their major geologic features are as follows:

Geologic features

The Huanglong Formation overlapped on the mid-Silurian, and was eroded on the top Its depositional environment was limited sea, shoal evaporite sea platform algal flat facies. Reservoirs are exposed shoal tidal that algal dolomite and brecciated dolomite. The effective thickness is from 10.0m to 15.0, average porosity from 0.04 to 0.07, matrix permeability less than 1.0x10-3 m2. Voids are the main reservoir space, and structure fissures are the chief permeable channels. Zones full of fissures are of high H*phi values, which have substantial gas delivery capabilities. C2hl reservoirs are defined as fissure-void ones. Formation pressures being non-abnormal, fringe water being inactive, C2hl reservoirs can be assumed as isochoric ones.

P. 567
Utilizing Risk Tolerance to Optimize Working Interest
Authors: MacKay James A.
Published: December 2007

This Paper discusses a personal computer (PC) model that uses utility theory to calculate the Risk Adjusted Value (RAV) by combining the components of the Expected Value (EV) calculation with an assessment of the decision maker's Risk Tolerance (RT). The RT can be calculated from prior working interest decisions or approximated using company average RT. The RAV is always equal to or less than the EV for risk averse corporations. The RAV for risky ventures may be higher at less than 100% working interest (Wl), indicating the optimum Wl is less than 100%.

The distributions of RAV's for a venture or portfolio of ventures are calculated by varying the Wl at discrete intervals and recalculating the RAV or using the Solver (linear program add in) included with most spreadsheet software. The Solver can be further constrained to model a limited capital budget and then used as a portfolio optimizer. Uncertainty in any of the parameters can be accommodated using a Monte Carlo add in.
The Economic Impact of Strategic Risk on Petroleum Ventures: Examples from West Africa
Authors: Ethetton L. K. , Brumbaugh W. D.
Published: December 2007

Strategic risks attend any and all business ventures. They arise from the nature of the particular business being pursued and the environment in which that business is being conducted. In the petroleum industry, considerable attention is devoted to quantifying technical risks, i.e., the risk of finding and producing hydrocarbons. However, strategic risks often impact economic viability more than technical risks. Accordingly, strategic risk analysis is critical to realistically evaluating petroleum ventures in today's turbulent business environment. While difficult to assess and quantify, strategic risks must be accorded equal status with technical risks. Competitor activity, contract terms, environmental sensitivity, political stability and market forces are typical strategic risks.

A strategic risk system correlates a company's capabilities with the quality of possible ventures. Internal strengths and weaknesses are thus matched against external opportunities and threats. This is known in the business literature as a SWOT analysis.

The degree of strategic risk is then proportional to the mismatch between the SWOT elements. Such a mismatch was not recognized during exploration of the West Africa Aptian Salt Basins play in the 1980s. Angola, Congo and Gabon all contain examples where failure to consider strategic risk ultimately resulted in "Gambler's Ruin".
Evidence and Results of Present Value Maximization for Oil and Gas Development Projects
Authors: Lohrenz J. , Bailey A. J.
Published: December 2007

In the business of developing oil and gas production, myriads of engineering decisions must be made all seeking to accrue net economic value, the more so the better. Those aggregated decisions and that goal ultimately lead to the expenditure of a development cost, ℘, to attain a peak production rate, q, from a recoverable reserve, Q. The hypothesis is that ℘, Q, and q should, therefore, reflect present value maximization. Here we characterize and find evidence of such optimal decision-making. In addition, empirical correlations amongst ℘, Q, and q show oil/gas development project economics of scale.
Ranking Exploration Opportunities - Some New Approaches
Authors: Moore C. R. K. , Tucker J. W.
Published: December 2007

Some new approaches to ranking exploration ventures are suggested. Risk capacity, reflecting the break-even odds of failure for any venture, provides a useful tool. The amount by which the perceived risk (chance factor) exceeds the inverse of risk capacity is a good measure of the quality of a venture. We define this dimensionless fraction Surplus Risk Factor (SRF) or, informally, Comfort. Expected value may be restated as the product of SRF and the present value of a discovery. Plotted against each other, these provide a useful basis for a value order plot.

Two other useful yardsticks are Exploration Cost Efficiency, the expected present value generated by a dollar of discounted exploration expenditure, and Predicted Finding Cost, based on the risk-weighted reserves.
Rationalizing Assets Through Trades (Win - Win or an Impossible Dream?)
Authors: Hickman T. Scott , Seanard Keith C.
Published: December 2007

In view of the asset concentration strategy being pursued in the US by major oil companies, trading producing interests appears to be an ideal approach. Interest in trading is at an all time high. Most easy trades have been done. New trade proposals are more complex and consequently are harder to accomplish. A major barrier to trades is the traditional competitive mind set of management. Trades will increase as attitudes evolve.
A Problem With Experts
Authors: Capen Edgar C.
Published: December 2007

In this litigation society, more and more professionals in the oil business may find themselves in court, either as a party to a lawsuit or as an expert witness empowered by the court to help clarify issues. Unfortunately, some of those who call themselves experts don't even come close. At least part of the problem comes from people with petroleum related degrees who also feel compelled to claim expertise in economics and probabilistic analysis. ’Tain't necessarily so. Thus in the courtroom we see hired guns who will come up with whatever principles their clients want to see espoused.
Production Effects of Fluid Loss in Fracturing High-Permeability Formations
Authors: Elbel J. L. , Navarrete R. C. , Poe B. D.
Published: December 2007

When fracturing zones having high permeability there is concern of damage to the matrix due to deeply penetrating fluid leakoff along the fracture and/or due to materials in the fluid that minimize the amount of leakoff. Materials used to minimize leakoff also have the potential to damage the proppant pack conductivity.

Previous tests have shown that high shear rates at the tip of the fracture may prevent the formation of external filter cakes, increasing the magnitude of spurt losses in highly permeable formations. This paper provides laboratory data on materials used to control spurt loss of linear gels [HEC], viscoelastic surfactant fluid and crosslinked borate-guars in formations having up to 500 md permeability. The depth of penetration into the matrix and magnitude of the permeability reduction to the matrix and proppant conductivity is shown.

This data is then used in a finite fracture conductivity production simulator that includes simulation of fracture face damage. Simulations are made for various fluid-loss additives controlling leakoff with different fracturing fluids over a range of formation permeabilities as well as other reservoir conditions and production modes. The simulations show the production effects of limiting the fluid loss penetration at the expense of permeability reduction in the formation and the propped fracture.
HF Acidizing Returns Analyses Provide Understanding of HF Reactions
Authors: Shuchart Chris E.
Published: December 2007

Numerous sets of well returns after HF acidizing treatments were analyzed to better understand the chemistry involved in HF acidizing. This understanding has led to more effective and efficient fluid designs. Returned samples were analyzed with various analytical techniques, including X-ray diffraction, inductively coupled plasma (ICP), and 19F nuclear magnetic resonance (NMR) spectroscopy. The combination of ICP and l9F NMR determined fluoride distribution on silicon and aluminum in the samples and the extent of HF fluid reactions.

The bottomhole static temperature (BHST) of the treated formation dominates the HF fluids’ extent of reaction in sandstone reservoirs. Analyses showed significant amounts of silicon (as silicon fluoride complexes) in returns from low-temperature formations (75°F), indicating that the secondary reaction did not go to completion. At 135°F, small amounts of silicon fluorides were present in the return samples, depending on the residence time of the fluid in the formation. At higher temperatures (150 to 200°F), the Si content of the samples was low, and no silicon fluorides returned from the wells. The overall F/Al ratios in the return samples ranged from 0.5 to 1.6, depending on the BHST, concentration of HF, concentration of HCl in the HF fluid, and contact time. Along with a better understanding of HF chemistry, the analyses presented numerous problems and concerns during the treatments, such as brine incompatibilities, complete consumption of the acid through the HF reactions, and reactions with carbonates. In most cases, these problems can easily be avoided in subsequent treatments. Close analysis of HF acidizing returns indicate that improved fluid designs can provide more effective and efficient stimulation treatments.
Laboratory Acid Effectiveness Evaluation is the Key to Productivity Improvement by Acidizing in the Clayey Agbada Formation of the Niger Delta
Authors: Abuya Ohen Henry , Nnabuihe Larry , Ososanwo Dunni
Published: December 2007

This paper presents data that attest to the need for acid effectiveness evaluation for determining Formation specific optimum acid recipes prior to acid work in the Niger Delta reservoirs. The results of a complete acid effectiveness evaluation study for two oil reservoirs (A and B) and one aquifer system (C) show that the regular mud acid (RMA) commonly used for stimulation in the Niger Delta may be damaging under many circumstances, The extent of damage by the regular mud acid and the improvement through properly designed recipes are shown by laboratory analytical tests which are scaled to field and well condition. The analytical work includes characterization of the reservoirs.

The hydraulic unit (HU) concept that combines the geological (texture and mineralogy) and petrophysical (porosity, permeability and capillary pressure) controls of the rock quality was used to delineate the reservoirs into units with similar fluid flow characteristics, This zonation enabled the determination of the acid recipes by hydraulic units and thus facilitated the extrapolation to uncored intervals or wells.

The optimum acid sequences for each hydraulic unit were determined on the basis of pre- and post stimulation indices, compressive strengths and critical velocities. Visual observation of core material at the end of the acid flush and iron sequestrant analysis were also used as interpretation tools.
Improved Minifrac Analysis Technique in High-Permeability Formations
Authors: Dusterhoft Ron , Vitthal Sanjay , McMechan David , Walters Harold
Published: December 2007

Interest in fracturing high-permeability formations to control sand production and bypass formation damage has recently increased. These treatments typically require a "tip screenout" design, followed by efficient proppant packing, to achieve the high conductivities required to achieve optimum results. The need for a tip screenout and the relatively short treatment pumping times require that fluid loss characteristics of the formation must be very well defined before job execution.

Borate-crosslinked fluids and linear HEC gels are by far the most commonly used fluids for high-permeability fracture treatments. Extensive laboratory testing has shown that the fluid loss behavior of these fluids can be very different from that described by conventional fluid loss models. Traditional minifrac analysis techniques fail to account for the correct fluid loss behavior of these gels. As a result, use of these techniques can lead to severe errors in the estimation of the leakoff parameters, resulting in over- or under-designed jobs. This paper presents a novel minifrac analysis technique that more accurately accounts for the fluid loss characteristics of the fracturing fluid, allowing for better design.

This analysis has been verified against actual treatments and shows excellent agreement with the observed ‘net’ pressure response for the minifrac and the actual treatments. Several case histories are provided to illustrate the method. This technique has broad applications to low and intermediate-permeability fracturing applications as well.
Application of Chemicals in Prevention and Treatment of Asphaltene Precipitation in Crude Oils
Authors: Groffe P. , Voile J. L. , Ziada A.
Published: December 2007

Damages due to asphaltene deposits both in the formation and in equipment is a well-known problem in production operations.

Asphaltenes have been thoroughly described and analyzed, but very few articles introducing surfactants as asphaltene flocculation inhibitors have yet been published.

As surfactants can adsorb on the surface of asphaltenes, thus preventing their flocculation, Anticor Chimie and Elf Aquitaine Production have set up a system of surfactants that allows asphaltene dispersion in crude oil. A specific formula has to be designed for each case, usable with current oil production processes.

Two different applications have been carried out:

– On the first oilfield, damage was due to the plugging of the surface equipment and the difficulties in breaking down emulsions. The use of a suitable surfactant formulation has prevented plugging and allowed effective water/oil separation at the well head – On the second oilfield, plugging occurred in the vicinity of wellbore, which caused a decrease in production and the formation of deposits inside the tubing. Wireline scraping had to be carried out twice a week.

A field trial squeeze was carried out, and resulted in a flow rate increase of 26 %. The surroundings of the hole were unplugged. Wireline scraping was stopped as deposits no longer appeared (during the treatment period).
MOLEX - The Oil Reservoir Characteristics Dependent Well Performance and Completion Model
Authors: Soleša Mišo , Cveticanin Snežana
Published: December 2007

The MOLEX was conceived and developed in the attempt to arrive at a well performance and completion model which will override the deficiencies of the available simulation models by integrating the many reservioir controls with the effects of well and perforations geometry.

The mathematical groundwork of the MOLEX considers oil flow dynamics in heterogenous pore space and perforations, expressed in terms of mathematical oil inflow equations valid for conventional (vertical) and unconventional (slant and horizontal) wells.

Heterogeneity effects are accounted for by three modifiers, i.e. the transformation matrix of anisotropic pore space into its homogenous equivalent (TT), the integral hydrodynamic factor (IKHF) and the composite skin factor (SCOMP).

Comprehensiveness is the feature of the model which makes it unique and original. This quality allows the combined action of reservoir characteristics to be analysed and the productivities of various well types, productivity ratios, reservoir and well parameters significance and cut-offs to be evaluated.

Using the built-in basic rules, the MOLEX simulation model pieces together the many facets of the oil well performance and completion problem. The right solution is offered by ways of stepwise and discriminating analyses of well productivites subject to reservoir characteristics.

The validity of the MOLEX has been tested on two selected cases, that of Turija Sever and Jermenovci fields. The calculations and analyses indicate that the optimum engineering solution for the future operation of these fields are slant and horizontal wells, respectively.
An Object Oriented Tool for Modeling Production Data Associated with Reservoir Simulation
Authors: Esau Richard , Wells Michael , Leiknes Jorgen
Published: December 2007

An object oriented, cross platform, C++ application has been successfully developed for the manipulation of production data associated with reservoir engineering and reservoir simulation data. The application supports all the main categories of production data necessary for simulation including historical production and injection volumes, well deviation surveys and reservoir events such as completion data.

Particular emphasis is placed on the rapid generation of accurate and representative simulation controls. Key features include time varying connection factors where parameters are calculated from perforation data specified in terms of measured depths and formations, a flexible timestep framework and the handling of deviated wells, partially penetrating wells and multiple completions within a single simulation cell.

The paper will discuss how the development of this and associated applications has shown it is possible to efficiently build sophisticated, cross platform products if the appropriate tools, suppliers and methodology are used.

Finally the paper will address how the application and corresponding application development environment helps address future uncertainties including the continuing hardware and software revolution, the move towards keywordless, "gridless" simulation on a geological model and the existence of multiple integration platforms.
An Object Oriented Expert System to Enhance the Log Analysis of the Colombian Basins
Authors: R. Soto B. , C. Soto T.
Published: December 2007

This paper describes an Expert System developed to predict whether a pay zone will produce hydrocarbon or water. This Expert System was applied to the Caballos and Villeta Formations in the Putumayo basin and the Mirador Formation of the Cusiana Field, both in Colombia. Log analysis "rules" relating the combination of logs (SP, GR, caliper, resistivity, density, neutron, sonic, etc.) and basic information are included in the knowledge base.

The Expert System uses the Kappa-PC Shell and is composed of three sub-systems: 1) an inference engine, 2) a knowledge base, and 3) a user interface. We also consulted human experts to formulate and expand the knowledge base. Additionally, each formation was characterized using a Log Interpretation System (QLA2). The results from each characterization were used to develop cross plots. The QLA2 cross plots provided practical correlations from which to formulate "rules" for the Expert System.

Logs from nine wells in the Cusiana Field were used to evaluate the Expert System. The recommendations of the Expert System agreed with conventional log analysis theory as well as with the known field results. Furthermore, it minimized the time and cost required to evaluate the pay zones. In conclusion, this Expert System can be used to predict whether or not a zone will produce oil or water with a high degree of accuracy.
CriTi-CAL: A Computer Program for Critical Coiled Tubing Calculations
Authors: He Xiaojun
Published: December 2007

A computer software package for simulating coiled tubing operations has been developed at Rogaland Research. The software is named CriTi-CAL, for Critical Coiled Tubing Calculations. It is a PC program running under Microsoft Windows.

CriTi-CAL is designed for predicting force, stress, torque, lockup, circulation pressure losses and along-hole-depth corrections for coiled tubing workover and drilling operations. CriTi-CAL features an user-friendly interface, integrated work string and survey editors, flexible input units and output format, on-line documentation and extensive error trapping. CriTi-CAL was developed by using a combination of Visual Basic and C. Such an approach is an effective way to quickly develop high quality small to medium size software for the oil industry.

The software is based on the results of intensive experimental and theoretical studies on buckling and post-buckling of coiled tubing at Rogaland Research. The software has been validated by full-scale test results and field data.
Computer Generation and Application of 3-D Model Porous Media: From Pore-Level Geostatistics to the Estimation of Formation Factor
Authors: loannidis M. , Kwiecien M. , Chatzis I.
Published: December 2007

This paper describes a new method for the computer generation of 3-D stochastic realizations of porous media using geostatistical information obtained from high-contrast 2-D images of pore casts, The stochastic method yields model porous media with statistical properties identical to those of their real counterparts. Synthetic media obtained in this manner can form the basis for a number of studies related to the detailed characterization of the porous microstructure and, ultimately, the prediction of important petrophysical and reservoir engineering properties. In this context, direct computer estimation of the formation resistivity factor is examined using a discrete random walk algorithm. The dependence of formation factor on measurable statistical properties of the pore space is also investigated.
Determination of Casing Setting Depth Using Kick Tolerance Concept
Authors: Santos Otto , Adasani Ibrahim , Azar J. J. , Escorihuela Francisco
Published: December 2007

This paper presents a methodology for designing setting depths of surface and intermediate casing strings in oil wells using the concept of kick tolerance. The methodology was implemented in a microcomputer program written in FORTRAN. The results are plotted to the microcomputer screen through a graphical interface written in C that calls Windows API functions.

The proposed algorithm uses an iterative procedure to define the shallowest casing shoe setting depth employing the kick tolerance concept. It compares the curve of fracture pressure equivalent density with the pressure generated inside the wellbore during a well control operation to estimate the casing shoe setting depth. The kick tolerance concept is applied in two ways: (a) for the well containment and (b) during the gas kick circulation.

In situation (a), the calculation procedure considers the wellbore pressure just after the well closure. In (b), a two-phase flow kick simulator is applied to predict wellbore pressure generated during the gas kick circulation from the well.

Two examples are elaborated to show the application of the proposed methodology and the computer program. The results are presented graphically to illustrate the use of the graphical interface.
FORTRAN: From Mainframe (to PC) with Love
Authors: McDowell Edward R.H.
Published: December 2007

Edward R.H. McDowell. Jr.

In 1993, PipeSoft Corporation ported 250,000 lines of FORTRAN code in 600 subroutines written for IBM 370 mainframes to the PC. This process produced PipeSoft's PC-based multiphase fluid flow simulator. PIPESOFT-2. The original simulator was developed by Chevron between 1976 – 1992. The new PC-based simulator, PIPESOFT-2 provides the same functionality as the mainframe version.

The wide acceptance and power of the PC makes porting legacy mainframe systems a realistic alternative to designing and building software from scratch for the PC. Porting not only extends a program's useful life, but also increases distribution opportunities. And, once ported to a mainstream platform the software can continue to be improved without loss of the original investment.

The Plan

PSC would receive a tape containing the FORTRAN source, quality control data and run results. A Unix workstation would serve as PSC's "mainframe."

Our plan was simple: get the code running under Unix and compare Unix OC results to IBM OC results. Then port the code to the PC and compare PC OC results to Unix OC results. (This double port wasn't quite as ambitious as it seems - Chevron had already ported the code to a Cray.)

Since PIPESOFT-2 is dynamically dimensioned we felt that recoding platform specific memory management routines would be the biggest obstacle.

PIPESOFT-2 actually consists of 10 modules. Three of which run sequentially and provide pre-processing of data. The fourth module (or more) run depends on selected modeling options.

We chose to use Microsoft FORTRAN PowerStation because:–A large, flat, 32 bit address space was necessary for the program.–A prior attempt to port the program to a PC using a different FORTRAN compiler encountered difficulties.–We anticipate that Microsoft will migrate support of their FORTRAN offerings to other platforms (e.g. Windows NT) in the future.

We anticipated this effort to be straight forward because the code was originally written with then current programming techniques, such as "modularization," and "top down structured programming." The code, on the whole, is well constructed.

P. 331
Latest Concepts in Offshore Lift Crane Design
Authors: Barber Donald E. , Bonneson Garland W.
Published: December 2007

This presentation describes how offshore operators were instrumental in developing specifications for marine lift cranes and how their specifications were translated into a new crane configuration especially suited to the ocean environment. The resulting crane design represents an effort to improve the safety and reliability of material handling offshore.

Historically, the stationary cranes used in offshore service have generally been adaptions of land crane upper works. Recognizing that this type of adaption might not fully meet the special needs of the offshore industry, field studies were conducted to determine the features and performance required for cranes in offshore service. A summary of this industry study and the resulting new lift crane designs are contained in this paper.

THE OFFSHORE INDUSTRY SURVEY

The twofold purpose of the survey of offshore operators was first to determine the needs and wants of the offshore industry and second to learn from the experience of longtime operators in the business. Using their stated-requirements and suggestions, crane specifications were gradually developed as the program progressed. When machine specifications appeared reasonably well established, preliminary machine designs were developed.

These preliminary designs and the supporting specifications were further refined through continuing interviews until it was determined that final designs could be established.

Over a period of 18 months, more than 50 interviews were conducted with people involved in specifying, purchasing or operating lift cranes purchasing or operating lift cranes in the offshore and marine industries.
Cold Lake Profitability Improvement
Authors: Boone D. J. , McGregor K. J.
Published: December 2007

For over 30 years, Imperial Oil Limited has been pioneering the extraction of a very heavy grade of oil known as bitumen from the Alberta oil sands in the Cold Lake area. For close to 10 years, a world scale commercial project has operated, employing a thermal recovery process known as "cyclic steam stimulation" (CSS). This process involves alternating periods of steam injection and production, both through the same wellbore.

The Cold Lake operation faces two challenges not typically experienced by conventional operations. First, substantial costs are incurred to generate steam, and treat water. Also, bitumen sells for less than light sweet crude. Consequently, margins are tight, and continuous unit cost improvements essential.

This paper describes the Cold Lake operation along with many of the innovations that have led to a one-third reduction in operating costs over the past decade.
Cogeneration Potential in Western Canada
Authors: Berry J. P. , Good W. K.
Published: December 2007

Western Canada has very large heavy oil and bitumen resources, the recovery of which will require the application of thermal recovery processes in most cases. The most common thermal process involves injection of large quantities of steam. Steam generation accounts for approximately 30 percent of the costs of recovering heavy oil and bitumen. Reduction of this cost, therefore, is a very important factor in the economics of recovering heavy oil and bitumen and affects the amount that will be ultimately recovered.

Cogeneration of steam and electricity has been implemented at a number of projects in California and other places. It has proven to be one method of improving the energy efficiency and reducing costs of both electricity and steam. An industry-supported study of cogeneration as it would apply to Canadian operations was undertaken in 1992. Typical small, medium, and large heavy oil or bitumen thermal recovery projects of 4,000, 15,000, and 50,000 BOPD were identified and conceptual cogeneration designs, cost estimates, and economic evaluations were carried out for 10 scenarios. Sensitivity analyses were conducted to illustrate the relationship between the power buy-back rate and fuel costs on the economics of potential cogeneration projects. The simple cycle gas turbine configuration applied to medium and large volume projects was shown to have potential applicability.

The design, cost estimates, economics, and other factors that must be considered in developing a cogeneration project are discussed.
Oil Sands: Strategies For Future Development - An Overview
Authors: Yildirim Erdal
Published: December 2007

Alberta Chamber of Resources has represented the resource industries in the Province of Alberta for almost 60 years. The Chamber's primary objective is to promote and support the orderly development of Alberta's natural resources.

In the early 1980's, the Chamber identified Alberta's oil sands as the priority mineral resource for further development during that decade. Towards this end, a Task Force of industry and government representatives was set up in 1984 to promote oil sands development. One objective of the Task Force was to identify and publicize the social and economic benefits of oil sands operations.

In 1993, a "National Task Force on Oil Sands Strategies" was formed by the Alberta Chamber of Resources, on behalf of both the government and the private sector. The Task Force's objective is to act as a catalyst for the further development of Canada's immense oil sands resources. During the last two years the Task Force has carried out its mandate to identify a clear vision for growth and to develop strategies and plans for long-term implementation.

This paper summarizes briefly the formation and the mission of the National Task Force and focuses on impediments and opportunities for development and offers strategies and recommendations for the future.

2.0 NATIONAL TASK FORCE ON OIL SANDS STRATEGIES

During 1992, the ACR Executives have had a series of meetings with the senior officials of the Alberta and Federal Energy departments for the formation of a National Task Force to formulate a set of strategies for oil sands development. The ACR proposals were well received and fully supported by both levels of government. Early in 1993, a Steering Committee was formed by the representatives of the Alberta and Federal governments and the industry.

This committee accepted the responsibility to carry out its mandate and formulated its mission statement as follows:

To be a catalyst for further development of Canada's oil sands resource through identification of a clear vision for growth and preparation of a plan of action.

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The Solvent Requirements for Vapex Recovery
Authors: Butler R. M. , Mokrys I. J. , Das S. K.
Published: December 2007

In both SAGD and VAPEX, recovery agents are introduced into the reservoir and these displace oil to horizontal wells located at the base. In each process it is desirable to inject at a pressure equal to or slightly below the pressure of the surrounding reservoir, so as to prevent flow of fluids to outside the recovery pattern.

The pressure in the recovery pattern is reduced by allowing production to draw vapour almost to the production well. The recovery agent that is produced is liquid (water condensate or dissolved solvent). This agent is separated and recycled.

The recycled quantity is about 2–6 tonnes per tonne (t/t) of produced oil for SAGD and 0.3–0.5 t/t for VAPEX. Recycle is much simpler for VAPEX.

The pore volume that contained the produced oil becomes filled with recovery agent either vaporized (steam or solvent vapour) or liquid (water or dissolved solvent). The net requirement of recovery agent is equal to the make-up supplied to the system to maintain operation.

For VAPEX, it is this quantity of solvent that determines the net cumulative solvent-to-oil ratio (NCSOR) before blowdown. Subsequently, during blowdown, a considerable fraction of this net solvent is recovered.

At one extreme the NCSOR is the weight of the solvent vapour that has the same volume as the produced oil. This is usually very small, e.g. 0.02 tonnes of propane per tonne of produced oil. At the other extreme it is the weight of the corresponding volume of liquid solvent and this is much larger, e.g. about 0.5 tonnes of propane per tonne of oil.

In practice the solvent in the reservoir is partly vaporized and partly dissolved in the draining liquid and, as a result, the NCSOR lies between the two extremes. In this paper, this situation is analyzed and experimental results from scaled-model studies are presented. These results show that, with propane as solvent, NCSOR values of about 0.1 to 0.2 may be expected in practice. This range of values corresponds to about 20–30% of the net solvent make-up remaining in the form of vapour.
Reducing Economic Risk in Areally Anisotropic Formations with Multiple-Lateral Horizontal Wells
Authors: Smith J. , Economides M. J. , Frick T. P.
Published: December 2007

Well orientation is critical to horizontal well performance in areally anisotropic reservoirs. A horizontal well, drilled normal to the direction of maximum permeability, will have higher productivity than one drilled in any other arbitrary direction. Currently, horizontal permeability magnitudes and even indications of direction are rarely measured in the field. Based on well performance modeling and economic evaluation, this study attempts to determine the relative attractiveness of horizontal wells with multiple-laterals. The work exposes the economic risk in ignoring horizontal permeability magnitudes and directions and demonstrates the importance of adequate reservoir testing. A new rationalization for multiple-lateral horizontal wells is the reduction of the economic risk associated with poor reservoir characterization in areally anisotropic formations while increasing the incremental net present value (NPV) over single-horizontal wells.
The Point Mclntyre Subsurface Development Team: Field Development Planning With A Multi-Company, Multi-Disciplinary Team
Authors: Pish W. J. , Erickson J. W. , Janes R. W. , Bredar W. L. , Pospisil G.
Published: December 2007

This paper describes the composition, functions, accomplishments and key learnings of the multi-company, multi-disciplinary team that is being used to develop the Point Mclntyre field. Additionally, the team's development of a common geologic description, log model, full-field model, and consensus field development plan is discussed. This paper demonstrates how, under certain circumstances, a multi-company, multi-disciplinary team can offer a cost effective alternative to more traditional joint-owner field development approaches.