Wednesday, July 28, 2004
Core Laboratories, 6316 Windfern, Houston, Texas 77040

Today's deepwater 'elephant' reservoirs are on the order of 10,000 to 50,000 acre-feet, but the near-wellbore 0.5 acre-foot can be a 'boiler room' for the source of catastrophic events! This workshop will look at four case scenarios where "what you don't know CAN AND WILL hurt you."

Evaluation of Condensate Banking in the Near-Borehole Area in Gas Reservoirs
Dr. William D. "Bill" McCain Jr, Texas A&M
(PDF, 634 KB)
When the producing bottomhole pressure in a gas condensate well decreases below the dew point pressure of the reservoir gas, a "cylinder" of reservoir around the wellbore develops a high saturation of condensate. The saturation of condensate in this cylinder of reservoir will be much higher than the volume of condensate measured in a constant volume depletion experiment. This causes a severe reduction in gas production rate. The level of condensate saturation depends on rock properties (effective permeability to condensate) and fluid properties (richness of the gas). This presentation will discuss the mechanics of the buildup of this cylinder of condensate and examine the dynamics of the condensate saturation as various changes in flow rate and reservoir pressure occur.

Asphaltene Near-Wellbore Formation Damage Modeling
Dr. Kosta J. Leontaritis, AsphWax, Inc.,
(PDF 552 KB)
During oil production, when the thermodynamic conditions within the near-wellbore formation lie inside the asphaltene deposition envelope of the reservoir fluid, the flocculated asphaltenes may cause formation damage. Mathematically, formation damage is a reduction in the hydrocarbon effective mobility, l (l =k/m). Three possible mechanisms of asphaltene-induced formation damage have been discussed in the literature. Asphaltenes can reduce the hydrocarbon effective mobility by a) blocking pore throats thus reducing the rock permeability k, b) adsorbing onto the rock and altering the formation wettability from water-wet to oil-wet thus diminishing the effective permeability to oil, ko, and c) increasing the reservoir fluid viscosity, m, by nucleating water-in-oil emulsions. In the most frequently encountered case of asphaltene-induced formation damage where under-saturated oil is being produced without water, the most dominant damage mechanism is blockage of pore throats by asphaltene particles causing a reduction in rock permeability k and to a lesser extent adsorption of resin-coated asphaltene particles.

This presentation concerns a rather simple, yet realistic way of modeling asphaltene-induced near-well formation damage caused by blockage of pore throats by asphaltene particles. The model utilizes both macroscopic and microscopic concepts to represent the pore throat blockages. It also utilizes the theory of an existing, published asphaltene phase behavior model capable of providing the asphaltene particle size distribution as a function of the thermodynamics of the system. The formation damage model is applied in one case where it is used to track the degree of formation damage as a function of time and the effect it has on near-wellbore and wellbore hydraulics and oil recovery. The van Everdingen-Hurst skin factor attributed to asphaltene-induced formation damage is also calculated by the model as a function of time.

Viscosity Correlations and the Impact of their Errors on Reservoir and Pipeline Flow Calculations
Dr. Dave Bergman, BP
(PDF 328 KB)
Ask any reservoir engineer what the most important physical property measured in standard PVT analysis is and 90% will answer viscosity. Ask a simulation expert or an equation-of-state analyst what property is the source for the most uncertainty and largest error variability in mathematical modeling and 90% will answer viscosity! Not exactly the combination of responses that would be most desirable in material balance calculations. Viscosity values influence decisions in reservoir engineering from mobility calculations to pipeline design to developmental well counts, yet the errors sometimes observed without measured values can approach 100%. Viscosity data are some of the key elements to understanding the dynamics of the two previous presentations. There are as many viscosity models as "fish in the sea", or at least if seems that way when one initiates a literature search. Are all correlations created equally? This presentation will draw upon 30 years of analytical experience and compare published correlations and 'unpublished' correlations, as well as look at variances in measured data and determine which sets are valid and which are not.

Geochemical Modeling of Inorganic Scaling Onsets: Model Verification and Tuning using HPHT NIR Techniques
Jack Lynn, Core Laboratories
(PDF 1 MB)
The "forgotten" form of formation damage, scale formation can be as catastrophic as problems caused by condensate banking or asphaltene flocculation. Mineral scales are adherent forms of inorganic salts that deposit on production equipment surfaces. Oilfield brines containing (among other constituents) excess concentrations of calcium and barium precipitate carbonate and sulfate salts when thermodynamic and kinetic conditions are favorable. When scales deposit on process equipment, production decreases and operators are compelled to remedy the problem, increasing production costs. Therefore, effective scale inhibition is an important preventive when designing and operating oil and gas wells.

However, the addition of scale control chemicals and the associated treatment facilities are a significant added cost to new facilities development, and as with any contingency, they should not be included if there is no perceived need. Unfortunately, retrofitting of facilities can increase the cost of control by an order of magnitude. We need effective means to predict scale onsets and the magnitude of the problem. Geochemical modeling entails using data derived from the ionic composition of the brine, the mineralogy of the producing or injection formation, and the thermodynamics of the equilibrium system (i.e., reservoir temperature and pressure), and reconstructing the solution and dissolution reactions that will control the species behavior. Geochemical models are used to access the potential for inorganic scale formation during production and injection of brines. They can also be used to evaluate dissolution of downhole species during the water flood process.

Models can be developed to model brine/brine interaction such as during surface mixing of various source brines for a waterflood project. This commonly will entail the use of reservoir simulators to predict break-through flood patterns. Scale can form as brines are mixed, or incompatibility can surface as a function of temperature during injection. The models must be constructed with due respect to the environments they will be modeling. Models that are looking at downhole injectivity must incorporate the solid phases present in the formation, dispersion effects with the formation brine and adsorption effects on chemicals added prior to injection. (A scale inhibitor added at the surface that plates out on the formation would not prevent scale downhole). The effects of dispersion are determined by core floods, and must be appropriately scaled to reservoir rates, with due respect to the geological and permeability character of the injection interval. Surface mixing models must incorporate effects from brine mixing ratios, flow rates, any chemicals added, gas stripping, and pipeline retention times. All of these effects can be investigated by core flooding methods, and incorporated into the geochemical models.

Unfortunately, All geochemical models suffer from "false positive indications", and are only as reliable as the thermodynamic data in their programs and there is limited thermodynamic data for more "exotic" solids. This presentation will discuss the use of geochemical inorganic scale prediction models, their advantages and limitations. We will demonstrate the use of HP/HT near-infrared (NIR) spectroscopy to validate and tune the geochemical models to eliminate "false positives". Two case studies will be shown, one for hydrocarbon well subsurface inorganic scale control, and one for deep formation injection, waste fluid disposal scale. We will also show how the NIR technology has been used in the selection of commercial inhibitors at reservoir conditions. We will also discuss LT/HP applications of the NIR technology.

About the Speakers

Dr. William D. "Bill" McCain, Jr.
Dr. McCain has been a Visiting Professor in the Harold Vance Department of Petroleum Engineering at Texas A&M University since 1991. He started his engineering career with Esso (now Exxon) Research Laboratories in 1956, where he assisted in research on surface processing of petroleum fluids. He was Professor and Head of the Petroleum Engineering Department at
Mississippi State University fro 1965 to 1976 and taught at Texas A&M University from 1984 through 1987. McCain was a consulting petroleum engineer with Cawley, Gillespie & Associates from 1987 until 1991. He was with S. A. Holditch & Associates from 1991 until 2000, retiring as Executive Vice President and Chief Engineer. He currently has his own consulting firm, McCain Engineering. He wrote two editions of the widely-used textbook, The Properties of Petroleum Fluids, holds U. S Patents, and has numerous publications in the field of petroleum engineering. He holds a B.S. degree from Mississippi State University, and M.S. and Ph.D. degrees from the Georgia Institute of Technology, all in Chemical Engineering.

Dr. Kosta J. Leontaritis
Dr. Leontaritis did his undergraduate work in Chemical Engineering at the University of Illinois, Chicago. He obtained his MS in Chemical Engineering with focus in petroleum refining from the Illinois Institute of Technology, Chicago, and his Ph.D. from the University of Illinois, Chicago, in Chemical Engineering in 1988. Dr. Leontaritis, affectionately known in the Gulf of Mexico circles as Dr. Wax, is founder of Kosta Oil Field Technologies, Inc. and AsphWax, Inc. AsphWax's objective is to provide the Oil and Gas Industry with simulation and consulting services in equipment development, modeling, problem solving, and chemical applications in the area of asphaltenes, waxes, hydrates and flow assurance. KostaTech's objective is to manufacture custom-designed asphaltene, wax, and hydrate solvents/inhibitors/dispersants/crystal modifiers and other oil-field specialty solvents.Prior to forming AsphWax Inc. in 1994, Dr. Leontaritis served as Manager of Research and Technology Development (RTD) and Director of Phase Behavior Research for Core Laboratories, Houston, Texas. Before joining Core Laboratories in 1991, he was Senior Research Engineer with ARCO Oil and Gas Company, Plano, Texas. Dr. Leontaritis worked for four years at North Aegean Petroleum Company. Prior and during his Masters studies, he worked as an Operations/Process Engineer for Union Oil Company in their Lemont, Illinois, refinery.

Dr. Leontaritis' "hands-on" experience on the design, operation, and maintenance of petroleum production, processing, transportation, and refining facilities covers the entire upstream and downstream oil industry including small independents, majors, service companies, and research organizations. Dr. Leontaritis has extensive experience with "real" field asphaltene, wax, and hydrate problems coupled with experience in modeling and simulation using Equations of State and other asphaltene and wax models, which in most cases he developed. Dr. Leontaritis is a member of AIChE and SPE. He has served as technical editor and symposium co-chair for professional societies and other research organizations relevant to the Petroleum Industry worldwide. He has also taught numerous courses in phase behavior, flow assurance, and asphaltene and wax deposition simulation and management.
You can reach Dr. Leontaritis via e-mail at: kosta@kostatech.com or kosta@asphwax.com. Websites: www.asphwax.com and www.kostatech.com

Dr. Dave Bergman
Dr Bergman is a 30 year veteran of the oil industry. He received a BS in Chemical Engineering from Michigan Technological University and his MS and PhD degrees from The University of Michigan. He began his career in 1973 as the primary researcher for the American Gas Association Project, U. of Michigan. In 1976, he joined Amoco Research in Tulsa. During his tenure with Amoco, he was involved in research into improved viscosity correlations, low-temperature equilibrium ratios, design of PVT and lab equipment, QA of internal and external fluid studies and became the Instructor for internal EOS and PVT courses. Dr Bergman is also the co-author of several published correlations, including the development of chromatographic methods for C7+ characterization. In 1999, upon the merger of Amoco with BP, his studies focused on the development of EOS descriptions for reservoir modeling and QA for outside testing laboratories. Professionally, he is a member of SPE and the Gas Processors Association.

Jack Lynn
Jack is a Technical Specialist for PENCOR's Advanced Fluid Studies Lab in Houston. Jack received a BS in Geology from Sul Ross State University and is a 25 year veteran of the industry and an experienced R&D, production, and reservoir geologist, as well as an expert in reservoir study integration. He is a recognized industry expert in formation damage, reservoir quality assessment, production problem remediation, routine and special core analysis and equipment design. He has prepared over 40 industry papers, and holds two US patents for scale mitigation programs. His geological specialties include clastic petrography, production and reservoir geology, reservoir simulation, and scale-up. His engineering specialties include stimulation and completion engineering, waterflood, EOR/IOR design and implementation. His past assignments have spanned the range from development, production and reservoir geologist to reservoir engineering support for environmental operations. He has had extensive experience in the integration of petrophysical data (sourced from wire line, rock, and well testing) with geological data.

He has spent 18 years in the Middle East where he provided consultant services in production and development and research geology in the engineering environment, specifically for formation damage assessment and remediation, reservoir quality assessment, stimulation prognosis and completion design in clastic and carbonate formations. His notable multidisciplinary projects range from water quality assessment for the super giant Ghawar field to scale mitigation in the Hawtah field trend, in which his design innovations resulted increased production of 45,000 barrels of oil per day, and cost avoidance of $1.8 MM per year. The work resulted in a novel, multistage emulsified scale mitigation treatment that has been patented. As a Laboratory Manager, he has staffed, equipped and maintained three laboratories, including most recently, the formation damage and remediation lab at Saudi Aramco with a $ 5.6 million capital budget, $100,000 per year operating budget, and 15 full time researchers/technicians. He is a member of AAPG, SPE, Society of Core Analysts, Canadian Petroleum Society, and Geochemical Society.