bluuebunny/crossref_metadata_2025 huggingface dataset:
Geology And Seismology: An Effective Combination In The Evaluation Of Underground Natural Gas Storage Prospects And Fields
Authors: Miller Robert R. , Reinerio Eugene D.
Published: December 2007

The primary purpose of this paper is to show the benefits obtained from coordinating seismic and geologic information into an acceptable interpretation of the subsurface geologic conditions existing at a particular gas storage project.

During 1974 and 1975, seismic explorations, utilizing the common depth point (CDP) technique and the Vibroseis energy method, were conducted at Northern Natural Gas Company's Dallas Center Aquifer Storage Prospect in central Iowa and Lyons Depleted Gas Field Storage Prospect in central Kansas. Although these two areas are geographically far removed from one another, the CDP technique is quite applicable to each of these geologic provinces.

The petroleum engineer's need for detailed information about the configuration and integrity of the gas storage reservoir often surpasses the geologist's knowledge, based on a finite number of drill holes. The seismologist, working in close association with the geologist and utilizing modern field recording techniques, instruments and computer data enhancement, can add a new dimension to the understanding and thinking of both the petroleum engineer and geologist.

Introduction

The Dallas Center Anticline, located in Dallas County, Iowa, is 300 miles northeast of the Lyons Anticline, located in Rice County, Kansas. Both of these geologic structures have been evaluated by shallow and deep drill holes and by common depth point seismic work. The purpose of this evaluation was to prove their purpose of this evaluation was to prove their relative worth either as an aquifer gas storage prospect (Dallas Center) or to more accurately prospect (Dallas Center) or to more accurately define the boundary faults associated with an abandoned gas field (Lyons). Figure 1, an index map, shows the location of these two anticlines in relation to each other and to State and County boundaries, as well as major geologic features.

Geologically, the two anticlines are in entirely different provinces. The Dallas Center Anticline is located at the extreme northern end of the Forest City Basin, eight miles east of the southeastern edge of the Mid-continent Gravity-Magnetic High. The Lyons Anticline is located on the southern half of the Genesco Uplift, the eastern most lobe of the larger Central Kansas Uplift.

The Dallas Center Anticline was originally delineated by Northern Natural Gas Company from preliminary structural mapping of shallow farm preliminary structural mapping of shallow farm water well data.
Impact of Clay Acidity on the pH of Invading Fluids
Authors: Gdanski Rick
Published: December 2007

It is commonly understood that clays have surface hydroxyls that are available for various interactions. However, this paper demonstrates the magnitude of the interactions possible by the natural acidity that clays possess. Laboratory experiments with a 3-ft Hassler sleeve and unconsolidated sand/clay-packed columns demonstrated that the pH profile of buffered and unbuffered high-pH fluids can be readily understood in terms of the natural acidity of clays. The impact of the clay acidity on brine pH was much larger than imagined. In fact, the original goal of the work was to investigate the attack of hydroxide on clays. However, it was found that the dominant mechanism for lowering the injected fluid pH was clay acidity. The impact oftotal clay acidity (TCA) on injected-fluid pH proflies was numerically demonstrated with the new model for both linear and radial flow. These two geometries are relevant to leakoff during frac-packs (linear) and for drill-in fluids and matrix treatments (radial).
The Effect of Fluid Leakoff on Gel Placement and Gel Stability in Fractures
Authors: Ganguly S. , Willhite G. P. , Green D. W. , McCool C. S.
Published: December 2007

Chromium acetate-hydrolyzed polyacrylamide gel systems are applied in fractured reservoirs for conformance control. A portion of the gelant leaks off into the adjoining matrix during placement of the gelant in the fracture. This paper describes an experimental study on the effect of fluid leakoff on the performance of a gel treatment. The stability of a gel that is placed in a fracture and is subjected to a pressure gradient was also investigated.

Physical models of a fracture were developed to conduct displacement experiments. The models were fractured Berea sandstones that were designed to permit leakoff of the gelant into the matrix on the sides of the fracture. A polyacrylamide-chromium acetate gelant was injected into the fracture under conditions in which there was leakoff and no leakoff into the matrix. A gel did not form and the gelant was easily displaced from the fracture by subsequent brine injection when the gelant was placed without leakoff. When the gelant was placed with leakoff, a gel formed in the fracture after placement and provided significant flow resistance. Lack of gelation in the absence of leakoff was caused by diffusion of chromium from the fracture to the matrix, reducing the chromium concentration in the gelant to levels where gelation would not occur.

It was discovered that gels that were formed in a fracture ruptured when a constant brine pressure was applied at the inlet. The pressure where rupture occurred was determined for gels placed in tubing of various lengths and diameters. The rupture pressure was proportional to a ratio of the length-to-diameter.
Treatment of Super-K Zones Using Gelling Polymers
Authors: Alqam M. H. , Nasr-El-Din H. A. , Lynn J. D.
Published: December 2007

An experimental investigation was undertaken to modify the permeability profile of high permeability fluid zones (producing and injection) using gelling (cross linking) polymers. The first phase of this study included characterization of "super-K" zones. Computerized Tomography (CT), Scanning Electron Microscopy (SEM), X-ray Diffraction (XRD) and an Apparatus for Pore Examination (APEX) system were used to determine the mineralogy and pore geometry of carbonate core plugs obtained from the matrix and super-K zones.

In the second phase of the study, various gelling solutions were injected into reservoir core samples to evaluate the ability of the gel to resist extrusion and determine the robustness of the treatment chemical under downhole conditions. Core plugs used in this study were obtained from an oil producer in a carbonate reservoir in Saudi Arabia.

The results of the first phase indicated that the super-K streaks have a tortuous path. There are significant differences between the lithology and pore size distribution of the super-K zones and the normal matrix. In addition, there is convincing evidence that the super-K intervals may be fractured as well diagenetically induced.

The use of thin section petrology has highlighted potential problems in using the gel in formations that are vugular or have large diameter natural fractures. The data has demonstrated that the gel will not fully fill pore voids greater than 400 microns, and would not invade pores smaller than 70 microns.

Coreflood tests indicated that the gelling solution could be injected into either the matrix super-K or the fractured super-K. Reservoir condition aging improved the stability of the gels that were placed in matrix cores, but gave in less promising results in fractured intervals.
Physicochemical Characterization of Crudes and Solid Deposits as a Guideline to Optimize Oil Production
Authors: Carbognani L. , Contreras E. , Guimerans R. , León O. , Flores E. , Moya S.
Published: December 2007

A comprehensive analysis scheme devised in order to cope with solid precipitation during oil production is being currently followed in many Venezuelan production units. Three goals from the scheme are: 1. Identification of remedial actions based on deposits characterization, 2. Selection of the most efficient dispersant additive, 3. Choice of the proper solvent mixtures for cleaning production strings, when organic types were assessed to be the main components of the deposit.

This paper addresses these aspects with examples taken from a field located in eastern Venezuela.
Ensuring Systems Compatibility for Deepwater Chemicals
Authors: Frostman L. M. , Gallagher C. G. , Ramachandran S. , Weispfennig K.
Published: December 2007

Efficient production of oil and gas generally relies on the use of specialty chemicals to prevent solids deposition, inhibit corrosion, and control fluid phase properties. While performance testing is an important step in selecting appropriate chemicals for such applications, the compatibility of the chemicals with materials used in the production system is critical to the successful implementation of any chemical treating program. Extensive formulation work, laboratory testing, and field verification are required to ensure that production chemicals will be compatible with system metals and polymers used in pumps, umbilicals, and capillaries. In offshore applications, particularly in deepwater where many components of the production system are not readily accessible, the systems compatibility of any production chemical is an essential part of the flow assurance process. This paper will focus on compatibility of production chemicals typically used in deepwater applications with system materials, and the deliverability of these chemicals through umbilicals and capillaries. Materials commonly used in deepwater installations were chosen, including mild steels, stainless steels, Nylon 11, elastomers, and thermoplastics. Standard test procedures including documentation were implemented. The results of a comprehensive study of corrosion, paraffin, asphaltene, hydrate and scale inhibitors will be discussed. Using material compatibility data for performance chemicals enhances the selection process for existing production, optimizes material selection and design in the development stage for new production, and facilitates formulation of new products.
Field Evaluation of Downhole Corrosion Mitigation Methods at Prudhoe Bay Field, Alaska
Authors: Hsi Daniel C. , Woollam Richard C.
Published: December 2007

Increasing downhole corrosion failures are observed in large number of carbon steel (CS) completion wells at Prudhoe Bay field in Alaska. The main corrosion damage mechanism was identified as CO2 corrosion (sweet corrosion), caused by relatively high temperature (200 - 220 °F) and high CO2 content (12%) in the reservoir gas.

Different downhole corrosion mitigation methods, including corrosion inhibitor batch treatments, gas lift corrosion inhibitor treatments, chemical treater strings, internally plastic coated tubing, and 13Cr tubing were evaluated in the field.

The relative effectiveness and economics of different downhole corrosion mitigation methods were compared based on extensive corrosion monitoring data from weight loss coupons, downhole and surface electrical resistance (ER) probes, caliper surveys, and well completion/ workover records.

Study results show that corrosion inhibitor batch treatments have limited treatment life (<10 days) in higher water cut wells. Inhibitor film persistency (treatment life) is inversely proportional to the daily water production rate. Except for very low water cut wells, quarterly or monthly corrosion inhibitor batch treatments are not cost effective at Prudhoe Bay field. Gas lift corrosion inhibition, on the other hand, can potentially provide cost effective protection against downhole corrosion in higher water cut gas lift wells.

Study results also show that chemical treater strings and 13Cr tubing have excellent corrosion resistance performance and they are recommended for future new completion if high water production rates and/or long completion service life are expected.
An Investigation of the Stability of Colloidal Asphaltene in Petroleum Reservoirs
Authors: Alkafeef Saad F.
Published: December 2007

Asphaltene precipitation from petroleum fluids has proved to be a difficult problem to define and study. Asphaltene problems may occur deep in the reservoir formation and cause permeability reduction as well as contribute to serious plugging problems in oil well tubing and surface facilities. The stability of a dispersion in colloid science terms refers to the resistance of the particles to flocculation. The degree of this resistance is a measure of stability. Asphaltene colloidal dispersions in petroleum reservoirs are considered physically stable if free from any changes in physical properties. This paper first examines theoretically particles (asphaltene) in crude oil to determine, if they are electrically charged, how important it is to their inter-particle repulsion (stability). The theoretical result is then compared with the surface potential and steric effect of asphaltene and/or solid in petroleum fluids. Both theoretical and experimental results indicated that the electrical charge effects of asphaltene were found to play an utterly negligible role in the interaction between asphaltene particles and either surface or other particles. The stability of colloidal asphaltene in oil was investigated and determined to be caused by the steric effect of high molecular weight material (resins) adsorbed on asphaltene particles. The aggregation kinetic rates of asphaltene were also investigated using a laser back-scattering technique and determined to be influenced by the resin chemical potential concentration and the dispersion medium solvency. The latter needs to be a "good solvent" for the resin so that the aliphatic chains can be extended and move freely, thus enhancing the steric repulsion force.
Iron Sulfide Formation in Water Supply Wells With Gas Lift
Authors: Nasr-El-Din H. A. , Al-Humaidan A. Y. , Mohamed S. K. , Al-Salman A. M.
Published: December 2007

Iron sulfide scale is present in sour gas, oil and water wells. It is present in various chemical species with different iron to sulfur ratios. Iron sulfide species with high iron content is soluble in acids, whereas those rich in sulfur are almost insoluble in acids. Iron sulfide scale was detected in several water supply wells where a sour gas is used for gas lifting operation. The objectives of this study were to determine the mechanism that led to the formation of this type of scale, to characterize this scale and determine the most effective chemical treatments to remove and prevent reoccurrence. Lab work included characterization of the scale, and examine various acids and non-acids formulae to remove various iron sulfide species.

Several wells in a sandstone aquifer are used to supply water needed for the operation of gas oil separation plants (GOSPs). The reservoir pressure is low, therefore the water is produced using gas lifting. The gas used is an associated gas that is produced with the oil from a carbonate reservoir. The gas is sour with a hydrogen sulfide content of 2 mol%. In addition, the supply water contains total iron at 5–10 mg/L. Hydrogen sulfide reacts with the iron present in the aquifer water and precipitates iron sulfide on the well tubulars and gas injection nozzles. Accumulation of iron sulfide has caused many operational problems.

Lab results indicated that iron sulfide scale deposited on the inside wall of the well tubulars. The scale was uniform with a thickness that increased from 0.025" above the gas injection point to 0.25" at the well head. The composition of the scale changes with the length above the gas injection point. Just above the gas injection point, the scale was identified as FeS whereas close to wellhead, the scale was identified as FeS2. Acid solubility varied across the length of tubing. In areas where there is FeS, acid solubility in 20 wt% was 85–90 wt%. On the other hand, acid solubility was only 3–5 wt% in areas where FeS2 was present. Experimental results showed that 20 wt% could be used to remove a portion of the scale, however a suitable hydrogen sulfide scavenger should be added to the acid. Several non-acid formulae were tested and some of them were effective in dissolving acid-insoluble scale.

Unlike typical types of oilfield scales, iron sulfide is present in different species. The chemical structure of these species affects the method that should be used to remove this scale. This study addresses various types of iron sulfide and methods to remove and prevent the formation of this type of scale.
Fully Coupled Geomechanics in a Commercial Reservoir Simulator
Authors: Stone Terry , Bowen Garfield , Papanastasiou Panos , Fuller John
Published: December 2007

Oil recovery operations are seeing increased use of integrated geomechanical and reservoir engineering to help manage fields. This trend is partly a result of newer, more sophisticated measurements that are demonstrating that variations in reservoir deliverability are related to interactions between changing fluid pressures, rock stresses and flow parameters such as permeability. Several recent studies, for example, have used finite-element models of the rock stress to complement the standard reservoir simulation.

We discuss current work on fully coupling the geomechanical elastic/plastic rock stress equations to a commercial reservoir simulator. This finite difference simulator has black-oil, compositional and thermal modes and all of these are available with the geomechanics option. In this paper, the focus is on the implementation of the stress equations into the code. Some work on benchmarking against an industry standard stress code is also shown as well as an example of the coupled stress/fluid flow. Our goal in developing this technology within the simulator is to provide a stable, comprehensive geomechanical option that is practical for large-scale reservoir simulation.
Enhanced Oil Recovery from Oil Fields with Bottom Water
Authors: Zakirov S. , Yulmetjev T. , Zakirov E.
Published: December 2007

A significant number of developed oil fields in the world possess bottom water and almost all reservoirs have edge water. Correspondingly water-oil zones can be of a large dimension. Oil recovery under bottom or edge water presence is characterised by the low efficiency of recovery: first by a high water cut that leads to a low oil recovery factor. This paper presents results of the research designed to improve recovery under these conditions.
Integrating Geomechanics and Geophysics for Reservoir Seismic Monitoring Feasibility Studies
Authors: Vidal S. , Longuemare P. , Huguet F.
Published: December 2007

Seismic measurements acquired at different stages in the life of a reservoir can monitor the fluid distribution over production time. Changes in saturation, pore pressure and stresses, induced by reservoir production may influence the process of wave propagation in rocks. The variations in mean effective stresses, due to changes in mean stress or /and pore pressure, are not always integrated in a proper manner. We present here a methodology to evaluate what is the contribution of a geomechanical approach on the computation of seismic velocities. This methodology has been used for the monitoring of an underground gas storage site of Gaz de France, the French gas Supply Company. Successful results illustrate the importance of integrating geomechanics with geophysics to validate real sonic data from DSI.
Perforating Requirements for Sand Control
Authors: Venkitaraman A. , Behrmann L. A. , Chow C. V.
Published: December 2007

This paper presents an improved approach to selecting perforation parameters (charge type, shot density and phasing) for sand-control applications that takes into account both laboratory and field data. Laboratory experiments have shown that perforation-generated rock debris can induce gravel-pack impairment, thus leading to a decline in gravel-packed perforation productivity. Previously published analytical models for predicting gravel-packed well performance relied on field data analyses and back-calculations of gravel permeability in the casing/cement portion of the perforation tunnel and/or effective shot density. In all cases the damage was attributed to the casing/cement portion of the perforation tunnel with varying extent of effective shot density.

Distinction is first made on the perforation tunnel definition (open/collapsed) in the formation depending on the strength (consolidation) of the rock. The selection of perforation parameters (penetration, area open to flow in casing, shot density) for a conventional gravel pack involves a tradeoff between the pressure drop in the formation (resulting from formation damage, damage in the tunnel) and in the casing/cement portion of the tunnel filled with damaged gravel. In the case of fracturing while gravel packing, the perforation phasing and shot density play a dominant role in the inflow performance because these parameters dictate the perforation tunnel area open to flow in communication with the fracture. The benefits of oriented perforating as a technique for such completions is discussed. A comprehensive set of optimum perforating guidelines is provided for both types of completions (gravel packing and fracturing while gravel packing) for different rates (oil and gas flow).

Field data are presented from a well in Nigeria where this technique was used to improve gravel-pack completion efficiency in weak sand completions. Sample calculations are also provided.
Restriction of Gas Flow in Gas-Capped Oil Reservoirs: Field Experiences and Lessons to Learn
Authors: Lakatos I. , Lakatos-Szabó J. , Kosztin B. , Palásthy Gy.
Published: December 2007

The laboratory and field studies were focused on development of a well treatment technology which can be used for restriction of gas coning in the Algyö reservoir. The method is based on simultaneous placement of a polymer/silicate gel at the GOC and a supporting foam pillow into the oil bearing layer. Extensive laboratory studies were carried out to tailor the chemical system to the field conditions. The use of short chain alcohol in the gel-forming system and natural protein or glycerine as additive in the foam-forming solutions were in the focus of improvements. Special attention was paid to implementation of the technology. Two-point injection regime was elaborated to develop a horizontal barrier between the oil and gas bearing zones. Three projects consisting of five treatments, one of the a repeated one, were carried out between 1991 and 1999. The field test resulted usually partial success: the hydrodynamic measurement definitely shown that the barrier was correctly placed, the oil flow in the pay zone was not effected, the GOR temporarily improved and the WOR positively changed. The long-term observations, however, definitively prove that application of foam pillow instead of other supporting media increase significantly the chance to have measurable change in the unwanted gas production. On the other hand, however, the investment and the return rate of expenditure is not balanced even in those cases when the treatment is qualified as successful in technical sense. The Hungarian experts take a stand on extending the observation period for more cycles and to collect abundant arguments to continue or to suspend the R&D activities and the field projects.
The Use Of Photon Logs To Evaluate Gravel Packing
Authors: Neill B.E. , Haire J.N. , Lynch D.A. , Lawrence T.D.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

The application of gravel packing in the soft and unconsolidated sands of California has enjoyed increasing use in recent years. The practice has allowed sand-free production from zones that have been impossible to produce by other means.

The photon log is available to the oil industry to evaluate grovel packs prior to placing the well on production, enabling operators to determine the production, enabling operators to determine the success of grovel packing operations and take immediate action when needed. Failures due to incomplete packs are minimized, as (ire workover programs, damaged equipment, and lost production. programs, damaged equipment, and lost production. A complete pack is especially important in steam operations because of the long time span between completion and actual recovery of hydrocarbons.

The photon logs supply valuable information pertaining to the quality of the grovel pack to the pertaining to the quality of the grovel pack to the engineer in time to isolate and eliminate potential problems and improve the probability of a problems and improve the probability of a productive and trouble free completion. productive and trouble free completion. This paper will discuss the photon log, its presentation, interpretation, applications, and discuss field presentation, interpretation, applications, and discuss field examples.

Introduction

Sand control is a chronic problem for the petroleum industry. The cost of sand production is enormous in terms of damaged equipment, expensive workover programs, and lost production. The problem exists programs, and lost production. The problem exists to some degree in (almost every producing area throughout the world, and considerable effort is devoted to preventing sand production so that oil and gas can be profitably produced.

Sand control methods fall in two broad categories: limiting production rates to reduce the tendency of the sand to move and various means of either artificially consolidating sand or of mechanically propping the formation. propping the formation. Open hole gravel packing is one of the most common examples of the latter category.

Open hole grovel packs are extensively used in the soft and unconsolidated sands of California. A wirewrapped liner or a slotted liner is set across the productive zone, and sand or grovel is pumped into productive zone, and sand or grovel is pumped into the annular space between the liner and the formation. The section is usually underreamed prior to setting the liner, so that a thicker pack is provided between the formation and the liner.

The purpose of the packed annular space is to provide a permeable filter that will allow production provide a permeable filter that will allow production and prevent the formation sand from moving toward the well bore.
Important Considerations In Geothermal Well Log Analysis
Authors: Sanyal S.K. , Meidav H.T.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

The objectives of well logging, logging operation and log analysis in the geothermal industry are considerably different from those in the petroleum industry. This paper discusses these differences. Usually the commercial logging companies provide well logging services using essentially the same equipments and procedure used in the petroleum industry. This creates some problems in quality assessment, normalization and calibration of logs. This paper discusses those problems with examples from geothermal wells in the Imperial Valley, California; Raft River, Idaho; and Jemez Mountains, New Mexico. Interpretation techniques of well logs used in the geothermal industry are borrowed in toto from the petroleum industry. Because of the inherent differences in the nature of petroleum and geothermal reservoirs, log interpretation techniques now used for geothermal wells often provide inaccurate or erroneous answers. This paper points out many such problems in interpretation and suggests improved procedure, where possible.

Introduction

Well logging operation and log analysis in geothermal wells are considerably different from those in the petroleum industry. These differences can be grouped under three main areas: logging objective, logging operation and log interpretation. In this paper we discuss these differences.

Although the development of hardware and interpretation techniques for geothermal wells have begun in earnest, it will be many years before the new hardware and techniques become practical and standardized. At present, practically all the hardware and techniques in the geothermal well logging industry are borrowed in toto from the petroleum industry. This leads to many problems in logging operation, assessment of log quality and log interpretation in the geothermal industry. The purpose of this paper is to point out these problems and suggest remedies, where possible.
A Study on BEM Series of Pour Point Depressants and their Application in China
Authors: Zhang Fusheng , Xie Huizhuan , Dong Lijian
Published: December 2007

On the basis of analyzing composition of the crude oil in China, and according to mechanism of PPD reducing pour point, BEM series of PPDs which have a good pour point-reducing/viscosity-reducing effect for Chinese crude oils, have been developed and already used in Luning, Zhongluo, Pulin, Weijing, Donghuang and Donglin etc. long distance pipelines in China. After the crude oils transported by above-mentioned pipelines were treated by 50mg/kg of BEM series of PPDs, their pour points were reduced by 19□, 19.5□, 18□, 13.5□, 13□ and 20□ respectively, and their viscosities were reduced by 84.6%, 94.9%, 97.5%, 93.0%, 15.7% and 23.0%, in the same time, safety and flexibility of above-mentioned pipelines operation were all enhanced, and a tremendous economic benefit was obtained. The experimental result shows the following. Above waxing out temperature, violent pump shear and weak pipe shear can't affect the rheological behavior of the crude oil; during waxing out peak temperature, violent pump shear can deteriorate the rheological behavior of the crude oil but weak pipe shear can improve the rheological behavior of the crude oil. The main reason for above-mentioned phenomenon is the following. Above waxing out temperature, there are a very small number of wax crystals in crude oil, shear couldn't alter the structure of wax crystals; during waxing out peak temperature, there are a great number of wax crystals in crude oil, the structure of wax crystals was destroyed by violent pump shear and became the smaller wax crystals with the new active centres, then the smaller wax crystals interlocked by the new active centres and formed network structure with the larger strength, but weak pipe shear improved probably interaction between PPD molecules and wax crystals.
HEC No Longer the Preferred Polymer
Authors: Vollmer Daniel P. , Alleman David J.
Published: December 2007

Because of the problems associated with hydroxyethyl cellulose (HEC), several water soluble polymers were evaluated to replace HEC used to viscosify completion and workover fluids. The rheological properties and formation damage tendencies of these polymers were initially tested in dry form in various brines at elevated temperatures. Then the same polymers were prehydrated and re-evaluated in high dense brines (above 11.6 ppg). The results showed that HEC is no longer the preferred polymer.

The preferred polymer at equal polymer concentrations outperformed HEC in nearly all cases based on rheological and formation damage tests. The preferred polymer does not have a tendency to precipitate at elevated temperatures like HEC does in sodium and potassium chloride solutions and unlike HEC can viscosify brines containing a particular concentration range of zinc at any density. This polymer can be used to thicken formate brines where HEC is not recommended. As a result, the polymer was implemented into the field and successful case histories are presented.
The Effect Of Potassium-Salt Muds On Gamma Ray, And Spontaneous Potential Measurements
Authors: Cox J.W. , Raymer L.L.
Published: December 2007

Interpretations of the Gamma Ray and Spontaneous Potential curves generally assume sodium chloride to be the dominant salt in both the formation water and the mud filtrate. However, potassium-salt muds are increasingly being used by the oil industry. The potassium cation is significantly different from the sodium cation in its radioactive and electrochemical properties.

Natural potassium contains a radioactive isotope which emits gamma rays. Thus, the presence of potassium salts in the mud system may contribute to Gamma-Ray tool response. Since the Gamma Ray is used quantitatively in many geological sequences as an indicator of clay content, a way to correct for the effect of potassium in the mud column is desirable. Correction methods and charts based on Laboratory measurements and field observations are presented ba this paper.

The effect of temperature on the resistivity of potassium muds is also briefly discussed. From data available, it appears to be similar to that for NaCl muds.

On the bases of field odservations and laboratory work, the electro-chemical properties of potassium-chloride and potassium-bicarbonate muds and mud filtrates are discussed. Activity relationships are proposed, and the influence of these salts on the SP component potentials—namely, the liquid-junction, membrane, and bi-ionic potentials—is described.

Field examples are presented.
Chemical Systems for Water and Gas Control: Terminology, Evaluation Methods, Candidate Selection, and Expectations
Authors: Botermans C. Wouter , Dalrymple E. Dwyann , Dahl J. , Smith David
Published: December 2007

Because water and gas production often causes reservoir, wellbore, and surface facility problems, controlling water and gas production is a primary concern for hydrocarbon producers.

Problems associated with water and gas production have triggered many companies, research institutions, and universities to study water- and gas-production problems and develop chemicals and mechanical products that can control these problems. Because of the varieties of studies and products there are differences in terminology regarding these chemicals and areas of application. As a consequence, there are differences in expectations of these products, too.

In this paper, chemical systems are categorized as nonsealing and sealing. A standard testing procedure is suggested to help evaluate the performance of the different systems. Standardized testing should help the industry compare the performance of different systems under specific conditions. This paper will consider treatment techniques and operations to emphasize the importance of detailedjob design and operations planning. The paper ends with a summary of the economics involved in water and gas production. The method presented for determining a treatment's value can be used to evaluate the feasibility of water- or gas-control treatments.
Cyclic Steam Reservoir Model for Viscous Oil, Pressure Depleted Gravity Drainage Reservoirs
Authors: Jones Jeff
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

An improved cyclic steam reservoir model has been developed which allows the calculation of steam injection pressure and temperature as well as steam quality. In addition producing rates of oil and water are calculated with consideration given to cumulative effects of changing temperature, fluid levels, relative permeability, fluid viscosities, and fluid saturations. permeability, fluid viscosities, and fluid saturations. A comparison of calculated performance with field results of seven consecutive steam cycles in a well located in the Midway Sunset field in Western Kern County, California is presented. The calculated performance is in excellent agreement with field reports in virtually all areas.

The model is presented with simplified mathmatics by subsitituting empiracle equations for rigorous integral equations in several places. places

Introduction

The literature contains many reports of analytical and numerical reservoir models which may be used to calculate the response of a steam stimulation project.

Boberg and Lantz provide a very good method for tracing the temperature history of thermally stimulated wells. However, the method used to predict fluid production is limited to use in reservoirs with relatively light oil and high primary productivity.

Kuo, Shain, and Phocas do not address the performance of individual steam stimulation performance of individual steam stimulation cycles.

Seba and Perry address gravity drainage but also employ several limiting assumptions. These include constant hot zone radius and temperature and harmonic decline in oil production which may or may not match the decline in areas other than Yorba Linda.

Closmann, Ratliff and Truitt studied the effects of changing fluid saturations and crossflow in a cyclic well but simplified the heat loss mechanism and ignored gravity drainage.

Williamson, Drake and Chappelear treat the effects of transient relative fluid saturation and viscosity vs temperature in individual wells but the model is designed specifically for use in a numerical isothermal reservoir simulator.

In the above abreviated literature survey no provision was found for calculating injection pressure and the associated temperature. pressure and the associated temperature.
A Critical Review of Steamflood Mechanisms
Authors: Wu Ching H.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

A critical review of steamflood mechanisms is made based on published laboratory and field data. Qualitative and quantitative discussions are presented on the major steamflood mechanisms presented on the major steamflood mechanisms including steam drive and in-situ solvent drive; viscosity reduction and thermal permeability variation; and thermal permeability variation; and thermal expansion and gravity segregation. Interaction of these mechanisms is responsible for high steamflood displacement efficiency, enhanced oil production rate, and poor vertical steam conformance. A basic poor vertical steam conformance. A basic understanding of these mechanisms should assist petroleum engineers in the design, analysis, and evaluation of steamflood operation and mathematical simulation.

Introduction

Steamflooding is a proven secondary or tertiary method for recovering oil economically from some heavy oil reservoirs. It has potential applications as a secondary or tertiary method to recover light oils. Therefore, it is conceivable that steamflood mechanisms responsible for displacing oils or helping to displace oil from the reservoirs are of great interest and importance to the industry.

Steamflooding is a complex oil displacement process involving simultaneous heat, mass, and fluid transports. Although steamflood mechanisms associated with these complex transports may be well known to some people, reports on these mechanisms have been scattered in many publications over more than fifteen years and have not been readily available for most petroleum engineers. Willman, et al. reported experimental studies on the effect of some steamflood mechanisms, such as viscosity reduction, thermal expansion, and steam distillation, on the oil recovery. Johnson, et al. Quinones and Wu and Brown reported steam distillation of crude oils in porous media. Farouq Ali and Alikhan and Farouq Ali reported the effect of solvent slug on the oil recovery by steam and hot-water floods. Gates and Ramey, Dingley, and Braden presented the thermal viscosity reduction of some crude oils. Several articles reported the temperature effects on the oil-water relative permeabilities and on the absolute permeability.
Critical Cuttings Transport Velocity in Inclined Annulus: Experimental Studies and Numerical Simulation
Authors: Masuda Y. , Doan Q. , Oguztoreli M. , Naganawa S. , Yonezawa T. , Kobayashi A. , Kamp A.
Published: December 2007

In drilling horizontal wells and extended reach wells effective transport of drill cuttings is critical. Cuttings deposition and accumulation could lead to formation of deposit bed(s) inside the annulus, causing stuck drillpipe, eccentric borehole, poor penetration rate, etc. Experimental investigations reported in the literature previously focused on evaluation of cuttings transport performance in directional wells, as functions of mud flow rate, mud rheology, angle of inclination, pipe rotation, flow regime, etc. Empirical correlations were also developed for critical flow rate for different flow conditions.

In this study, both experimental investigation and numerical simulation were performed to determine the critical cuttings transport velocity in inclined annulus, for different flow conditions. Experiments were carried out in a flow-loop, using a novel data-acquisition-and-analysis system. The behavior of drill cuttings at both steady-state and unsteady-state flow conditions were recorded by a CCD video camera system. The captured images were then analyzed to obtain the velocity profile, the cross-sectional distribution, and average velocity of cuttings in annulus. Results from this experimental investigation were compared against those predicted by an unsteady-state cuttings transport numerical model developed in-house. The numerical model developed for the study allows for the interaction between the drill cuttings and drilling fluid, and follows broadly the two-layer model reported in the literature. It enabled the determination of pressure, fluid and cuttings velocity, fluid and cuttings concentration distributions inside the annulus at different times. The model was run using parameters similar to experimental conditions. Its results agree closely with experimental data for the critical flow rate for cuttings transport in inclined borehole, for the majority of cases.
A New Approach for Drill Bit Selection
Authors: Bilgesu H. I. , AL-Rashidi A. F. , Aminian K. , Ameri S.
Published: December 2007

Presented is a new methodology for selecting rotary drilling bits in an oil or gas well. Currently, bits are selected based on the performance of similar bits at offset wells. Parameters affecting a bit performance have a complex pattern. The relationship between formation properties, drilling fluid characteristics, bit design, and operational parameters in these patterns are not easily understood.

For a given field, studied were variables such as bit size, weight on bit, rotary speed, pump rate, drilled interval, and bit type. A three-layer artificial neural network was designed and trained with field data. This method incorporates computational intelligence to define the relationship between the variables. Further, it can be used to estimate other drilling parameters. The results indicate that the back propagation achitecture with two hidden slabs is the most effective neural network design for predicting the optimum bit type.

With the given data sets, this new model successfully predicted the bit types for several fields. For different data sets used in this study, the correlation coefficients for the predicted and field used bit types ranged between 0.857 and 0.975.
Two-Phase Relative Permeability Prediction Using a Linear Regression Model
Authors: Ibrahim M. N. Mohamad , Koederitz L. F.
Published: December 2007

In the absence of laboratory measured data or in the case when a more general representation of fluid flow in a reservoir is needed, empirical relative permeability correlations become useful. These correlations will also apply to simulation studies which require adjustments to the relative permeability values to account for grid effects. A linear regression model approach is employed to develop prediction equations for water-oil, gas-oil, gas-water, and gas-condensate relative permeability from experimental data. Use of the SPE CD-ROM has allowed a rapid and thorough data retrieval for this study; 416 sets of relative permeability data were obtained from published literature and various industry sources. Improved equations were developed for water-oil and gas-oil systems based on formation type and wettability. Additionally, general equations for gas-condensate and gas-water systems were formulated. Craig’s rule for determining the rock wettability has been modified to cover a wider range of relative permeability data currently available. Available data has increased significantly since the last published work in this area. The prediction equations are compared with previously published correlations where possible.
Optimizing Deliverability in Five Gas-Storage Reservoirs—Case Studies
Authors: Guoynes John , Squire Ken , Blauch Matt , Yeager Valerie , Yater John , Wallace Robert , Frame Russell , Clark Randall
Published: December 2007

Proper identification of damage mechanisms can improve stimulation techniques used in remediation of damaged gas-storage wells. Identifying damage mechanisms is only a beginning step in optimizing remediation. Determining the highest potential candidate wells and evaluating reservoir quality in the field can be just as crucial in optimizing a deliverability enhancement program. Historical data and reservoir/geological description analysis are required to properly rank candidates and design specific treatments to optimize deliverability potential. Once the diagnostic data and analysis are completed, an operator must begin the tedious process of applying the relevant data analysis to rank and validate the candidate wells’ potential and select one or more tailored treatment designs. Adequate well ranking is critical to ensure that APE dollars achieve maximum deliverability.

This paper illustrates case studies using a "Solution Team" a multidisciplined team process, in which over 75 wells were diagnosed and treated successfully. Rigorous damage-identification techniques and reservoir quality diagnostics were used in the five gas-storage reservoirs. Each case study produced damage-specific stimulation treatments based on the operator’s objectives to enhance existing deliverability. Follow-up evaluations were made at 1- and 2-year intervals to show how the team process that uses new, improved diagnostic practices can optimize deliverability.

In this study, damage mechanisms were identified with improved methods described in a previous Gas Research Institute (GRI) project. Damage in each well was quantified using welltest analysis and historical injection/withdrawal cycle performance matching. Log analysis, petrophysical data, geological data, wellbore imaging, and workover historical data were also gathered as treatment-design criteria. The deliverability improvement was quantified for each well using post-treatment diagnostics. The post-treatment evaluations were updated with 1- and 2-year follow-up evaluations. Each study incorporates several unique treatment options addressing a variety of damage mechanisms. Treatments were selected to produce the highest deliverability enhancement and maximize the operator’s return on investment.

Case Study 1 incorporates high-pressure jetting, tailored acidizing, and hydraulic fracturing techniques used in a deep high-permeability pressure-drive carbonate reservoir. Case Study 2 includes high-pressure jetting and damage-specific fluid treatments in two shallow water-drive clastic reservoirs. Case Study 3 incorporates hydraulic fracturing and high-pressure jetting of a shallow high-permeability pressure-drive clastic reservoir. Case Study 4 incorporates high-pressure jetting with foamed chemical treatments in a converted oil-carbonate reservoir.