bluuebunny/crossref_metadata_2025 huggingface dataset:
Some Case Histories of Remedial Work Resulting from Water Tracer Surveys
Authors: Ford Walter O.
Published: December 2007

Use of water tracer surveys to improve the over-all performance of waterfloods has long been recognized. Remedial work to water injection wells is becoming more important as the ratio of secondary reserves to primary reserves increases. While the proper use of tracer surveys does not necessarily mean a workover after every survey, too little significance is often given surveys where they could be of real productive use. This paper lists several case histories where tracer surveys were run and properly analyzed, resulting in thoughtful remedial work. What actual effect this remedial work had on production in the immediate area it also shown, when available.

Introduction

During the past 10 years, waterflood operators have tended to rely more on the use of quantitative water injection profiles. Though there are several different types and methods being used today to obtain this quantitative information, this paper will not discuss their principles or merits; rather, the assumption is made that quantitative water injection profiles can be run by a variety of service companies. Concern over what can and has happened from this point is the basis of this paper. This work was undertaken to present evidence from actual case histories where water tracer surveys were used, relied upon and found capable of being highly informative and of utmost practical value. During the search for such histories, an effort was made to stay away from examples where evaluation of remedial work could only be done at the injection well. Instead, examples are sought where direct production results confirmed proper water tracer survey evaluation of injection well remedial work, regardless of its success. This had a tendency to lead the author away from any but the most positive cases-where any cause for production changes, other than the success or failure of the remedial work, was extremely remote. Case History 5 is somewhat of an exception to this aim.

Case History 1

This case history was taken from a dolomite flood in which a northwest-southeast breakthrough system had been indicated (Fig. 1). Well 63 was converted to water injection in March, 1964. By June, 1964, Well 124 started to increase in water production with no increase in oil production (Fig. 2). This trend continued until Well 124 was producing over 100 BWPD and very little oil (2 to 3 B/D).

JPT

P. 791ˆ
Chromatographie Transport of Alkaline Buffers Through Reservoir Rock
Authors: Jensen J. A. , Radke C. J.
Published: December 2007

Use of relatively low-pH alkaline buffers, such as sodium carbonate or sodium silicate, is explored as a means for overcoming sodium/hydrogen ion-exchange delay in alkaline waterflooding. A local-equilibrium chromatographic model is outlined to describe the concentration velocities for injection of alkaline buffers into a linear porous medium that exhibits reversible sodium/hydrogen exchange. The theory predicts a buffer ion-exchange wave that is substantially faster than that for equivalent-pH sodium hydroxide solutions.

New experimental displacement data are presented for NaOH over a pH range from 11 to 13 and for 0.1, 0.5, and 1.0 wt% Na2CO3 flowing through a 1 wt% NaCl brine saturated Berea sandstone core at 50°C [122°F]. To permit a complete description of the system, column effluent concentrations are measured for sodium ions, hydroxide ions, H3-tagged water, and 14C-tagged carbonate. The experiments confirm that Na2C03 propagates through the Berea sand at a higher rate than NaOH. For example, at pH=11.4, Na2CO3 migrates with a velocity that is 3.5 times faster than NaOH.

Comparison of experiment with the ion-exchange chromatography theory shows good agreement. We successfully model the concentration histories of tritium-labeled water, total carbon, sodium, and hydroxide, all with no adjustable parameters.

This work establishes with both theory and experiment that buffered alkali significantly increases the propagation speed of hydroxide in reservoir sands in comparison with unbuffered alkali at equivalent sodium and hydroxide concentrations. Because lower-pH buffered alkali can also protect against rock dissolution loss, the validated reduction of buffer ion-exchange lag considerably improves the promise of the alkaline flooding process for field application.
Restored-State Core Analysis for the Hutton Reservoir
Authors: Wendel D. J. , Anderson W. G. , Meyers J. D.
Published: December 2007

Wettability is a major control parameter in multiphase flow analyses such as relative permeability. When such analyses are required, the native wettability of the reservoir must be maintained in the test plug. Unfortunately for laboratory analysis, cores are increasingly being taken with wettability-altering, oil-based, surfactant-containing muds. When a core's wettability has been altered by such drilling fluids, special procedures must be used to obtain proper analyses. First, the core plug must be cleaned of wettability-altering contaminants, then restored to reservoir wettability using uncontaminated native crude before accurate relative permeabilities can be obtained.

These special cleaning and restoration procedures are described for cores from the Hutton field, located in the U.K. sector of the North Sea. Plugs taken from Hutton cores were contaminated with invert-oil-emulsion drilling mud, which made them strongly oil-wet. By use of special cleaning methods, the surfactants from the drilling mud were removed, and the Hutton reservoir was subsequently shown to be only slightly oil-wet by use of relative permeabilities on plugs that had been restored to native wettability. It was also found that some sections of the Hutton cores were neutral-wet to slightly oil-wet even when clean, possibly because of the presence of coal.
CO2 Displacements of Reservoir Oils From Long Berea Cores: Laboratory and Simulation Results
Authors: Kremesec V. J. , Sebastian H. M.
Published: December 2007

CO2 displacements of three different reservoir oils from long Berea cores were conducted over a wide range of reservoir conditions with the pressure always above the slim-tube minimum miscibility pressure (MMP). The detailed performance of these displacements is simulated with a fully compositional simulator and the Redlich-Kwong (RK) equation of state (EOS). Oil recovery, GOR, and effluent profiles are compared with experimental results. The EOS is observed to be capable of predicting the phase-behavior transitions that occur in situ when miscibility is generated by multiple contacts. The good comparison between experimental results and the simulation has led to specification of a minimum data set for which an EOS should be able to predict before a priori simulations of displacement experiments can be made. The simulation assumed a stable one-dimensional (ID) displacement and that phase-behavior effects play the primary role in the displacement, but the number of gridblocks had to be adjusted in a rough correlation with the CO2/oil-viscosity ratio. Experimentally, final oil saturation and CO2 breakthrough time also correlate with the viscosity ratio. This suggests that viscous instabilities play a role in the experimental displacement, but in this geometry and under these displacement conditions, they can be simulated as numerical dispersion.
A Model of Limited-Entry Completions Undergoing Spherical Flow
Authors: Tang R. W.
Published: December 2007

Methods are presented in this study to determine wellbore and reservoir properties from limited-entry tests of very thick formations. This situation is often encountered in the Overthrust Belt and in geothermal operations. Most published limited-entry analysis methods assume the existence of three flow regimes during testing if wellbore storage is small. Theoretically, the regimes are (1) an early cylindrical flow period indicative of the opened interval, (2) a short spherical transition period, and (3) the late-time cylindrical data reflecting the entire productive thickness of the reservoir. The above methods are not applicable to very thick reservoirs because field data are often dominated by wellbore storage and a long spherical flow period.

In this study, an analytical solution is presented to analyze the wellbore-dominated and the spherical-flow periods. The model includes cylindrical skin of the open interval and wellbore storage. The solution and resulting type curves allow direct estimates of stimulation potential in situations where wellbore storage and spherical flow dominated pressure-transient behavior. Prior methods to determine damage require late radial-flow data and separate estimates of pseudoskin caused by flow convergence. Field examples from a gas-condensate reservoir and a geothermal well demonstrate the methods. The practical aspects of analyzing other limited-entry data are discussed.
Case Study of Gas Migration in the Wasatch and Mesaverde Formations of the Piceance Basin, Colorado
Authors: Mercer James C. , Ammer James R. , Frohne Karl-Heinz
Published: December 2007

The U.S. DOE Morgantown Energy Technology Center (METC) conducted a reservoir simulation study and an engineering analysis on gas migration for two tight lenticular sandstone units, the Wasatch formation and the Mesaverde group, in Garfield County, CO. The study quantified potential gas loss through migration from the Naval Oil Shale Reserve (NOSR) No. 3 (Fig. 1) to nearby producing wells located in the Rulison field and forecasted production for proposed NOSR No. 3 offset wells located at previously selected sites, offsetting commercial wells outside the reserve. After the reservoirs were characterized, production was forecasted by use of a reservoir simulator to history match actual production. A dual-porosity reservoir simulator, developed specifically for naturally fractured gas-producing reservoirs, and reservoir engineering calculations were used in the study. The study followed two extensive DOE field testing programs, a nearby multiwell experiment (MWX), and a special Mesaverde test well (1XM9) drilled in NOSR No. 3 (see Figs. 1 and 2). These DOE field tests provided geologic information and values for reservoir parameters that control production from this unconventional gas resource. In addition to the results from the two field experiments, the study used a detailed geologic analysis and production data from nearby industry wells to characterize the producing formations.
Rate Dependence of Unstable Waterfloods
Authors: Sigmund P. , Sharma H. , Sheldon D. , Aziz K.
Published: December 2007

Viscous fingering is part of the flow mechanisms that are operative in waterflooding and in a wide range of EOR methods. This work presents a laboratory and computer model analysis of the viscous-fingering dynamics that develop when a less mobile fluid is immiscibly displaced by a more mobile fluid in a permeable medium.

Physical experiments of horizontal fluid displacements conducted in a rectangular bead pack show that the amplitude/frequency character of the wave-like fingers that form depends on flow rate and mobility ratio. The nature of these wave-like features is shown for two viscosity ratios and several displacement rates. Spatial frequency domain analyses of finger shapes at fixed time intervals were conducted on digitized records of the laboratory experiments. The results of these analyses indicate that fluctuations comprising the fingered zone have a wave number corresponding to a maximum growth rate. The analyses suggest that the amplitude of flow fluctuations can be characterized by a root mean square (RMS) growth rate that is linear in time. Finite-difference solutions of a set of two-dimensional (2D) flow-in-porous-media equations were made to exhibit similar frontal instability. The linear growth rate of the mixing zone suggests that fractional flow relationships can provide an adequate and practical method of representing space-averaged two-phase flow variations for many reservoir engineering applications.
Downhole Solids Control: A New Theory and Field Practice
Authors: Hayatdavoudi A.
Published: December 2007

The primary objective of this paper is to show the effects of total solids content on size distribution of cuttings and the penetration rate (ROP) of the insert bit in hard rock and shale drilling. The secondary objective is to introduce a new "power index" theory that relates the cutting size to total power input to the rock, hydraulics of a solids separator, and a hydraulic grinding index.
Solids-Conveyance Dynamics and Shaker Performance
Authors: Lal Manohar , Hoberock L. L.
Published: December 2007

No comprehensive mathematical models are available that can predict solids conveyance and shaker fluid handling capacity for arbitrary solids in a specified drilling fluid. This paper addresses the solids loading problem and presents an analytical approach to the design of shale shakers, based on a dynamic model for solids conveyance off the screen and fluid flow through the screen. First, the solids loading is derived as a function of shaker geometry, solids-conveying speed, bit penetration rate, hole size, drilling fluid flow rate, particle size distribution of drilled solids, and screen opening size. Second, the solids-conveyance model is developed, based on the physics of the problem, accounting for the adhesive forces resulting from wet solids. The effect of various parameters, such as vibration pattern and normal acceleration on solids conveyance, is discussed. The solids-conveyance model can give the optimum set of shaker design parameters for efficient solids conveyance off the screen. For a given shaker, the solids conveying speed predicted by the model can also be used to obtain the flow capacity of the shaker in the presence of solids. Experimental and field results relevant to this study are also discussed.
Surfactant Transport Through Porous Media in Steam-Foam Processes
Authors: Lau H. C. , O'Brien S. M.
Published: December 2007

Experimental and theoretical studies show that the transport of steam-foam surfactants through reservoir sands can be substantially retarded as a result of cation exchange between the surfactant solution and the formation clays. Results, however, show that a high injected salinity favors surfactant propagation by displacing divalent cations faster and by reducing partitioning when divalent cations are present.
Sweep Improvement in CO2 Flooding by Use of Foaming Agents
Authors: Casteel J. F. , Djabbarah N. F.
Published: December 2007

This study has two objectives: (1) to screen and select foaming agents for specific CO2 floods and (2) to determine the effectiveness of foam in improving sweep efficiency in CO2 flooding. Foaming agents were evaluated on their ability to produce ample, lasting foam and to have low loss from adsorption on reservoir rock and decomposition at reservoir conditions. Foaming agents that performed well in shaking, blender, long-term stability, and high-pressure stability tests were selected for core-flow experiments. The stability test results demonstrated that foaming agents are reservoir-specific. The extent of the loss depends on the foaming agent, reservoir fluids, reservoir lithology, and reservoir conditions.

The core-flow experiments involved the simultaneous injection of CO2 into two waterflooded Berea cores. The cores were arranged in parallel and had different permeabilities. The test temperature and pressure were constant and above the critical conditions for CO2. Three types of core-flow tests, involving injection of CO2 to displace oil, injection of alternate slugs of CO2 and brine, and injection of foaming agents, were conducted. The foaming agents were injected before CO2 injection and after CO2 had displaced oil from the more permeable core.

The results show that in-situ foam generation is an effective method for improving CO2 displacement efficiency. Foam was most effective when the foaming agent was injected after CO2 displaced the oil from the more permeable core. The improved sweep efficiency was caused by the tendency of the foam to be generated preferentially in the more permeable core. The foam increased resistance to flow in this core and caused more CO2 to flow through the less permeable core. The second injection method is also more applicable to field implementation.
A New Correlation for the Cementation Factor in Low-Porosity Carbonates
Authors: Borai A. M.
Published: December 2007

The use of common correlations for the cementation factor, m, has led to discrepancies between log interpretation and actual test results in several tight carbonate formations offshore Abu Dhabi. While logs indicate high water saturations, production tests resulted in unexpected dry hydrocarbons.

The existing common correlations for carbonates yield constant m (Archie) or an increasing m with a decrease in porosity (Shell formula). In the carbonates found offshore Abu Dhabi, m decreases with decreasing porosity. Based on core and log data from five formations in 14 structures, a more representative correlation for m has been derived. This new correlation successfully eliminates the discrepancies between log and test results. Examples confirming the validity of the new formula are included.
Compositional Gradients in the Anschutz Ranch East Field
Authors: Metcalfe R. S. , Vogel J. L. , Morris R. W.
Published: December 2007

Experimental data from analyses of more than 20 recombined fluid samples show that a significant compositional gradient exists in the Anschutz Ranch East field. The gradient can be correlated as a linear function of depth. Using the correlation, an engineer can estimate compositions for any bottomhole location and then use other methods to estimate fluid properties and/or depletion performance.
Compositional Effects in Gravity-Dominated Nitrogen Displacements
Authors: Ypma Jan G. J.
Published: December 2007

In this paper, the role of compositional effects during secondary, gravity-stable nitrogen displacements in (dipping) light-oil reservoirs, such as the Statfjord reservoir in the Brent field, is discussed. Displacements of both a gas condensate from the top of the Statfjord hydrocarbon column and a volatile oil from a more downdip location in this column are discussed. The main compositional effects in such vaporizing-gas-drive-type displacements are the following.

The displacing vapor at the displacement front is not nitrogen, but a rich hydrocarbon gas liberated from the reservoir fluid upon contact with nitrogen. This hydrocarbon vapor is miscible with the reservoir fluid in the case of the gas condensate, but just fails to develop miscibility in the case of the oil-like reservoir fluid. The remaining oil is a degassed, more viscous oil than the original reservoir fluid.

In addition to equation-of-state (EOS) programs, both a compositional simulator and an analytic, dispersion-free model for vaporizing-gas drives have been used to quantify the effect of phase behavior on recovery efficiency. These compositional calculations indicated that next to the phase behavior, the longitudinal dispersion level and, in the case of the oil-like fluid, the degree of gravity segregation at the displacement front are key factors determining displacement efficiency. Results are presented of a systematic investigation into the relative contributions of phase behavior, physical dispersion, and gravity drainage to the recovery process. A comparison of predicted results and slim-tube and coreflood experiments is made. The extent to which these laboratory experiments might be representative for reservoir-scale displacements is also briefly discussed.
A New X-Ray Absorption Method for Measurement of Three-Phase Relative Permeability
Authors: Oak M. J. , Ehrlich R.
Published: December 2007

A new X-ray absorption method has been developed for simultaneous measurement of water, oil, and gas saturations during three-phase relative permeability experiments. This method permits saturation measurements as a function of axial position in a core for both transient and steady-state conditions.
Muldoon Field: An Evaluation of Behind-Casing Pay Zones in a Freshwater Environment
Authors: Hull R. L. , Johnson D. E.
Published: December 2007

The wells in the Muldoon field, first drilled in 1952, produce from shallow, high-porosity, freshwater Eocene sands. Production may be either oil or gas. Vintage Petroleum Corp. purchased the field in June 1984 with the objective of reworking the existing wells and increasing field production through the selective plugging of zones and the opening of new zones currently behind casing. To accomplish this, it was necessary to determine oil/water contacts, water zones, and potential pay zones as yet unproduced. Serious obstacles to this objective were lack of adequate logs [most wells had only an electric log (ES) or induction electric log (IES)] and the very fresh formation waters (1,500 ppm chlorides).

These obstacles were overcome through application of state-of-the-art "formation evaluation through casing." An induced gamma spectrometry log, compensated neutron log, and gamma ray log were used to evaluate the formations accurately and indicated not only oil/water contacts and watered-out zones, but also oil and gas zones.

Because of the favorable production results, the structure has been re-evaluated and seven new well locations have been chosen. This paper will discuss the interpretation and results of the three wells that were initially evaluated and show how this re-evaluation has led to an increase in field production.
Performance of Equipment Used in High-Pressure Steam Floods
Authors: Owens M.E. , Bramley B.G.
Published: December 2007

The high temperature and pressures encountered in steam flooding have necessitated the use of premium and, in many cases, unique equipment. Field results from three steam flood installations give an insight as to the performance of high-pressure equipment when subjected to the accompanying high temperatures. Performance of the equipment and factors entering into the selection of equipment for steam flood installations are discussed.

Introduction

Recovery of low-gravity, high-viscosity crude oil from relatively shallow reservoirs is becoming feasible through the application of steam flooding. Pan American Petroleum Corp. initiated a pilot steam flood with a 5.36 million Btu/hour, 1,500-psi steam generator at the Winkleman Dome field in west central Wyoming in March, 1964. After one year of operation, this steamer was replaced with a larger unit capable of 12 million Btu/hour at 2,500 psi. Two other pilot steam flood projects were started at that time using 12 million Btu/hour, 2,500-psi steam generators, one at the Salt Creek Shannon field and another at the Fourbear field, both in Wyoming. This paper discusses the equipment used in high-pressure steam flooding and reviews some of the problems encountered in the application of the equipment. Where determined, a suggested solution is presented. The discussion follows the conventional flow of water and steam: water treating. steam generation, steam control and transmission, wellhead and subsurface equipment, and instruments and data collection (Fig. 1). The steam generation and transmission equipment discussed in this paper has been designed for 2,500-psi saturated steam service. Maximum operating conditions have been 1,875 psi and 626F.

Water Treating

Successful operation of steam generation equipment depends primarily upon a good source of water combined with an effective water treating system. Experience gained in the past two years of pilot steam flood operation indicates the majority of steamer down-time is caused by water treating problems.

The quality of raw water dictates the amount of treating required; therefore, it is imperative that the best water available should be used. Some criteria for a good quality raw water are:

the water should be free of oil or filming amines; dissolved gases such as O2, C2 and H2S, should be absent or at least present only in trace amounts; total hardness should be low; and suspended solids concentration should be low.

Since the quality requirements of water used in a single-pass steam generator are extremely stringent, it is unlikely that the available raw water can be used without some form of treatment.

JPT

P. 1525ˆ
Catalytic Effect of Heavy Metal Oxides on Crude Oil Combustion
Authors: Drici Ouarda , Vossoughi Shapour
Published: December 2007

Differential scanning calorimetry (DSC) and thermogravimetric analysis (TGA) were applied to crude oil combustion in the presence and absence of metal oxides. It was found that the effect of titanium oxide was similar to that of silica and alumina. Vanadium, nickel, and ferric oxides behaved similarly in enhancing the endothermic reactions. In the presence of a large surface area such as with silica, the surface reactions are predominant and unaffected by the small amount of metal oxide present. Kinetic analysis of the DSC curves revealed that the activation energies and the frequency factors of the hydrocarbon and the coke combustion reactions, estimated for all the metal oxide additives including silica and alumina, followed the same normal compensation trend. The crude oil mixture of 90% ferric oxide was the only exception to this trend.
Use of Cumulative-Production Type Curves in Fracture Design
Authors: Elbel J. L. , Sookprasong P. A.
Published: December 2007

When a fracture treatment is designed, the expected increase in productivity or production rate is usually considered. Because production rate varies with time, an economic evaluation based on a production rate increase at a given time can be misleading. A better method of economic evaluation would use the cumulative production after some time period. This can be determined by reservoir simulators that incorporate the effect of propped hydraulic fractures. These simulators are not readily accessible to everyone, however, and are time-consuming and expensive to run. Several authors have stated that cumulative-production type curves can be made with data generated by dimensionless-pressure type curves for a fractured well with infinite fracture conductivity. This paper shows how cumulative-production type curves for finite fracture conductivity can be generated from published dimensionless reciprocal-rate type curves or from reservoir simulators. A simple graphic procedure can then be used to give the combinations of fracture lengths and dimensionless fracture conductivity that will show the desired cumulative production or production rate at some particular time. Charts and simple equations also are given that will allow a quick estimate of the proppant volume required for the various fracture geometries needed for the desired production. This would form the basis for optimizing the fracture treatment. When used with methods to determine fracture fluid volumes for various fracture lengths, the minimum cost for any desired production can be made.
Automatic Custody-Transfer System at Lake Pelto, Louisiana
Authors: Tansil John T. , Moor Leslie M.
Published: December 2007

The production system and custody-transfer system for the Sun Oil Co.-Pure Oil Co. installation at Lake Pelto La., was designed to operate continuously and automatically to achieve maximum throughput with a minimum requirement for on-lease storage and manual attendance. Suitable equipment was installed in such a manner that all the wells can be controlled from a central production platform; their produced liquids can be processed continuously and delivered to the custody-transfer system with the assurance that all oil delivered is of merchantable quality. The custody-transfer system was designed to deliver oil automatically from the production system to the gathering line, using positive-displacement meters and related equipment for the measurement function.

Introduction

Everyone is aware that the cost of oil production and handling facilities in water locations is quite high. These costs have been trimmed a little through the years by more careful engineering, by prefabrication, and even by some attempts at mass production; today, however, the greatest hope for cost reduction lies in the use of newer improved oil-handling techniques.

For this reason, in planning the facility to serve the Sun Oil Co. operated Louisiana State Lease 2620 in the Lake Pelto field, the design section was instructed to utilize automatic control systems and equipment wherever the application could be of economic or operational advantage.

The full portent of this charge was realized when initial engineering estimates were summarized to showthat a continuous throughput design, utilizing automatic custody transfer, would reduce oil storage requirements 60 to 70 per cent compared to a conventional system andthat the additional cost of the equipment and controls necessary to make the operation continuous and completely automatic was approximately the same as the cost of 1,000 bbl of storage in this water location.
The Statistical and Dimensioniess-Time Analog to the Generalized Dykstra-Parsons Method
Authors: Enick Robert M. , Reznik Alan A. , Miller Robert A.
Published: December 2007

Statistical and graphic representation of the recently generalized Dykstra-Parsons vertical stratification analysis are presented for the injection constraints of constant rate and pressure. Waterflood performance parameters include the instantaneous reservoir water cut and the vertical coverage as functions of dimensionless real time and injection constraint for a complete range of mobility ratios and permeability variations. The layer permeabilities are log-normally distributed.

The real times associated with the two injection constraints are reduced to dimensionless forms by use of reference times that are both rational and different for the respective injection constraints. The introduction of real time or dimensionless real time reveals the dramatic distinction in performance characteristics between the constant-injection-rate (CIR) and constant-injection-pressure (CIP) cases. Elimination of the time basis between the waterflood performance parameters masks the distinction between the two injection constraints and reduces the graphic solutions to those originally presented by Dykstra and Parsons without the inclusion of their severely restrictive recovery correlation.

The relationship between complete vertical coverage and dimensionless time is shown to be a simple analytic function of the permeability variation statistic and the number of beds for the case of constant injection pressure.
Protective Coatings for Corrosion Control in Production Operations
Authors: Robinson R.M.
Published: December 2007

Introduction

Coatings are used in production operations for identification purposes, for appearance and for corrosion control. The role of coatings as a corrosion-control measure in production operations has become an increasingly important one during the last several years. There are a number of reasons for this, the primary one, of course, being costs. Labor and equipment-replacement costs have risen sharply during the past decade, but the price of the prime product, oil, has not risen accordingly. Another reason for increased use of coatings is the presence of severer corrosive environments such as those encountered in offshore operations. Also, more operators have become aware of the savings and benefits to be gained from the proper selection and use of coatings.

When used for corrosion control, coatings serve as barriers to separate the metal from the corrosive environment. In production operations, the corrodents and physical conditions are almost innumerable. Consequently, a myriad of coatings and coating types have been offered to the industry, and new ones are being marketed almost daily. Many tapes and sheathing materials also are available for use as corrosion barriers. Tapes and sheathing materials are discussed later in conjunction with the services for which they are used.

Present-day coatings belong to many generic types. Some "dry" by solvent evaporation, some dry by oxidation while others dry, or "cure", by polymerization. Oxidation or polymerization may be catalyzed by chemical additives or by baking at elevated temperatures. Relative resistances of the coating materials vary greatly between, and even within, generic families. Therefore, it becomes the corrosion man's problem and responsibility to select the proper coating for a particular corrosive environment.
Efforts to Develop Improved Oilwell Drilling Methods
Authors: Ledgerwood L.W.
Published: December 2007

During the past three decades, the oil industry has expended increasing efforts seeking improved drilling tools or systems to reduce drilling costs. The total cost of these efforts is unknown, but it certainly amounts to tens of millions of dollars. Most of the "new" systems that past and present investigators have sought to develop actually are old public information.

In seeking to implement new-system concepts, investigators have tested the following: impact at frequencies ranging from 6 to 300 cycles per second; electrical, mechanical and hydraulic means of actuating percussors; bit rotary speeds up to 2,000 rpm; electric and hydraulic bottom-hole means of rotating bits; bottom-hole machines with power outputs up to 400 hp; shock waves; explosives; high-velocity pellets; flame; arc; grinding wheels; abrasive jets; erosion by high-velocity gases;chemical attack; electric current; magnetic waves; retractable rock bits; reelable drill pipe; continuous coring with reverse circulation; and automation of drilling rigs. Table 1 shows how these investigations are grouped for discussion purposes in this paper.

In spite of these efforts to discover new and improved systems, rotary drilling maintains its economic leadership. Undoubtedly, rotary drilling costs will continue to be reduced by rigid application of the best available technology and by development of new rotary technology. In view of the extensive past development programs, however, significant long-range improvement appears to be a research, not a development problem. Research must postulate and prove theories and principles governing various subsurface rock-failure processes pertinent to both rotary and new systems. Also, research must produce physical and engineering data relative to these processes. When such information is available, earth boring will graduate from an art to a science. Major improvements in rotary drilling can then be expected, and the systematic evolution of an improved drilling method can be initiated-with a strong probability for success.
Additive Effectiveness and Contaminant Influence on Fluid-Loss Control in Water-Based Muds
Authors: Nyland T. , Azar J. J. , Becker T. E. , Lummus J. L.
Published: December 2007

The proper fluid-loss control of drilling muds becomes more difficult when drilling high-temperature, high-pressure formations. Chemical additives for reducing fluid loss differ considerably in effectiveness; in turn, these differences vary, often unpredictably, with temperature and pressure. This paper discloses the results of static-filtration experiments that compare capabilities of various additives to minimize filtrate invasion at elevated temperatures when the mud contains certain common contaminants. The effects of mud weight, high-temperature aging, and the presence of asphalt on mud fluid loss were also investigated.

The additives selected for study were WL-100™, carboxymethyl cellulose (CMC), Dextrid™, CC-16™, Resinex™, and several asphalts. Certain combinations of these were also studied. The contaminants used typify those originating from drilled formations: sodium chloride, calcium sulfate, sodium sulfate, cement, and Rev Dust.

On a cost-equalized basis, a combination of Dextrid and CC-16 was found to be a good additive for controlling fluid loss at high temperatures and pressures regardless of whether contaminants were present. The additives WL-100 and Dextrid were also effective.
The Effect of Instability on Relative Permeability Curves Obtained by the Dynamic-Displacement Method
Authors: Peters Ekwere J. , Khataniar Santanu
Published: December 2007

A study was undertaken to investigate how instability would affect the oil/water relative permeability curves obtained by the dynamic-displacement method. In this method, stable Buckley-Leverett displacement theory is used to calculate relative permeability curves from coreflood data. Thus, to obtain the true relative permeability curves by the dynamic-displacement method, the coreflood must be stable. However, the method frequently has been applied to unstable corefloods. The consequence of this application of the method has not been previously reported.

We compared oil/water relative permeability curves from steady-state and dynamic-displacement experiments at several levels of instability. The results showed that the dynamic-displacement relative permeability curves deviated significantly from the steady-state curves as the degree of instability increased. This observation indicates the need to scale laboratory relative permeability measurements to account for instability. To obtain representative relative permeability curves for numerical modeling of a reservoir, laboratory displacement experiments should be conducted at the same degree of instability as that in the reservoir.
Progress Review of the K&S Carbonated Waterflood Project
Authors: Hickok C.W. , Christensen R.J. , Ramsay H.J.
Published: December 2007

A carbonated waterflood process which comprises the treatment of a hydrocarbon reservoir with controlled amounts and concentrations of carbon dioxide is one of the newer methods of increasing oil recovery being used in a commercial field application. The process consists of the treatment of a crude-oil reservoir with controlled amounts and concentrations of carbon dioxide (CO2) or solutions of carbon dioxide. To achieve this end, the techniques of water flooding are combined with the injection of carbonated water into a reservoir during the early stage of the flood. The K and S project is the first commercial application of this process.

Water injection was initiated on the and project in Feb., 1958, and CO2 injection started in April of the same year. The carbonation period should be completed by April 1, 1960. At this time it is too early to predict the ultimate oil recovery from the project. However, several notable accomplishments have been recorded to date. When the project was initially developed, several areas were noted to be highly water productive due to a previous dump flood. These areas subsequently have produced considerable oil, indicating that additional recovery has been gained. Second, injectivity has been increased to two to four times the rate of neighboring input wells which have not been subjected to the carbonated water process. And third, in 1959 more oil was produced than has been previously produced for the total primary life of the property.

Introduction

This paper is a progress report outlining the accomplishments and difficulties experienced to Jan. 1, 1960, at the K and S project. The K and S project is located 10 miles north of Bartlesville, Okla., and consists of three contiguous leases totaling 240 acres. There are 35 input wells and 24 producing wells spaced on a regular 10-acre five-spot pattern, as shown in Fig. 1. Water injection was initiated in Feb., 1958, and CO2 injection started in April of the same year. CO2 injection will be completed by April 1, 1960. Water injection will continue throughout the life of the project. The property was acquired in June, 1957. With 80 per cent of the working interest, Oil Recovery Corp. acts as engineering consultant and supervises the application of the process. Wellsville Oil Co., with the remaining 20 per cent of the working interest, is flood operator of the joint venture.
Use of Potassium/Lime Drilling-Fluid System in Navarin Basin Drilling
Authors: Holt C. A. , Brett J. F. , Johnson J. B. , Walker T. O.
Published: December 2007

This paper presents a case history of Amoco Production Co.'s use of potassium-lime mud (KLM) for drilling a series of wells in the Navarin basin. The remote location, logistical concerns, environmental regulations, and the high cost of the operation mandated that the project be carefully planned. Planning, however, was hampered because the nearest offset to any of the wells was more than 100 miles [160 km] away. This paper describes the planning, implementation, and results of the mud system used to drill the wells. It includes a matrix of tests used to define further the nature of KLM, presents the methods used to run the system while the wells were drilled, and describes the results of using the mud in the basin. Navarin basin experience suggested that KLM should be considered when clay inhibition is needed and moderate bottomhole temperatures (BHT's) are expected.
Predicting the Build/Drop Tendency of Rotary Drilling Assemblies
Authors: Jogi P. N. , Burgess T. M. , Bowling J. P.
Published: December 2007

Today, the majority of rotary bottomhole assemblies (BHA's) for directional control are designed through practical experience and trial and error. This approach can produce satisfactory results when a great deal of local experience can be drawn on. It can prove costly, however, during drilling in a new area because of the increased number of trips and correction runs. This paper demonstrates how a BHA model can be used to predict the directional inclination tendencies of rotary assemblies, thus limiting the uncertainty associated with the traditional BHA design techniques.

The technique is demonstrated on data from 17 bit runs from three wells on the same platform in the Gulf of Mexico. Predicted tendencies from BHA descriptions alone proved to be accurate (to an error of ±0.1°/100 ft [±0.03°/10 m]) in more than half the cases. The uncertainty of other predictions appeared to depend on the hole gauge. The distance taken for a BHA to reach a stable build/drop rate after the start of a bit run depends on the length of the BHA. This factor must be taken into account in the prediction of BHA performance.
The Application of Slim-Hole Completions to Secondary Recovery
Authors: Hinckley Jack
Published: December 2007

Introduction

Oil men are probably as tired of hearing about rising costs as they are of experiencing them. It goes without saying that we are vitally concerned with discovering less expensive methods of developing production, both primary and secondary. Slim-hole completions are believed to be a partial solution to this problem. Contrary to what many people think, slim-hole completions are not new. One operator, the Stekoll Petroleum Corp., has been completing wells with 2 7/8-in., or smaller, casing for 18 years. The purpose of this paper is to review this development and discuss its application to secondary recovery. Slim-hole completions should not be confused with slim-hole drilling. The primary purpose of a slim-hole completion is to save money. Quite often, the cost of drilling a small-diameter hole is more than that of a slightly larger one. In such cases, it is defeating the purpose of slim-hole completions to insist on the drilling of a smaller hole.

History of Development

In 1942, Stekoll initiated a water flood in the Bolton field of Montgomery County, Kans. The Bartlesville sand in this area lies at a depth of approximately 1,000 ft, and the property was developed as a flowing-type water flood. The completion cost of wells with 4-in. casing, which size was customary for the area, was compared with the cost of completions using 2-in. casing. This study indicated that the additional capital investment resulting from completing with the larger casing would be very substantial when applied to the entire property. Because of this and because of the shallow depth of the wells, it was decided that 2-in. line pipe would be used for casing in both producing and injection wells. As a result, total development costs were reduced by 33 1/3 per cent.

A short time later, another Kansas water flood was developed on wider spacing, and producing wells were pumped instead of being flowed. It was here that the company first attempted to pump inside 2-in. casing using a reciprocating string of 1-in. line pipe as tubing and rods. An insert-type bottom-hole pump was adapted successfully. Operating costs over the past 15 years have been equivalent to those of conventional wells.
A Correlation of Dewpoint Pressure With Fluid Composition and Temperature
Authors: Nemeth L.K. , Kennedy H.T.
Published: December 2007

The investigation presented in this paper was performed to develop a relationship between the dewpoint pressure of a hydrocarbon reservoir fluid and its composition, temperature and characteristics of the heptanes-plus fraction. This is part of an over-all program to develop correlations for the essential properties of reservoir fluids with the composition, temperature and pressure. In all, 579 dewpoint pressures, determined experimentally on 480 different condensate systems along with their compositions and temperatures, were obtained from the literature and from previously unpublished sources. Compositions were expressed in terms of mol fractions of methane through heptanes-plus, nitrogen, carbon dioxide and hydrogen sulfide, and the molecular weight and specific gravity of the heptanes-plus fraction. Distribution of the samples assured a good representation of most of the major oil-producing areas in the world.

A multiple regression analysis program written for the IBM 7094 digital computer was used to compare numerous equations and to calculate their coefficients. The final equation containing 11 coefficients resulted in an average absolute deviation of 7.4 percent for all the samples. Segregation of data on the basis of one or more variables did not materially improve the results. The correlation developed is useful in predicting the dewpoint pressure of condensate reservoir fluids from variables normally measured in the laboratory.

INTRODUCTION

In any discussion of the dewpoint of hydrocarbon mixtures, it should be noted that there are two kinds of dewpoints which, must be distinguished. The first type, or normal dewpoint, usually occurs at low pressures as dry gas is compressed to the point where liquid first forms. The second type, sometimes called the retrograde dewpoint, occurs when a gas mixture containing heavy hydrocarbons in solution is depressured until a liquid is formed. The first type, as applied to condensate mixtures, would normally be below atmospheric pressure and would be of no interest in reservoir performance. The second type is of great significance in interpreting reservoir behavior and is the property referred to throughout this paper.

Laboratory measurement of dewpoints is laborious, expensive and subject to many errors, and it is desirable to find a reasonably accurate method to predict dewpoint pressures from the composition and other readily available properties normally measured on the fluids. A possible method of calculating dewpoint pressures would be to employ a set of equilibrium ratios (K-values).1 However, the K-values themselves depend on composition as well as temperature and pressure; presently their use adds nothing to the accuracy of predicting dewpoints. If future correlations provide a significantly better method of estimating K-values for heavy hydrocarbons, they may be of greater use.