bluuebunny/crossref_metadata_2025 huggingface dataset:
Polymer Trial Using Horizontal Wells: Conceptual Well Completion Design and Surveillance Planning Aspects
Authors: Mukmin Mukmin , Al-Azri N. , Al-Mjeni R. , Morshidi A. , Douma S.
Published: April 2012

This paper describes key aspects related to conceptual well completion design and surveillance planning for an evolving polymer field trial in the South of Oman. An existing field was developed with mostly horizontal production wells drilled at the top of the oil column to deliver high oil production rates. The production of this medium-heavy oil is supported by a strong bottom drive. However, many wells have observed premature water breakthrough resulting in high water cuts and large volume of unswept oil. Polymer flooding using a horizontal well approach is proposed to improve sweep efficiency. If successful, this alternative approach has the potential to significantly improve oil recovery in the subject field.

Because of the significant investment required and novelty of the process (i.e. heavy oil, strong bottom water drive combined with the use of horizontal wells), a field trial is planned to address some of the development risks. Key subsurface risks and uncertainties include: possible polymer losses to the underlying aquifer, loss of effective matrix polymer injectivity, lack of polymer injection conformance along the horizontals and poor sweep efficiency. A number of activities were performed to help design the field trial and reduce some key risks and uncertainties i.e. laboratory coreflood, subsurface study, injectivity test and field visit to analogue field.

The study concluded horizontal polymer injectors placed between the existing producers and slightly deeper than the centre of the oil column is optimum to recover the unswept oil. Polymer injector with Smart completion is proposed to mitigate the lack of conformance along the horizontals. A detailed surveillance plan is critical to identify the required tools and technologies to facilitate data gathering and well intervention activities during the field trial. Proposed surveillance technologies are DTS, Multi Pressure Sensors (MPS) and saturation logging. Observation wells with glass reinforced epoxy (GRE) pipe are planned to get a higher accuracy and deeper investigation of the formation saturation. These activities will be supported by calibrated subsurface simulation models as new data is available to address the trial performance, as well as, better predict full-field performance.
Polymer Flooding in a Large Field in South Oman - Initial Results and Future Plans
Authors: Al-Saadi Faisal Salim , Amri Badr Ali , Nofli Sami , Van Wunnik John , Jaspers Henri F , Harthi Said , Shuaili Khalfan , Cherukupalli Pradeep Kumar , Chakravarthi Ravula
Published: April 2012

In heavy oil reservoirs, water flooding leaves behind unswept hydrocarbon volumes due to unfavourable mobility ratios resulting in low ultimate recoveries. Increasing the viscosity of the injected water using polymer improves the water-oil mobility ratio resulting in improved recovery factors. This paper discusses for a large field in South Oman the successful implementation of a polymer flood project, the early results of Phase I and the planned expansions to Phase II and Phase III. Following a number of field trials and a series of laboratory studies, a full-field polymer project was implemented in the field in 2010. One of the key risks identified prior to starting the project was poor polymer injectivity. However, initial field results showed better injectivity than expected. Surveillance efforts are in progress to understand the better injectivity. The data analysis so far indicate that wellbore clean up due to polymer injection, improved as a result of improved mobility ratio and small scale induced fractures in some injectors are contributing to the improved injectivity. These factors enabled injection of more volumes of polymer than planned resulting in improved volumetric sweep efficiency and producer response. Results to date are encouraging, as after over a year of polymer injection, the oil gain due to the polymer flood is higher than expectation. Based on the initial results of Phase I, expansion phases II and III are being planned. Phase II is based on utilizing the available ullage in the system to accelerate the oil gain from polymer; it requires a relatively small upgrade of the existing infrastructure and surface facilities. Phase III is a full-field polymer flooding expansion combined with an intense infill drilling. Currently, a study is in progress to optimize the development concept for the infill wells and polymer flooding of Phase III.
New Frontiers In EOR Methodologies By Application Of Enzymes
Authors: Jain Tarang , Sharma Akash
Published: April 2012

Enhancement of the amount of oil recovered from existing reservoirs is slowly becoming a standard procedure during the operational life of an oil well. The need for a cost effective and efficient method led to EEOR or Enzyme Enhanced Oil Recovery, a process based on the application of enzymes. It is basically a subset of Microbial EOR in which co-injected micro organisms or nutrients are used for reduction of oil viscosity.

EEOR offers a wide array of applications due to efficient surfactant mechanism and utility in both oil-wet and water-wet systems. Moreover its cost effectiveness has led to applications in marginal oil fields, for example in the Mann Field in Myanmar this led to an increase in production from 10 bopd and 109 bwpd to 17 bopd and approximately 1636 barrels of incremental oil was produced from one of the wells within 9 months of enzymatic treatment.

Use of engineered enzymes not only counter the risk of using nutrients over a long period of time but also enhance the recovery process by accelerating desired biochemical reactions between a substrate, water medium and formation. Enzymes tend to reduce viscosity and inter facial tension to a remarkable extent. Moreover they are not consumed during the reaction and act even in low concentrations. Certain strands of enzymes like Acinetobacter sp.6A2 have the ability to degrade alkanes with a chain length ranging from C10 to C40 and reduce paraffin content.

The present paper effectively summarizes the utility of EEOR through its various advantages. Enzymes are the key to the future which eradicates the long term use of microbes. Moreover its utility in marginal fields and paraffin reduction abilities make it highly suitable for countries like India which greatly suffer from such issues.
Improve Oil Recovery for Heavy Oil by Chemical Treatment Implementation as an Alternative, Cast Study Bentayan Field
Authors: Mucharam Leksono , Nugroho Wisnu , Wibisono Kunto
Published: April 2012

The Bantayan field, located on the northeast flank of the South Sumatra basin, was delineated by surface geological studies in the late 1920s as a narrow northwest trending anticlinal structure bisected by numerous northeast trending transbasinal normal faults. In 1932, a discovery well encountered productive upper Talang Akar sandstones which yielded 800 BOPD of paraffinic based crude with a pore point of 115 degrees F. Until year of 1982, only 12 delineation wells were drilled, from which 12 potentially productive sandstone units were obtained within a structural area of 27 sq km. Further evaluation from other new 8-well, it was found that this reservoir system is considered a complex system.

In the Bentayan Field, the hydrocarbon oil is deposited in the Talang Akar depositional complex, with the best overall reservoir quality which is relatively thick and well-connected, fine-to coarse-grained, and cross-bedded fluvial sandstones3).

Oil properties of this reservoir currently have oil gravity of 17° API and viscosity of 82.2 cp1) at the reservoir temperature. Based on the above oil properties, Bentayan field is considered as a heavy oil reservoir, and so far only 14% of Bentayan oil reserve has been produced. Since 80 years of the discovery, reservoir pressure of Bentayan field has declined from 1696 psi to about 1035 psi, and oil production has also declined significantly. In order improve the oil production, water injection has been implementing to several wells throughout the field, however the oil production is still declining.

To reduce viscosity of the oil in the reservoir, application of steam huff n puff could not work very well for improving oil production in this field. This could be caused by high reservoir pressure and also by depth of the reservoir. Since this field is considered as a mature field where all production wells have been producing with high water cut, all conventional efforts to improve oil production would be difficult to success. Implementing chemical EOR, in this case, is the best way to increase oil production. However, the selected chemical must be able to lower the oil viscosity, lower IFT and alter the oil wettability. In this case, a special chemical treatment (SEMAR) had been implemented in this field using huff n puff technique. Since, the reservoir is under strong water drive, the injection of SEMAR can also improve oil production of other surrounding wells nearby. These phenomena are very interesting to be evaluated for further steps in fullfield chemical EOR implementation.
Improved Oil Recovery by Chemical Flood from High Salinity Reservoirs-Single-Well Surfactant Injection Test
Authors: Hsu Tzu-Ping , Prapas Lohateeraparp , Roberts Bruce L. , Wan Wei , Lin Zhixun , Wang Xiaoguang , Budhathoki Mahesh , Ben Shiau B. J. , Harwell Jeffrey H.
Published: April 2012

Reservoirs containing very high total dissolved solids and high hardness make the design of a surfactant polymer (SP) flood extremely difficult because surfactant tends to precipitate and separate under these conditions. Beside divalent ions, Ca2+and Mg2+, the presence of iron in the brine can be a challenging issue. Different surfactant formulations incorporating cosurfactants and co-solvents are studied. These formulations minimize viscous macroemulsions, promote rapid coalescence under Winsor Type III conditions, and stabilize the chemical solution by reducing precipitation and phase separation. The optimal surfactant formulations are further studied in one-dimensional sand packs and coreflood tests using Berea sandstone, reservoir oils, and brines at 42°C. Using similar injection protocols, 0.5 PVs surfactant/polymer, oil recoveries ranging from 50 % to 70% of the residual oil (Sor) after waterflooding are observed. The level of surfactant loading is less than 0.6 wt%. A single-well test is conducted to confirm laboratory results in situ in the presence of high-salinity formation water containing 165,000 mg/L total dissolved solids (TDS). The test is considered to be a technical success and confirms the effectiveness of a high-salinity surfactant-polymer formulation composed of 0.23 wt% of surfactant and 1,800 ppm of polymer loading. Approximately 87% of the residual oil was mobilized.
Laboratory Investigation of the Injectivity of Sulfonated Polymer Solutions into Carbonate Reservoir Rocks
Authors: Han Ming , Zhou Xianmin , Alhasan Fuseni B. , Zahrani Badr , AlSofi Abdulkareem M.
Published: April 2012

The injectivity of sulfonated polymer solutions in carbonate reservoir rocks was investigated to evaluate the performance and feasibility of the polymer in the porous media under reservoir conditions. A sulfonated polyacrylamide with a sulfonation degree of 25 mole% was selected for this study. Polymer solutions at 0.1 wt% and 0.2 wt% in seawater were injected into carbonate core plugs with a permeability ranging from 100~600 mD at reservoir temperature and pressure. Two critical parameters, the resistance factor and residual resistance factor, were obtained in the tests. The resistance factor represents a quantitative measure of the mobility reduction during the propagation of the polymer solution in the porous media, while residual resistance factor is a measure of permeability reduction after the polymer treatment. The resistance factor is 5 ~ 8 at a flow rate of 0.5cc/min for 0.1 wt% polymer solution. The residual resistance factor is 1.24 ~ 1.34 for seawater injection after the polymer injection. Meanwhile, the resistance factor is 50~65 at a flow rate of 0.5cc/min for 0.2 wt% polymer solution. The residual resistance factor is 1.48~2.17. It is found that resistance factor increases significantly with flow rate, while residual resistance factor decreases with flow rate. The investigation of adsorbed polymer layer based on the permeability reduction provides insights into the performance of the selected polymer in the carbonate cores.
Evaluation of Long-Term Gas-Hydrate-Production Testing Locations on the Alaska North Slope
Authors: Collett T.S.. S. , Boswell R.. , Lee M.W.. W. , Anderson B.J.. J. , Rose K.. , Lewis K.A.. A.
Published: April 2012

The results of short-duration formation tests in northern Alaska and Canada have further documented the energy-resource potential of gas hydrates and have justified the need for long-term gas-hydrate-production testing. Additional data acquisition and long-term production testing could improve the understanding of the response of naturally occurring gas hydrate to depressurization-induced or thermal-, chemical-, or mechanical-stimulated dissociation of gas hydrate into producible gas. The Eileen gashydrate accumulation located in the Greater Prudhoe Bay area in northern Alaska has become a focal point for gas-hydrate geologic and production studies. BP Exploration (Alaska) Incorporated and ConocoPhillips have each established research partnerships with the US Department of Energy to assess the production potential of gas hydrates in northern Alaska. A critical goal of these efforts is to identify the most suitable site for production testing. A total of seven potential locations in the Prudhoe Bay, Kuparuk River, and Milne Point production units were identified and assessed relative to their suitability as a long-term gas-hydrate-production test sites. The test-site-assessment criteria included the analysis of the geologic risk associated with encountering reservoirs for gas-hydrate testing. The site-selection process also dealt with the assessment of the operational/logistical risk associated with each of the potential test sites. From this review, a site in the Prudhoe Bay production unit was determined to be the best location for extended gas-hydrate-production testing. The work presented in this report identifies the key features of the potential test site in the Greater Prudhoe Bay area and provides new information on the nature of gas-hydrate occurrence and the potential impact of production testing on existing infrastructure at the most favorable sites. These data were obtained from well-log analysis, geological correlation and mapping, and numerical simulation.
Design of SWTT at High Salinity and High Temperature: Where are the Limits?
Authors: Mechergui Aymen , Romero Carolina , Ganzo Alejandro
Published: April 2012

The single well tracer test SWTT is a well established method to measure Residual Oil Saturation (ROS) in-situ. The large radius of investigation makes the SWTT a well suited method to evaluate ROS reliably compared with other techniques such as coring and logging.

The partitioning tracer is chosen depending on three basic parameters: reservoir temperature, reservoir salinity and live oil partitioning behavior. These properties control the extent of the hydrolysis reaction that takes place during the shut-in time period to generate the secondary non-partitioning tracer. At high temperature and high salinity (HT/HS), the partitioning coefficient Kd and hydrolysis reaction rate Kh can be significantly high, therefore risking complete reaction of the partitioning tracer and loss of test results reliability.

This paper presents a simulation study carried out to evaluate the feasibility of performing SWTT at HT/HS and help the selection of tracers at these conditions. Using experimental design, a series of SWTT numerical simulations were performed to assess the impact of high Kd and Kh on ROS measurement and interpretability of tracer profile.

Results indicate that conventional rules used for SWTT design would need to be modified or adapted in order to have an interpretable signal from the test. The paper presents also the impact of modified shut-in time and drift on the quality of test.
Crude Oil, Brine Salinity and Sandstone Interaction - Nanoscale Resolution
Authors: Al-Aulaqi Talal , Fisher Quentin
Published: April 2012

Many laboratory experiments and field tests have shown improved oil recovery by manipulating wettability of reservoir rocks. Until recently, most of what is known about crude oil/brine/rock (COBR) interactions has been inferred from contact angle measurements, which are considered to be macro physical parameters. Advancement of surface analytical tools enables us to characterize structures of crude oil deposition as a function of brine salinity, temperature and asphaltene content at nano-scale resolution.

The non contact mode of vertical scanning interferometry (VSI) is utilised as a tool to study COBR interaction for the first time. A borosilicate glass surface used as a substrate for crude oil deposition as a function of brine salinity, temperature and asphaltene content. The main results it provides the first direct evidence of thickness of adsorption oil is largely minimised as NaCl brine salinity diluted. Furthermore the temperature shows to enhance the accumulation of oil adsorption. Three dimensional view of crude oil morphology indicate the absence of asphaltene content generate wider valleys features than the asphaltenic oil morphology. The oil solvency generates a dendritic crude oil adsorption when crude oil is mixed with heptane whereas a very thin layer when crude oil is mixed with toluene. A detail analysis of surface profile is conducted using two and three dimensional parameters.
Rock Rupture as Affected by Fluid Properties
Authors: Scott P.P. , Bearden William G. , Howard G.C.
Published: April 2012

This paper concerns the rupture or breakdown of rock formations as related to drilling, completing, and stimulating production of wells, and comprises data compiled from a study of literature and records of treatment of oil and gas wells, and from tests conducted in bores drilled into rock cores and outcrops of rock. Results of the investigation indicate that the internal pressure to rupture cylinders of rock and to break-down rock formations surrounding a bore in the earth is dependent upon the extent of intrusion of fluids, the position of bedding planes, the ratio of internal to external diameter, the tensile strength of rock, and magnitude of confining pressure, and is independent of the size of bore, degree of fluid saturation, and temperature of rock within practical limits.

It is concluded that the mathematical relationship of pressure in bores and stresses in the surrounding rock must not be limited by the simplifying assumptions of homogeneity, isotropy, and impermeability; that the incidence of lost circulation of drilling fluids to induced fractures may be reduced by preventing intrusion of fluids into the small intrinsic fractures along weak bedding planes; and that the magnitude of the breakdown pressure of wells to be treated may be lowered by removal of mud cake.

Introduction

The purpose of this paper is to present and discuss the results of tests which may serve to broaden the understanding of the phenomena of rupture or breakdown of rock and thus contribute to the improvement of the techniques for drilling and completing wells, including such operations as preventing lost circulation, stimulating production, and placing cement.

Since the early recognition of the possibility of rupturing rock adjacent to a well by fluid pressure, the distribution and magnitude of stresses around a well and the internal pressure to cause failure have been expressed mathematically by application of the principles defining the elastic and inelastic behavior of thick-walled cylinders of a homogeneous, isotropic, impermeable material. In either the elastic or plastic state, if the conditions of homogeneity, isotropy, and impermeability were the normal characteristics of rock, there would be no reason to question the validity of the above principles when applied to rock.
Properties of Linear Waterfloods
Authors: Rapoport L.A. , Leas W.J.
Published: April 2012

The original Buckley-Leverett theory has been extended and a more detailed formulation of the waterflood behavior in linear horizontal systems is presented. Particular consideration has been given to the evaluation of capillary pressure effects and differential equations permitting an explicit evaluation of these effects have been derived. On the basis of the developed theory it is recognized that the flooding behavior is dependent upon the length of the system and the rate of injection. At the same time it has been determined that systems of different lengths yield the same flooding behavior if the injection rates and/or the fluid viscosities are properly adjusted or "scaled." It has also been found that the sensitivity of the flooding behavior with respect to rate and length decreases as any one of these factors increases in value and that for sufficiently long systems and high rates of water injection the flooding behavior becomes independent of rate and length, or "stabilized." To such stabilized conditions the theory formulated by Buckley and Leverett is applicable. A number of laboratory flooding tests have been made and good agreement has been found between theory and experimental observations. The experimental results are discussed and it is shown that under field conditions the flooding behavior is usually stabilized. As a result of these findings a procedure is indicated for evaluating field performances either on the basis of tests performed with commonly available core samples or by means of calculations using relative permeability data.
Origin of the Electric Potential Observed in Wells
Authors: McCardell W.M. , Winsauer W.O. , Williams M.
Published: April 2012

The mechanism by which an electrical potential difference is developed between two salt solutions separated by shale is shown to be a consequence of the electrical double layer of the shale surfaces. A mathematical derivation is presented to show the dependence of the potential on the shale characteristics and on the concentration of the salt solutions. The equations developed describe adequately the potential-concentration behavior of a long shale core. The equations also describe the variation of potential of sand-shale mixtures with variation of clay content. Ion adsorption is an important factor in the development of the surface charge on the shale, and electrical resistivity and ion transference number data are employed to estimate the increase of surface charge with concentration. Since the potential is shown to be dependent on the characteristics of the particular system, water salinities estimated from the potential log by previously proposed methods may be low in some cases.

Introduction

That the electric well log exists today may be attributed to the ingenuity of the Schlumberger brothers, who adapted to the logging of wells techniques which were originally developed as surface prospecting methods for the location of ore bodies. Empirically, it was found that the potential curve of the electric log usually gave values for clean sands which were negative with respect to the values for shales. It was suggested that the potential was responsive to porosity. It was postulated, in explanation, that the potential was the sum of a streaming potential, which differed for sands and shales, and of an "electro-chemical" potential of undetermined origin.

Mounce and Rust in 1943 showed that the streaming potential is small in most cases and that the potential is generated by a process in which shale and a salinity difference play essential parts. Dickey, in the same year, concluded that the potential is dependent upon adsorptive properties of reservoir rock.
Calculations of Unsteady-State Gas Flow Through Porous Media
Authors: Bruce G.H. , Peaceman D.W. , Rachford H.H. , Rice J.D.
Published: April 2012

The problem of unsteady-state gas flow through porous media leads to a second-order non-linear partial differential equation for which no analytical solution has been found. In this paper a stable numerical procedure is developed for solving the equation for production of gas at constant rate from linear and radial systems. An electronic digital computer is used to perform the numerical integration using an implicit form of an approximating difference equation. Solutions are presented in graphical form for various values of dimensionless parameters. The solutions are compared with the laboratory study of gas depletion in a linear system.

Introduction

Production of fluids from porous rock reservoirs is essentially a transient process. Transient gradients develop as soon as production begins, and further withdrawals continue to cause disturbances which propagate throughout the reservoir, each adding in some way to the prior ones.

A correct mathematical analysis of this behavior is complicated by the fact that the transient or unsteady-state flow of compressible fluids must be described by difficult second-order partial differential equations. As a practical matter, three distinctly different cases arise:Flow of single-phase liquidFlow of gasesMultiphase flow

The first of these has been found to give a linear second-order equation similar to the well-known heat flow equation.

Solutions of Equation (1) for both linear and radial flow are available in several forms.

Although a number of approximate solutions have, been proposed, each is limited in value by the associated simplifying assumptions.

Inasmuch as the analysis of transient flow is limited to liquid systems, a solution of the second case is necessary if further progress is to be made in studying underground fluid movement. For this reason a solution of Equation (2) was undertaken by means of numerical integration of approximating difference equations.
Application of the Material Balance Equation to a Partial Water-Drive Reservoir
Authors: Van Everdingen A.F. , Timmerman E.H. , McMahon J.J.
Published: April 2012

The present paper contains a method which combines the material balance equation with the water influx equation to obtain reliable values for the active oil originally in place and a quantitative evaluation of the cumulative water influx. The method is illustrated by an application to a reservoir without original gas cap. In the absence of an original gas cap, results may be obtained using only field production and pressure data, PVT analyses, and a minimum of subsurface information.

Characteristics of Reservoir and Reservoir Fluids

Production in the field under review is obtained from the top of the Wilcox formation of Eocene age, at a depth of approximately 8,100'Ft subsea. The structural map, Fig. 1, shows that the accumulation, half elliptical in shape with the long axis in east-west direction, is trapped to the north and on the upthrown side of a normal fault. A number of east-west faults with additional minor faulting in random directions are found in the general area, and seismic information and production performance indicate in this particular case the existence of a second fault a short distance downdip, with a strike more or less parallel to the fault controlling the accumulation. It is estimated that 1,830 acres were originally underlain by oil and that the maximum thickness of the original oil column, about 37 ft, was only slightly greater than the maximum thickness of the oil-bearing sand. Maximum net sand thickness was estimated at approximately 26 ft. From logging and subsurface information the gross sand volume has been placed at 37,400 acre-ft, which reduces to about 27,500 acre-ft after probable non-productive intervals have been deducted. The following table presents laboratory analyses data for the Wilcox sand cores.
Permanent-Type Well Completion
Authors: Huber T.A. , Tausch G.H.
Published: April 2012

Very encouraging progress has been made in the development of the permanent-type well completion which decreases considerably the cost of completions and workovers and aids in the acquisition of reliable reservoir information at low cost. Completion and remedial operations are performed with tools which pass through the well tubing. Perforating and plug-back operations can be done with the tubing in place and do not require pipe-handling equipment.

Because of the many advantages afforded by this method, development work is going forward in anticipation of ultimately being able to use it to perform all usual well completion and work over operations. Effort is also being directed to the development of a more permanent type of lift equipment suitable for use with the permanent-type well completion.

Introduction

The permanent-type well completion is one in which the tubing and well-head are set in place only once in the life of the well and the completion or remedial work is performed through the tubing with a tubing-type perforator, a retrievable tubing extension, and other wire-line tools. This new type completion has made possible the saving of one to two days' rig time in the completion of each of several hundred wells during the past two years, and use of equipment developed for this type of completion has resulted in a 75 per cent reduction in costs of certain types of workovers. In addition, the more reliable indication of the commercial value of a reservoir and the more accurate general reservoir information made possible promise to be of even greater value in oil recovery than the reduction of costs for completions and workovers.

Recently, several wells were worked over by using the retrievable tubing extension suspended on a swab line to plug back with cement and then perforating a higher producing interval with the tubing-type perforator, thus opening the way for complete through-the-tubing workovers which may be performed without pipe-handling equipment or mud. Those items attendant to the use of pipe-handling equipment and mud, such as board matting, rig substructure, and pits, were also eliminated.

There are indications that the elimination of drilling mud during completion and workover operations will frequently give increased well productivity, as plugging of the perforations will not occur.
Bubble Formation in Supersaturated Hydrocarbon Mixtures
Authors: Kennedy Harvey T. , Olson Charles R.
Published: April 2012

In many investigations of the performance of petroleum reservoirs the assumption is made that the liquid, if below its bubble-point pressure, is at all times in equilibrium with gas. On the other hand, observations by numerous investigators have indicated that gas-liquid systems including hydrocarbon systems, may exhibit supersaturation to the extent of many hundred psi in the laboratory. Up to the present, there has been no reliable data on which to judge the actual extent of supersaturation under conditions approaching those existing in petroleum reservoirs.

The work reported here deals with observations and measurements on mixtures of methane and kerosene in the presence of silica and calcite crystals. Bubbles were observed to form on crystal-hydrocarbon surfaces in preference to the glass-hydrocarbon interface or to the body of the liquid. Statistically, it was found that the number of bubbles formed per second per square centimeter of crystal surface was a function of the supersaturation only, and the function was evaluated graphically.

Supersaturations were observed up to 770 psi, under which condition bubbles formed quickly and with considerable violence. With decreasing degrees of supersaturation, the frequency of bubble formation became less, until at 30 psi supersaturation and lower, no bubbles were observed to form, even though the observation at 30 psi was continued for 138 hours. It was found that silica and calcite crystals had identical effects, within experimental error, in accelerating the formation of bubbles, and that small amounts of water and crude oil had no effect on the results.

It is shown that the maximum supersaturation that can exist in a reservoir may be calculated from the data presented and from the area of the rock surface. It is also shown that the number of bubbles formed in the reservoir, in order of magnitude, may be calculated for any rate of pressure decline imposed on the reservoir by production. The bearing of the number and distribution of bubbles on reservoir performance is discussed.
Pressure Gradients in Natural Gas Reservoirs
Authors: Cornell David , Katz Donald L.
Published: April 2012

Procedures for computing turbulent flow of gas in steady state near the well bore and a graphical method for predicting unsteady state laminar flow at distances from the well have been combined to compute pressure gradients in gas reservoirs.

Methods are discussed for predicting single and multiple transients at constant flow rate in an infinite reservoir, predicting constant flow rates in a finite reservoir, reproducing and interpreting back pressure test data, and prediction of the behavior of a closed-in gas well. An example of the graphical method is given for a single transient and the results are compared to a published analytical solution. A typical calculation of the pressure gradient in a reservoir and the production of gas is made starting with data from a back pressure test.

Introduction

The calculation of pressure gradients throughout a gas reservoir at any point in its production history is a complex problem involving turbulent flow near the well bore and unsteady state flow of the gas from the reservoir. The problem is complicated further by the variety of boundary conditions that may be imposed upon the flow. Such boundary conditions include finite or infinite reservoirs, constant or variable rates of production, constant or varying bottom hole pressures, complex initial pressure distributions throughout the reservoir, and pressure maintenance through cycling.

In addition to these problems there are the practical difficulties associated with natural gas reservoir analysis. These might include:variations in the permeability and porosity throughout the formation,variations in the thickness of the formation,communication of the producing formation with other producing zones,radial variations in permeability due to influx of drilling fluid, acidizing, or the buildup of liquid in the formation around the well,partial penetration of the producing zone,water flood, and many others.

These problems will be considered eventually. In the meantime, it is necessary to present methods of handling the case of radial flow through a homogeneous, regular, producing stratum to a single well uncomplicated by other factors.
A Quantitative Analysis of the Electrochemical Component of the S.P. Curve
Authors: Wyllie M.R.J.
Published: April 2012

The relationship between the electromotive force (E.M.F.) across a shalebarrier and the concentrations of sodium chloride solutions on either side hasbeen investigated.

It is shown that the action of a shale barrier is analogous to a glass membraneseparating two acid solutions of different hydrogen ion concentrations. Theshale behaves as a sodium electrode and is responsive to the activities of thesodium ions in the two solutions in such a way that the potential can becalculated by means of the Nernst equation. This conclusion is confirmed bylaboratory experiments.

In a borehole the total E.M.F. of a shale cell is the algebraic sum of thepotential across the shale and a boundary potential. The relationship betweentotal E.M.F. and the resistivity ratio of two sodium chloride solutions isindicated for a number of formation temperatures. The E.M.F. thus predicted isthen compared with the self potential read from an electric log and goodagreement is demonstrated.

Based on both the self potential and resistivity curves of the electrical log.a method is given for calculating connate water content in a bed havingintergranular porosity and containing both connate water and hydrocarbons.

Introduction

The first paper on electrical well logging by C. and M. Schlumberger and E.G.Leonardon in 1934 attributed the self potential curve principally to streamingpotentials, i.e. to electrokinetic effects. Almost immediately greatdifficulties were encountered in reconciling many of the curves they obtainedwith this interpretation, and a second paper by the same authors soon appeared.In this second paper self potentials were attributed to the combined effects ofstreaming potentials and electrochemical potentials, the electrochemicalpotential being considered the result mainly of the interaction of fluids ofdiffering salt concentrations, i.e. a boundary potential, and partly ofpotentials set up at the faces of impermeable materials. Some experimentsinvolving a gray clay for the impermeable material were quated.

T.P. 2511
Gulf of Mexico Floating Drilling Tender
Authors: Besse C.P. , Osborne G.W.
Published: April 2012

Drilling operations on the Gulf of Mexico continental shelf are followingtwo general plans. The first plan placed all buildings, equipment, andmaterials on a large platform while the second copies Lake Maracaibo drillingmethods by placing a minimum of equipment on the platform and using a floatingdrilling tender or drill barge anchored adjacent to the platform in an attemptto take maximum advantage of flotation in an effort to reduce costs.

A complete power rig, mud pits, pipe racks, and small auxiliaries have beenplaced on the platform as shown in Figure 1, to assure proper handling ofdrilling operations under the most adverse weather. This has the economicadvantages of eliminating the fabrication of a large structure, a materialreduction of rigging up time on each structure, and elimination of delay timeon equipment while quarters and equipment placed on the tender are being riggedup. These factors have certainly proved their economic value in drill bargeoperations in the Louisiana and Texas coastal area.

Naturally the heart of such an operation is the anchorage. This anchorage, topermit taking advantage of maximum economies, must hold the ship in arelatively fixed position under the following weather conditions:Winter northwestersSoutheasterly galesSevere rain squalls

In hurricane weather all operations must be suspended regardless of methodof operation and the floating tender will, if possible, be moved to a protectedlocation. However, in case of an emergency the floating tender should beprepared to swing with the wind and seas on a single anchor as there is considerable doubt that either ship oranchorage could withstand the severe strains imposed by fixed anchorage inhurricane weather.

Northwesters are reported to have developed wind gust velocities as high assixty miles per hour and steady winds of approximately forty-five miles perhour. Fortunately these winds do not travel a great distance over water beforearriving at our location, and, while they can possibly develop seasapproximately eight feet high, the waves are short and if taken on the bow orstern of a ship 250'Feet or more in length they should not present a difficultproblem.

T.P. 2590
Relation Between Pressure and Recovery in Long Core Water Floods
Authors: Breston Joseph N. , Hughes Richard V.
Published: April 2012

Conclusions drawn by previous research workers with respect to the relationbetween pressure gradients and/or velocity and oil recovery obtained bylaboratory water flood tests have been in disagreement probably due to variableprocedures and unnatural conditions and materials. The Bradford Laboratory ofthe Pennsylvania Grade Crude Oil Association as part of its secondary recoveryresearch program has conducted nineteen water floods on two long cores ofwidely differing characteristics in an attempt to clarify this relationship andmake it an aid in predicting flooding pressures in the field. Unlike previousresearch procedures the present experiments were conducted with the aim ofduplicating field conditions as closely as possible by using long unextractedconsolidated cores, a live crude, and natural brines for both flooding andconnate water content. Also, the pressure gradients and flooding velocitieswere representative of field conditions where similar sands were being flooded.Eleven floods on one core and eight floods on the other core showed increasedrecoveries and lower residual oil saturation with increased flood pressuregradients and flood velocities. A marked decrease in recovery was obtained fromboth cores at very low flood velocities. This pressure versus recoveryrelationship is shown to hold up to the point of water breakthrough and also upto the 100 and 1 produced water to oil ratio point.

Introduction

The possibility of water flooding oil sands was suggested by Carll of thePennsylvania Geological Survey in 1880. It is not known when the practice wastried intentionally for the first time, but its beneficial effects were notedin the annual production rate of the Bradford field as early as 1907. Thepractice was illegal in Pennsylvania until 1921. Early water floods in theBradford field usually consisted of shooting or splitting the casing secretlyto permit subsurface waters to enter the producing sands under hydrostatichead. As it was noted that the benefits of water flooding seemed to beproportional to the quantity of water dumped into the well many also began toutilize surface sources after the practice became legal. It was probably duringthe middle 20's before many producers realized that the pressurehead of thewater upon the producing sand determined the rate and quantity of water thatwould enter the sand. Hence, rate and quantity of production appeared to be adirect function of input pressures.

T.P. 2591
Evaluation Of Capillary Character In Petroleum Reservoir Rock
Authors: Rose Walter , Bruce W.A.
Published: April 2012

Improved apparatus, methods, and experimental techniques for determining thecapillary pressure-saturation relation are described in detail. In thisconnection a new multi-core procedure has been developed which simplifies theexperimental work in the study of relatively homogeneous reservoirs. The basictheory concerning the Leverett capillary pressure function has been extendedand has been given some practical application. Some discussion is presented toindicate the relationship of relative permeability to capillary pressure, andto provide a new description of capillary pressure phenomena by introducing theconcept of the psi function.

Introduction

For the purposes of this paper the capillary character of a porous mediumwill be defined to express the basic properties of the system, which produceobserved results of fluid behavior. These basic properties may be classified inthe following manner, according to their relationship to:The geometrical configuration of the interstitial spaces.This involves consideration of the packing of the particles, producing pointsof grain contact, and variations in pore size distribution. The packing itselfis often modified by the secondary processes of mineralization which introducesfactors of cementation, and of solution action which causes alteration of porestructure.The physical and chemical nature of the interstitial surfaces.This involves consideration of the presence of interstitial clay coatings, theexistence of non-uniform wetting surfaces; or, more generally, a considerationof the tendency towards variable interaction between the interstitial surfacesand the fluid phases saturating the interstitial spaces.The physical and chemical properties of the fluid phases in contact withthe interstitial surfaces.

This involves consideration of the factors of surface, interfacial and adhesiontensions; contact angles; viscosity; density difference between immisciblefluid phases; and other fluid properties.

Fine grained, granular, porous materials such as found in petroleum reservoirrock possess characteristics which are expressible bypermeability,porosity, andthe capillary pressure-saturation behavior of immisciblefluids in this medium.

These three measurable macroscopic properties dependupon the microscopic properties enumerated above in a manner which defines thecapillary character.

T.P. 2594
Behavior of Binary, Ternary, and Multicomponent Systems at States Similar to Those Encountered in Condensate Fields
Authors: Sage B.H. , Lacey W.N.
Published: April 2012

The growing background of experimental information concerning the volumetricand phase behavior of binary and ternary hydrocarbon systems is used as thebasis for a comparison of these systems with naturally occurring hydrocarbonmixtures under conditions representative of underground petroleum reservoirs.The qualitative and semiquantitative similarities and differences between thetwo types of systems are considered in reference to the possibilities andlimitations of using experimental data on binary and ternary systems forpredicting the volumetric and phase behavior of naturally occurring hydrocarbonmixtures of low molecular weight. The possible influence on such phase behaviorof water, hydrogen sulphide, nitrogen, and components of relatively highmolecular weight is discussed.

Introduction

During the past two decades much effort has been devoted to the study of thevolumetric and phase behavior of pure paraffin hydrocarbons and of binary andternary mixtures of these compounds. Many of these studies were carried outwith the direct objective of utilizing a knowledge of the detailedcharacteristics of binary and ternary mixtures of the lighter paraffinhydrocarbons for predicting the behavior of more complex mixtures. The abilityto make such predictions with accuracy would be of great value in petroleumproduction and refining. Although the behavior of the methane-propane systemserved at one time as a qualitative illustration of the probablecharacteristics of the more complex hydrocarbon mixtures found in nature, itfell fal short of requirements for quantitative predictions. The present paperendeavors to indicate the relation of the more recently accumulated informationconcerning the behavior of binary and ternary hydrocarbons to this problem. Indiscussing binary and ternary systems as examples pointing toward the behaviorof multicomponent systems no effort is made to present new methods ofpredicting the characteristics of natural hydrocarbon mixtures. Preliminaryproposals have been made elsewhere for the prediction of volumetric, phaseequilibrium, and thermodynamic data for multicomponent mixtures, utilizing as abasis the behavior of binary and ternary systems. Numerous other proposals havebeen made. That based upon the concept of a pseudo-critical state" hasmoved to be of value to the petroleum industry.

T.P. 2631
Introduction to Induction Logging and Application to Logging of Wells Drilled With Oil Base Mud
Authors: Doll H.G.
Published: April 2012

A new logging method, called induction logging, is described; it measuresthe conductivity, or resistivity, of the strata traversed by a bore hole. Theapparatus, which is briefly described, comprises a coil system coupled with theground by induction, so that there is no need for direct contact with the mud, or with the formations. For that reason, the method is particularly useful inoil base mud, and it was first applied to that case.

A discussion concerning the respective contribution of each region of groundin the vicinity of the coil system is given. Through the concept of ageometrical factor, it is demonstrated that the total signal, which measuresthe apparent conductivity, is the summation of the partia1 products -geometrical factor by conductivity - for the different regions of the groundunder consideration. It is thus possible to establish, for each type of coilarangement, investigation characteristic as well as departure curves andcorrection charts for beds of various thicknesses. This should greatlyfacilitate the quantative interpretation of the field logs, even in cases wheresuch interpretation would have been difficult on electric logs taken withelectrodes.

It is also shown that focussing combinations of coils can be used, whichgive, directly on the recorded log, a value close to the true conductivity, even for fairly thin beds, thus eliminating in most cases the need forcorrections. These focussing systems also give a sharper definition of theboundaries between successive strata.

T.P. 2641