bluuebunny/crossref_metadata_2025 huggingface dataset:
Alkaline Surfactant Polymer Flooding To Revitalize Oil Production from a Mature Water Flooded Field
Authors: Ansarizadeh M. M. , Weatherstone P. M. , Strong J. B.
Published: April 2012

Mitigating production decline is a challenging task that every oil company will be faced with at some point over the life of an oil reservoir. However, depending on the existing reservoir fluid and rock characteristics, saturation distribution, and the level of heterogeneity of the reservoir rock, Enhanced Oil Recovery (EOR) programs can be implemented to alleviate the decline in oil rate and improve overall recovery.

This paper presents an example of a how a mature waterflooded field in southwestern Saskatchewan, Canada could be revitalized using Alkaline-Surfactant-Polymer (ASP) flooding. In this study, laboratory tests were undertaken to select effective chemicals and optimize concentrations that would yield the highest potential oil recovery. Subsequent radial coreflood experiments demonstrated a wide range of potential recovery that depended on slug size and chemical concentration. A detailed numerical simulation of the optimum core displacement was performed in order to calibrate the interaction of the EOR agent with the reservoir rock and fluids, and ultimately upscaled to the full field numerical model Reservoir simulation sensitivity runs were conducted in order to identify an optimum field development strategy using the selected ASP fluid. The results from this optimized development strategy were compared to the waterflood base case to demonstrate the potential upside of the chemical flood. This paper also presents a holistic roadmap for developing EOR projects from initial concept to field implementation and beyond.
PDOs EOR Screening Methodology for Heavy-Oil Fractured Carbonate Fields - A Case Study
Authors: Warrlich Georg , Al-Waili Ibrahim , Said Dhiya , Diri Mohamed , Al-Bulushi Nabil , Strauss Jonathan , Al-Kindi Mohammed , Al-Hadhrami Fahad , van Heel Ton , van Wunnik John , de Zwart Bert-Rik , Blom Carl , Al-Mjeni Rifaat , Boerrigter Paul
Published: April 2012

Petroleum Development Oman’s (PDO) portfolio of heavy-oil, fractured carbonate prospects and fields contains a potentially large number of EOR opportunities, many of which present unique subsurface challenges. In the context of evaluating one such field, an EOR screening approach was developed combining subsurface definition through a tailor-made appraisal campaign, coupled with technical & economic feasibility evaluation of candidate EOR methods and benchmarking against other fields globally. This paper presents the screening workflow that will serve as template for the evaluation of future EOR opportunities in heavy-oil, fractured carbonate discoveries in PDO.

At the outset of the reservoir characterization of this field it was recognized that the application of any EOR technique would be challenging. High oil viscosities coupled with shallow depths render it a candidate for thermal EOR and potentially chemical concepts. However, key uncertainties in basic subsurface parameters such as reservoir architecture, matrix permeability, fracture spacing and (low) oil saturations, necessitated further data gathering before feasibility of any recovery mechanism could be concluded.

Based on literature surveys and examination of showstopper properties, a first-pass screening of a multitude of thermal and chemical EOR methods was conducted. A probabilistic assessment of key subsurface parameters was conducted against which the candidate EOR techniques were ranked. This resulted in the identification of SAGOGD, CSS, ISC and novel-chemical flooding as the most promising EOR methods.

For each of these methods the critical subsurface parameters and their impact were further assessed through the combination of (1) an appraisal campaign that included drilling of new wells, conventional production & pressure interference testing to constrain the uncertainties in these parameters and (2) Fit-for-purpose modeling (analytical analysis, sector modeling and full-field simulation) to check project feasibility.

It was found that none of the thermal recovery methods are technically or economically feasible, but chemical methods are being investigated further.
Investigating Low Salinity Waterflooding Recovery Mechanisms in Carbonate Reservoirs
Authors: Aladasani Ahmad , Bai Baojun , Wu Yu-Shu
Published: April 2012

Manipulating the injected brine composition can favorably alter the reservoir wetting state; this hypothesis has been validated in sandstone reservoirs by several scientists. A total of214 coreflooding experiments were conducted to evaluate low salinity waterflooding (LSWF) secondary recovery and 188 experiments were conducted to evaluate tertiary recovery, for sandstone reservoirs. Although the incremental recovery potential in carbonate reservoirs is greater than in sandstones, only a few imbibition and coreflooding experiments have been conducted. The simulator and recovery mechanisms presented by Aladasani et al. (2012) are used and their suitability and validity to low salinity waterflooding in carbonate reservoirs has been confirmed. This has been achieved by comparing simulated LSWF secondary and tertiary recoveries with published coreflooding experiments. Furthermore, the prediction profiler in JMP was used to examine incremental recovery for the following variables: (a) acid number and interfacial tension (IFT) sensitivities, and (b) 2nd stage injected brine and 3rd stage injected brine anion contents. In weak water-wet conditions, the incremental recovery is driven by low capillary pressures, and the underlining recovery mechanism is the increase in oil relative permeability. Therefore, wettability modification is ideal when achieved by shifting the wetting state from oil-wet or water-wet to a maintained intermediate wetting condition irrespective of the injected brine salinity dilution. If the wettability is shifted to a strong water-wet system, then it would be more favorable to use brine with anions to shift the wettability back to an intermediate wetting state. IFT has a bigger impact on LSWF in carbonate reservoirs; however, contact angle is more significant to the final oil recovery. Future work should consider studying the impact of cationic and anionic ions on coreflooding recovery separately and using cores with different initial wetting states, preferably strong oil-wet cores.
Integrated Surveillance and Modelling to Monitor Risk of Fault Re-activation During Steam Injection
Authors: Ali Al-Lawati Mohamed Hassan , Schoofs Stan , Ita Joel Jacob , Van Der Heyden Frank
Published: April 2012

A small area of carbonate field in North Oman was tested to monitor steam injection. The reservoir is a fractured carbonate and is overlain by a 250 m thick shale. Models are required to translate indirect observations or extrapolate point measurements of wells to give us a three dimensional view on field response.

The microseismic monitoring system for the steam injection pilot consists of 6 dedicated observation wells. The objectives of the system are to detect any generation of new fractures or re-activation of existing fractures due to steam injection and monitor cap-rock integrity.

800 events were recorded by the micro-seismic system so far. The events occur mainly in a clustered fashion and are attributed to cooling- and heating, and potentially to re-activation of a fault zone close to updip injectors. Micro-seismic activity has expressed the extent of this fault zone. Finally, some of the events were attributed to well related noise.

Microseismic events in the overburden could represent a continuum between two end members. One being that they represent failure of critically stressed asperities along pre-existing lineaments in which the faults and fractures are not critically stressed over a majority of surface area. The other end of the spectrum is that the minor events are indicative of incipient larger scale failure.

To gauge where the subsurface is on this spectrum, 3D geomechanical simulations were performed to estimate the proximity to large scale failure in the reservoir and overburden.

The base case model results suggest that the micro-seismic events are indicative of the first end member state, and represent asperities along pre-existing lineaments. Exploration of the full range of uncertainty in rock material showed that no large-scale fault re-activation is to be expected.
Experimental Studies of Low Salinity Water Flooding in Carbonate Reservoirs: A New Promising Approach
Authors: Zahid Adeel , Shapiro Alexander , Skauge Arne
Published: April 2012

Low salinity water flooding is well studied for sandstone reservoirs, both laboratory and field tests have showed improvement in the oil recovery in many cases. Up to very recently, the low salinity effect has been indeterminated for carbonates. Most recently, Saudi Aramco reported that substantial additional oil recovery can be achieved when successively flooding composite carbonate core plugs with various diluted versions of seawater. The experimental data on carbonates is very limited, so more data and better understanding of the mechanisms involved is needed to utilize this method for carbonate reservoirs.

In this paper, we have experimentally investigated the oil recovery potential of low salinity water flooding for carbonate rocks. We used both reservoir carbonate and outcrop chalk core plugs. The flooding experiments were carried out initially with the seawater, and afterwards additional oil recovery was evaluated by sequential injection of various diluted seawater. The experiments applied stepwise increase in flow rate to eliminate the influence of possible capillary end effect. The total oil recovery, interaction of the different ions with the rock, and the wettability changes were studied both at ambient and high temperature.

No low salinity effect was observed for the reservoir carbonate core plug at the ambient temperature, but increase of the pressure drop over the core plug was detected. On the contrary, a significant increase in oil recovery was observed under low salinity flooding of the reservoir carbonate core plugs at 90 °C. An increase in pressure drop was also observed in this case, possibly related to migration of fines or dissolution reactions. The outcrop Aalborg chalk core plugs did not show any low salinity effect, both at the room and at a high temperature. In the light of experimental results, discussions are made about possible mechanisms for improving oil recovery in carbonate reservoir as a function of change in brine salinity.
Acceleration of Oil Production in Mixed-wet Reservoirs by Alteration of Relative Permeability Curves using Surfactants
Authors: Abeysinghe Kumuduni Prasangika , Fjelde Ingebret , Lohne Arild
Published: April 2012

Surfactants have been considered to mobilize the residual oil left after water flooding of oil reservoirs. The focus has been on surfactant flooding of water-wet reservoirs utilizing mainly their ability to reduce oil-water interfacial tension, while the potential of surfactant flooding for non water-wet reservoirs has not been investigated too much degree.

The purpose of this study was to investigate the effect of reducing the interfacial tension between oil and water on the relative permeability curves at different wettability conditions. Several core flooding experiments were carried out at different wettability conditions including multiple rate water flooding followed by multiple rate surfactant floods. The wettability conditions were characterized before and after the core floods. Relative permeability functions and capillary pressure curves were estimated by history matching the recovery and the pressure drop data obtained from the core floods.

For the non water-wet systems the measured remaining oil saturation was found to decrease with increasing capillary number at low capillary number. The measured capillary desaturation curve (CDC) for the mixed-wet and oil-wet conditions are not true CDC and must be corrected for capillary end effects. The relative permeability was found to vary with capillary number and also with wettability. At low capillary numbers typical for water flooding, the relative permeability curves were constant. By increasing the capillary number the relative permeability for oil was found to increase for mixed-wet and oil-wet conditions.

Since most of the sandstone reservoirs are characterised as mixed-wet, the potential for classical surfactant flooding can be low because the real residual oil saturation is low. The oil recovery from mixed-wet reservoirs can be accelerated by alteration of the relative permeability curves by surfactants.
Low-Tension Polymer Flooding Using Amphoteric Surfactant in High Salinity/High Hardness and High Temperature Conditions in Sandstone Cores
Authors: Bataweel M. A. , Shivaprasad A. K. , Nasr-El-Din H. A.
Published: April 2012

Surfactant-polymer (SP) flooding is one of the chemical EOR processes that are used to recover residual oil saturation. In high salinity/high hardness and high temperature applications many chemical flooding methods would not be effective. During the 80’s BP proposed low-tension polymer flooding (LTPF) method to overcome some of the challenges caused by using high concentration of surfactant during some early SP flooding projects and to reduce the cost of operation. Amphoteric surfactant shows high thermal and chemical stability in these environments was evaluated in this study.

An experimental study was conducted to evaluate the performance of the low-tension polymer flooding (LTPF) process in recovering water flood residual oil using two types of amphoteric surfactants, two types of anionic surfactants, and two types of polymers that are suggested to be used for high salinity / high hardness at elevated temperature. Surface and interfacial tension, zeta potential and core flood experiments were conducted to study the surfactant-polymer interaction at high salinity brine, ability of the solution to lower IFT, surface charge to predict chemical retention, tertiary oil recovery, oil cut and pressure drop during chemical propagation in the porous media. In this study Berea sandstone cores with 1.5 in. diameter and 20 in. length were used to determine the above parameters. The core flood experiments were conducted at temperature and brine salinity of 95° C and around 172,000 ppm, respectively.

Amphoteric surfactant showed association with two types of polymers, HPAM and AMPS that caused reduction in surface activity until polymer-free aggregate concentration was reached. Increasing polymer concentration increases the surfactant concentration needed to reach to polymer-free aggregate concentration. When HPAM polymer used in preparing chemical slug, it shows higher injectivity decline compared to AMPS. Anionic surfactant showed less chemical retention due to the negative surface charge on Berea sandstone particles when this type of surfactant is used. No significant recovery was obtained during surfactant flooding, which prove that IFT reduction can’t improve recovery without the aid of mobility control by polymers.
ASP vs. SP Flooding in High Salinity/Hardness and Temperature in Sandstone Cores
Authors: Bataweel M. A. , Nasr-El-Din H. A.
Published: April 2012

Chemical flooding methods are used to recover residual oil left after water flooding. Several chemical flooding processes has been used to improve recovery: surfactant-polymer (SP), low-tension polymer flooding (LTPF), and alkaline-surfactant-polymer flooding (ASP). When working high salinity/high hardness reservoirs each of above processes will interact differently with reservoir component and will give different recovery results.

An experimental study was conducted to examine different type of chemical flooding technologies on the oil recovery of the water flooded residual oil, formation and injectivity decline of each technology. Two Anionic, two amphoteric surfactant, two alkalis and two types of polymers were used in this work to formulate the different chemical solutions. Core flow experiments using core samples of 1.5" diameter and 20" in length prepared from Berea sandstone material. Core flooding experiments was conducted on challenging condition of elevated temperature of 95°C and high salinity environment of 172,000 ppm.

ASP formulation prepared with anionic surfactant showed the best oil recovery compared to other chemical flooding processes. Although solutions prepared with amphoteric surfactant shows the least IFT values they did not give the highest recovery. ASP solution prepared using organic alkali low surfactant concentration showed similar recovery when compared to high concentration surfactant formulation. Formulations prepared using the ASP technology showed the highest pressure drop after chemical injection which can be due to the precipitation of the inorganic alkali when mixed with residence brine before the chemical injection.
Reservoir Characterization Begins at First Contact With the Drill Bit
Authors: Shayegi S.. , Kabir C.S.. S. , If F.. , Christensen S.. , Kosco K.. , Casasus-Bribian J.. , Hasan ABM K. , Moos H..
Published: April 2012

Underbalanced drilling (UBD) offers a unique opportunity to estimate undamaged, in-situ formation properties upon first contact with the formation while drilling. This paper compares well-testing techniques developed for UBD with conventional methods. The reservoir flow rates in combination with flowing bottomhole pressures (BHPs) acquired while drilling can be used to identify productive intervals and estimate dynamic reservoir properties.

Unlike typical UBD projects where reservoir benefits are the primary focus, the driver for this mature field was overcoming the drilling problems associated with the wide reservoir-pressure variability caused by nearby producers and injectors. UBD was piloted as a means to achieving the requisite lateral lengths for reserves capture and meeting production targets. Minimizing formation damage and characterizing the reservoir while drilling were added benefits.

Several reservoir-characterization methods based on rate-transient analysis (RTA) were used to perform well testing while drilling. Rate-integral-productivity-index (RIPI) analysis uses the rate and pressure data acquired during drilling to determine whether additional hole drilled contributes and to ascertain the relative quality of the rock. In the increasing-boundary method, real-time rate and pressure data during drilling, circulating, and tripping allowed assessment of formation properties through history matching. Pressure-buildup data were also available during trips because the concentric annuli allowed the pressure to be monitored below the downhole isolation valve. These data enabled the estimation of reservoir pressure and productivity index (PI) with a proxy vertical-well model for each productive interval drilled. These interpretation methods show close agreement in results and lend credence to the UBD-derived parameters.
Waterflooding in North Government Wells Field, Duval County, Texas
Authors: Collingwood D.M. , Bethancourt R.J.
Published: April 2012

The use of a pilot waterflood is very desirable where all of the pertinent data necessary to initiate a full scale waterflood are not available. This paper attempts to take a specific case and show the step by step process of starting with a pilot water flood and progressing to a full scale flood as results are obtained.

Introduction

Many of the older fields of Southwest Texas are approaching depletion by primary production methods. As primary producing operations on individual properties approach theireconomic limit, conflicting considerations face management: on the one hand, plugging and abandonment of wells for equipment salvage; on the other hand, further investment in secondary recovery installations, equipment, and well workovers in the interests of conservation and additional oil reserves.

In many instances, where primary production by pressure depletion and gas solution drive has been comparatively good, there still exists the possibility of an economic secondary recovery by waterflood. This is not necessarily true to the same degree of all such fields, nor all portions of large fields.

To properly evaluate the economics of a prospective waterflood requires a considerable amount of precise geological, statistical, and physical data. Such information on the older fields is often very limited, and in the case of the property discussed in this paper was considered inadequate to justify investment in an overall waterflood. Primary production was estimated at 39 per cent of the original oil in place, yet sand conditions of permeability and homogeneity, and position in the field appeared to be favorable for a limited margin of profit from a carefully controlled waterflood.

Thus a pilot waterflood, with its minimum initial financial risk, followed by extension as favorable results were obtained, seemed to be the answer for the Sun Oil Co.'s L. Wiederkehr lease in the North Government Wells Field, Duval County, Texas.
The Microlaterolog
Authors: Doll H.G.
Published: April 2012

A new electrical logging method, called MicroLaterolog, is described, whereby the resistivity Rxo of the invaded zone close to the wall of the bore hole is measured. This method essentially utilizes a system of concentric circular electrodes imbedded in an insulating support which is applied to the wall of the hole. A beam of current of very small diameter is focused horizontally into the formations by means of an automatic control device, and then opens widely at short distance from the wall. With this method, Rxo most often can be recorded directly, except when the mud cake is very thick, in which case a correction is easily provided. The basic role of factor Rxo in the quantitative analysis of electrical logs in terms of fluid saturation and of porosity is explained. The paper is illustrated with field examples.

Introduction

In electrical logging, the resistivity of that part of the permeable and porous formations which is invaded by mud filtrate is an important factor in the interpretation. Measurements made with the conventional devices - normal, lateral- and also with improved systems as the Laterolog and induction logging - are very often more or less affected by the presence of the invaded zone, and the knowledge of the resistivity of this zone is useful in the evaluation of the true resistivity of the beds, which itself is a basic element for the determination of fluid saturation. Moreover, the comparison of the resistivity of the invaded zone with the resistivity of the mud filtrate gives valuable indications on the magnitude of the formation resistivity factor - which in turn is necessary for the quantitative interpretation of the logs, both in terms of fluid saturation and of porosity.

On the other hand, it is generally admitted that the invaded zone is not a homogeneous medium separated from the uncontaminated part of the bed by a well defined cylindrical boundary, but that the fluid distribution - filtrate, connate water, hydrocarbon - and hence, the resistivity in the invaded zone varies progressively with the distance from the wall of the hole. The term "resistivity of the invaded zone" therefore corresponds to an average value which is a function of the distribution of the fluids. Inasmuch as the law of this distribution is not exactly known, the resistivity of the invaded zone is not a well defined factor.
A Laboratory Investigation of Oil Displacement From Porous Media by a Liquified Petroleum Gas
Authors: Henderson J.H. , Gove N.B. , Ledbetter H.J. , Griffith J.D.
Published: April 2012

The results of a series of laboratory flood tests using liquid iso-butane to displace refined oils from test cores are presented and interpreted on an empirical basis. The study revealed the similarity of the miscible liquid displacement to that of the immiscible-fluid displacement mechanism. The efficiency of the iso-butane flood decreased markedly as the oil viscosity increased, but the effect of injection rate on the effectiveness of the primary production stage was negligible over the range investigated. The presence of free-gas saturation prior to iso-butane breakthrough increased the volume of isobutane required to recover a given percentage of the oil present. Injection of liquid iso-butane prior to water flood resulted in a marked improvement in oil recovery by the water flood.

Introduction

The production of petroleum is often enhanced by the injection of extraneous fluids into the reservoir. It has been suggested that the injection or cycling of a wet gas or a liquefied petroleum gas would be instrumental in increasing the efficiency of oil recovery to a greater degree than the commonly injected fluids, dry gas and water. Although instances of injection of light liquid hydrocarbons are not unknown, a systematic recording of the results is unavailable; and superficially, the practice gives the impression of being economically unsound.

For specific types of displacement, analytic solutions have been advanced which aid in understanding the physical mechanisms involved. However, there is no generalized theoretical concept which permits adequate prediction of displacement efficiency from a knowledge of readily measured reservoir rock and fluid properties. The Buckley-Leverett approach to oil displacement by an immiscible phase is an admirable analysis of that type of mechanism. Dykstra and Parsons have introduced a useful concept in their evaluation of the role of the mobility ratio and its merit in rationalizing displacement phenomena. Everett, Gooch and Calhoun in their report on the effect of viscosity ratio and miscibility have pointed out the lack of a comprehensive theoretical approach and the desirability of investigating the mechanism of miscible-miscible displacement.

In lieu of a well-developed theory concerning miscible-miscible displacement and in view of the scarcity of engineering information on actual LPG injection trials, the limited program of laboratory experimentation described below was undertaken.
Equilibrium Constants for a Gas-Condensate System
Authors: Hoffman A.E. , Crump J.S. , Hocott C.R.
Published: April 2012

Planning of the efficient operation of a gas-condensate reservoir requires a knowledge not only of the gross phase behavior of the system but also of the equilibrium distribution of the various components between the gas and condensate phases. This equilibrium distribution can be calculated with appropriate equilibrium constants. In this paper are presented equilibrium constants determined experimentally for the oil and gas phases initially present in the same reservoir and for the gas and condensate phases of the gas cap material at a series of pressures below the original reservoir pressure. Also presented is a method for the correlation of the experimentally determined equilibrium constants. The utility of the correlation is demonstrated further by an example of its use in adjusting the equilibrium data to permit their application to another gas-condensate system of similar composition.

Introduction

Planning of the efficient operation of a gas-condensate reservoir requires a thorough knowledge not only of the gross phase behavior of the particular hydrocarbon system but also of the equilibrium distribution of the various components between the gas and condensate phases. At the initial conditions of reservoir temperature and pressure, the original hydrocarbon materials in a gas-condensate reservoir or in the gas-cap of an associated reservoir exist in a single, homogeneous vapor phase. However, some condensation of hydrocarbons to a liquid phase usually occurs in the reservoir as pressure declines incident to production. Because of this condensation, the produced gas changes composition continuously. The composition of the produced gas, as well as that of the condensed liquid, can be calculated from the composition of the original reservoir material through the application of appropriate equilibrium constants or "K"-values provided these values are known.

Equilibrium constants have been used for many years in problems of surface separation of gas and oil and natural gasoline recovery. However, no satisfactory equilibrium data at reservoir conditions have been available for the higher boiling hydrocarbons which acquire abnormal volatility at high pressure and are therefore present in the gas phase in condensate reservoirs. Early work in this field indicated that the behavior of the higher boiling hydrocarbons largely determines the behavior of gas-condensate systems at high pressure.
Relative Permeability Calculations From Pore Size Distribution Data
Authors: Burdine N.T.
Published: April 2012

Formulas for calculating relative permeability from pore size distribution data are derived from basic laws of fluid flow in porous media. The tortuosity factors that appear in the equations are described in terms of the physical properties of the medium and the saturations of the contained fluids. Procedures for calculating and methods for measuring the tortuosity factors are discussed. Values of relative permeability calculated by the formulas are compared with results obtained by experimental measurements.

Introduction

Recently, several investigators have derived relative permeability equations from Darcy's and Poiseuille's Laws in which some physical factor or factors describing the porous system appear. The factor that has caused the greatest amount of comment, and which is probably least understood, is the tortuosity of the fluid path in the porous sample. Values of the tortuosity factors appearing in the equations range from a constant for all conditions of the fluid flow system to an inverse function of the pore radii.

It is the purpose of this paper to compare some experimentally determined relative permeability curves with those calculated by a method which utilized capillary pressure information. The capillary pressure data were obtained preferably from pore size distribution information as determined by mercury injection but, in some cases, in the absence of suitable mercury injection information, data were taken from measurements made by the porous semi-permeable diaphragm method. The physical significance of certain tortuosity concepts is inferred and the determinations of the tortuosity factors from pore size distribution data and by electrical measurements are discussed.
A Method of Perforating Casing Below Tubing
Authors: Lebourg M.P. , Hodgson G.R.
Published: April 2012

The introduction in the field of a new type well completion called for the setting of tubing open-ended in the well before perforating the casing. This paper describes a new perforating tool of the shaped charge expendable type, small enough to pass through tubing and powerful enough to perforate the casing. The perforations are produced at an angle and are large enough for optimum production. Performance of this tool in targets and under various well conditions is described.

Very often no lifting equipment will be available at the well. In some cases, pressure will exist in the well at the time of the perforating operation (workover wells or multiple trip perforation); therefore, new equipment and new technique for the perforating operation were devised. This paper describes this equipment and technique, particularly casing collar recording, sheave support, and cable pull-down device, this last item being necessary for wells under pressure. Results obtained with this tool in the field are given.

Introduction

One of the key requirements for the introduction in the field of a new method of permanent well completion was the development of a new perforating method involving the use of a perforating gun small enough to go through tubing and with enough penetrating power to perforate the casing satisfactorily.

The equipment described in this paper was basically designed to go through open-ended two-in. tubing and to perforate 5?-in. casing. The equipment is illustrated in accompanying figures.

New Completion Method

With the new permanent type well completion, the production string of casing is run and cemented through the potential producing zone. Open-ended tubing is then run into the well and used to replace the drilling fluid with oil or water. The amount of the oil or water "cushion" can be varied according to the expected bottom hole pressure. Thus, if desired, the hydrostatic head can be greater, equal to, or less than the expected pressure within the zone to be perforated.

Mud having been displaced, the tubing is then positioned so that the end is above the zone to be perforated.
Effect of Pressure and Temperature on Oil-Water Interfacial Tensions for a Series of Hydrocarbons
Authors: Hassan M.E. , Nielsen R.F. , Calhoun J.C.
Published: April 2012

An apparatus was constructed for the measurement of interfacial tensions over a range of temperatures and pressures. This apparatus utilized the pendent drop method, and resembles in construction similar apparatus recently described in the literature and in use in some petroleum research laboratories. The interfacial tensions of benzene, propane, n-pentane, n-hexane, n-octane, and iso-octane against water were measured at temperatures ranging from 26? to 82? C and at pressures ranging from 1 to 204 atm. Values of interfacial tensions for the benzene-water system and their variations with temperature and pressure are generally in good agreement with values of previous investigations.

The data in all cases showed a slight decrease of interfacial tension with pressure at constant temperature in the range studied. The effect of pressure became less as the pressure was increased, with an indication of a reversal of the effect at higher pressures. There was a decrease of interfacial tension with temperature at constant pressure in all cases, as would normally be expected. This rate of decrease became greater the higher the temperature.

A general equation is presented for the interfacial tensions as a function of pressure and temperature over the range studied, and the constants calculated for each system. A definite trend was found in the effect of molecular weight on the interfacial tension at a given temperature and pressure, for the homologous series from propane to n-octane. Data for n-decane from the literature fitted well into this trend.

Introduction

It has been recognized for many years that surface forces play an active part in the production history of an oil reservoir as well as in determining the amount of unrecoverable oil. The magnitudes of these forces are governed by the values of the interfacial tensions. These vary greatly with composition, pressure, and temperature. The effect of composition is greater than that of pressure and temperature over the ranges normally encountered. In fact, because of the variety of compounds present in a crude, no attempt has yet been made to correlate crude composition with its surface tension or with its interfacial tension against water. The amount of dissolved methane greatly affects the surface properties of an oil, and there are "surface-active" compounds in crudes which have a much greater effect on boundary tensions than do equal amounts of hydrocarbons.
Relationship of Drilling Mud Resistivity to Mud Filtrate Resistivity
Authors: Patnode H.W.
Published: April 2012

The effect of suspended solids on the resistivity of slurries is discussedand the relationship between drilling mud resistivity and mud filtrateinvestigated. It is concluded that it is erroneous to substitute mudresistivity for mud filtrate resistivity in electric log calculations. Arecommendation is made that both the bud resistivity and the mud filtrateresistivity be determined when electric logs are run.

Introduction

The electric log is influenced not only by the resistivity of the drillingmud in the borehole at the time of logging but also by the resistivity of thedrilling mud filtrate.

Sherborne and Newton investigated the relationship of mud resistivity to mudfiltrate resistivity and concluded that, "The resistivity of the mud inmost cases closely approximates that of its filtrate," and "In fact, with the exception of Aquagel and its filtrate, the figures for any particularmud and filtrate are almost identical." Present practice is to determineonly the drilling mud resistivity and apply this same value to calculationsinvolving the mud filtrate. The purpose of this study is to reexamine thefactors governing the relationship between mud resistivity and mud filtrateresistivity.

Effect of Borehole Fluid on the Electric Log

Resistivity Log

The resistivity log may be modified by the resistivity of the borehole fluidin two different ways:The apparent resistivity of a formation may be different from the trueresistivity of the formation because of the flow of some current through thedrilling mud in the borehole. Therefore the resistivity of the mud is animportant factor.The apparent resistivity may differ from the true resistivity, if aformation is invaded by mud filtrate, because of displacement by the mudfiltrate of some of the interstitial fluid in the formation. In this case theresistivity of the mud filtrate rather than the resistivity of the mud is theimportant factor.

Self Potential Log

The self potential arises, in part, from electrochemical effects resultingfrom the interaction of connate waters in porous formations and the fluid inthe borehole. A theory of the electrochemical component of the self potentialin boreholes has been recently set forth by Wyllie. In the above equationresistivities have been substituted for activities of the ions in the fluids.It is therefore apparent that the resistivity of the mud filtrate is morenearly representative of the activities of the ions than is the resistivity ofthe mud. However, it is possible that in some instances the ionic activities ofcations from certain clays may contribute to the total cationic activity of thedrilling fluid to such an extent that the mud resistivity is more nearlyrepresentative of the activities than the filtrate resistivity. This isparticularly the case when the resistivity of the mud is less than theresistivity of the mud filtrate.

In addition the apparent self potential may be influenced by the resistivity ofthe drilling mud because of current flow through the borehole.

T.P. 2512
Semiautomatic Power-Operated Drilling Machinery
Authors: True Martin E. , Stone Bert L.
Published: April 2012

To cope with the problems encountered when drilling at greater depths and toreduce the amount of physical effort required on the part of drilling crews inmaking round trips, a new type of semiautomatic power-operated drillingmachinery has been developed which permits round trips to be made without thedrill pipe being touched by hand. This equipment consists of hydraulicallyoperated tongs which perform the stabbing, spinning, and tonging operations, and two power-operated racking units mounted in the derrick for carrying thepipe to and from the center of the hole and positioning it on the mat and inthe rack. With this equipment all of the operations of the various units arecontrolled remotely by manipulation of hydraulic valve levers and electricswitches.

Introduction

As horsepower rises to meet the demand for deeper drilling, it is necessaryto increase the weight of surface drilling equipment. Also, the duration ofrepetitive operations in making round trips to change bits is greatly increasedwith depth. Harder formations encountered at greater depths reduce bit liferapidly, resulting in more frequent round trips and in some instances more timeis consumed in changing bits than in drilling.

Since the introduction of the first rotary employed to drill for oil in 1895there has been relatively little change in the general procedure for making up, breaking out, stabbing, and racking drill pipe in making round trips to changebits. The conventional method of making round trips with the drill piperequires that drilling crews lend strenuous physical assistance to manuallyoperated tools.

Although many new devices have been developed to improve efficiency, increase speed of making round trips, improve safety, and reduce the amount ofphysical effort required in handling drill pipe, it is considered a vitalnecessity to substitute automatic or semiautomatic power-operated machinery formany of our more or less manual operations if extremely deep drilling is to becarried out successfully on a production basis in the same manner as ourshallower drilling of today.

T.P. 2543
Capillary Pressures - Their Measurement Using Mercury and the Calculation of Permeability Therefrom
Authors: Purcell W.R.
Published: April 2012

An apparatus is described whereby capillary pressure curves for porous mediamay be determined by a technique that involves forcing mercury under pressureinto the evacuated pores of solids. The data so obtained are compared withcapillary pressure curves determined by the porous diaphragm method, and theadvantages of the mercury injection method are stated.

Based upon a simplified working hypothesis, an equation is derived to showthe relationship of the permeability of a porous medium to its porosity andcapillary pressure curve, and experimental data are presented to support itsvalidity.

A procedure is outlined whereby an estimate of the permeability of drillcuttings may be made with sufficient accuracy to meet most engineeringrequirements.

Introduction

The nature of capillary pressures and the role they play in reservoirbehavior have been lucidly discussed by Levrett, Hassler, Brunner, and Deahl, and others. As.a result of these publications the value of determiningcapillary pressure curves for cores has come to be generally recognized withinthe oil industry. While considerable attention has been directed toward thesubject in an effort to provide a reliable method of estimating percentages ofconnate water, it has been recognized that capillary pressure data may prove ofvalue in other equally important applications.

This paper describes a method and procedure for determining capillarypressure curves for porous media wherein mercury is forced under pressure intothe evacuated pores of the solids. The pressure-volume relationships obtainedare reasonably similar to capillary pressure curves determined by the generallyaccepted porous diaphragm method. The advantages of the method lie in therapidity with which the experimental data can be obtained and in the fact thatsmall, irregularly shaped samples, e.g., drill cuttings, can be handled in thesame manner as larger pieces of regular shape such as cores or permeabilityplugs.

Based upon a simplified working hypothesis, a theoretical equation will bederived which relates the capillary pressure curve to the porosity andpermeability of a porous solid, and experimental data will be presented tosupport its validity. This relationship applied to capillary pressure dataobtained for drill cuttings by the procedure described provides a means forpredicting the permeability of drill cuttings.

T.P. 2544
Methane Hydrate at High Pressure
Authors: Kobayashi Riki , Katz Donald L.
Published: April 2012

The conditions at which methane and water form solid hydrates have beenextended from 4,000 to 11,200 pounds per sq. in. The curve at high pressure hadbeen in doubt because of Villard's report of a critical decompositiontemperature. The paper explains the nature of the hydrate curve at highpressure and its dependence on fluid phase behavior. Extropolation of themethane hydrate curve indicates a pressure of 40,000 pounds per sq. in. willcause hydrates to form at a temperature of 100' F.

Introduction

The conditions under which natural gases form hydrates when liquid water ispresent have been studied by several investigators up to pressures of about4,000 pounds per sq. in. The early work by Villard on hydrates of methane andethylene, ethane, and propane included references to critical decompositiontemperatures of the hydrates. Villard's work raised the question as to whetherthe pressure-temperature curve for methane-water hydrate continued above atemperature of 70.7?F. or whether this was the maximum temperature at whichhydrates would form.

This paper extends the experimental data on methane hydrate to 11,200 poundsper sq. in. A discussion of phase relations in the hydrate region for thehydrocarbons and of the methane-water system at high pressures isincluded.

Previous Work

Villard suspected that methane hydrates could not be formed at temperaturesabove 21.5?C. (70.7?F.) irrespective of the pressure of the liquid-vaporsystem. However, he was limited in his studies by his apparatus in 1888 topressures not greater than 300 atmospheres (4,410 pounds per sq. in.) so thatthere has remained some doubt as to the existence of such a maximum temperaturein this region.

For the case of ethylene hydrates, however, Villard does specifically state theoccurrence of what he terms a "critical temperature for the decompositionof the hydrates."

T.P. 2579
Reservoir Performance of a High Relief Pool
Authors: Burtchaell E.P.
Published: April 2012

A method is presented for evaluating the effect of gravity drive upon thereservoir performance of a high relief pool. Conventional forms of reservoiranalysis do not consider the alterations in the basic material balance datacaused by gravity segregation of reservoir fluids. A procedure is outlined forstructurally weighting physical and chemical data for use in the materialbalance equation. It is demonstrated how actual pool performance data can beutilized to evaluate the future reservoir performance of a gravity drivepool.

Introduction

Conventional reservoir engineering procedure is inadequate for the analysisof an oil pool which has considerable structural relief, steep dips, and goodpermeability development. In pools of this type, gravity drainage has animportant part in the movement of oil to the wells and the effects of gravityon the overall pool performance should be included in any analysis of reservoirbehavior. Many engineers have the opinion that the force of gravity in themovement of oil is not important until the later life of a pool. Probably thebasis for this belief is that gravitational effects may not be readilydiscernible until a pool is nearing depletion. This would be especially truefor pools not having a high degree of structural relief and permeabilitydevelopment. Actually the effects of gravitational forces are at a maximum whenthe pool pressure is high, for during this period the hydrostatic head of theoil column is at a maximum and the viscosity of the oil is at a minimum.

Oil recoveries from pools having favorable gravity drive characteristics mayequal or even exceed recoveries which might be expected from waterdisplacement. Field evidence indicates that in some reservoirs gravity drivehas resulted in recoveries greater than that which could have been expectedfrom gas expansion or water drive. Unfortunately, the possible effects ofgravity drive on pool performance have been underestimated and other reasonshave been sought to explain the high recoveries obtained. There areunquestionably many reservoirs to which the principles of gravity drainage canbe effectively applied.

It is the purpose of this paper to illustrate one method whereby gravitydrive is included in the reservoir analysis of an oil pool. A hypotheticalpool, typical of many California reservoirs, is used as an example. As used inthis paper, "gravity drive" is defined as the overall effect ofgravitational influences on the recovery of petroleum from the reservoir;"gravitational segregation" as the gravity separation of oil and gaswithin the reservoir; and "gravity drainage" as the downward movementof oil as caused by the force of gravity.

T.P. 2645