bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Summary
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.