bluuebunny/crossref_metadata_2025_split huggingface dataset:
How to Compute the Permeability and Skin Factor of Low Pressure Water Zones
Authors: Szpunar T. 
Published: March 2010

Abstract
The paper presents a simple mathematical model which allows prediction of the behaviour of the water table in a low pressure water well which does not flow to surface. The derived relations enable computation of the permeability and skin factor of the water zone. Unlike the type-curve method used for interpretation of "slug test" data, the permeability and skin are computed using a straight-line approximation. The slope of the straight line and its intersection with the ordinate axis are used to interpret the test data. The presented method is very simple and yields unique results.

How to Compute Permeability and Skin
In low pressure water wells, the water table stabilizes at some depth below the surface. Such a situation is observed in water wells, some oil wells, hydrogeological wells and coalbed methane wells. "Slug testing"involves the sudden removal of some liquid from the well, and then analysing the water table behaviour (or pressure response) to determine the reservoir transmissibility. If the duration of flow from the reservoir is sufficiently long, liquid will continue to accumulate in the well until the pressure exerted by the liquid column in the well equals the reservoir pressure. The permeability and skin are evaluated by matching the measured pressure vs. time data or water level vs. time data to one curve among the family of theoretical curves. Mismatching ends up with erroneous results. The model presented here enables computation of the permeability and skin using a straight-line approximation through the conventional "slug test" data; i.e., it can be used for interpretation of DST flow period data. The relation (derived in the Appendix) used to compute the permeability and skin is:
Equation (1) Available In Full Paper.
z0 denotes the stabilized liquid level (which corresponds to original reservoir pressure), and z1 denotes the liquid level after some fluid is removed from the well at t = 0 (which corresponds to initial tubing pressure at the water zone level). z(t) is a current water level measured while the water table rises up in the well (corresponds to actual tubing pressure at the water zone level).
The following nomenclature is assumed in Equation (1):k = permeability of a water zoneh = thickness of a water zoneρ = fluid densityg = acceleration of gravityr w = tubing radiust = timeφ = porosity of a water zoneμ = fluid viscosityS = skin factor
Equation Available In Full Paper.
is a root of the following equation:
Equation (2) Available In Full Paper.
Where
Equation (3) Available In Full Paper.
As long as ct does not change with time, Equation (1) indicates
that a plot of
Equation Available In Full Paper. vs. t is linear with slope
Equation (4) Available In Full Paper.
permitting the calculation of permeability, k. The skin factor can be calculated by evaluating the point of intersection of the same plot at t = 0, given as D:
Equation (5) Available In Full Paper.
Progress in the In Situ Recovery of Heavy Oils and Bitumen
Authors: Butler R.M. , Yee C.T. 
Published: March 2010

Abstract
Most of Canada's trillion barrels of petroleum consists of bitumen, and to a lesser extent, heavy oil. This total may be compared with the total Canadian production of light-medium crude oil to date, which is only 12 billion barrels. Mining is effective for the production of bitumen, but is limited to the minor fraction of the resource that is shallow; also mining involves significant environmental difficulties.
The challenges of efficient in situ production are like those for other petroleum production activities:to find and define suitable reservoirs,to create conditions for oil to flow at economic rates, andto drain the reservoir systematically to obtain high recoveries.
This paper discusses the following in terms of production rate, recovery, energy requirements and economic factors. Each topic is a step, sometimes a sideways step, in the search for a means to achieve high rates and recovery within the bounds of economic constraints.Cold production using vertical wells and horizontal wells.Stimulation by wellbore heating.Cyclic steaming using conventional wells.Steam Assisted Gravity Drainage (SAGD).Steam and Gas Push (SAGP).Cyclic Steaming with horizontal wells.Vapour Extraction (Vapex).
Processes resulting in the displacement of oil by gas to a lower horizontal well show the most promise. The viscosity in the region around the horizontal well should be reduced to allow economic rates without gas coning.
In SAGD, injected steam heats the oil and fills the reservoir as it drains, and rates of 79 – 159 m3/d (500 – 1,000 B/d) can be achieved with bitumen recoveries greater than 50%. Heat savings can be achieved by building a substantial gas concentration within the depleted region (SAGP).
In Vapex, viscosity reduction is obtained by dilution with a olatile solvent; this is a promising approach for lower viscosity heavy oils.
Another promising approach is cyclic steaming with horizontal wells, combined with gas addition to the steam to maintain drive.

Introduction
As conventional oil reserves become depleted, interest continues to grow in the improved recovery and utilization of Canadian tar sands and heavy oil. The resources are enormous in magnitude, and there have been great strides in technology. One approach, the mining and upgrading of shallow Athabasca deposits has, with the success of the Suncor and Syncrude projects, already become a major source of Canadian oil. Major expansions to both of these projects, as well as other new tar sand mining projects are underway.
While mining overcomes the problem of moving the oil to the surface and of obtaining high recoveries, it requires the handling and disposal of vast amounts of solids and sludge, and it is only economic for the shallowest of deposits. The major part of the Canadian oil sand resource is too deeply buried for mining to be practical.
This paper is concerned with the recovery of bitumen and heavy oils by in situ methods, i.e., by means of wells drilled from the surface.
Comparison of Pressure Transient Behaviour of Composite and Two-Layered Reservoirs
Authors: Jordan C.L. , Mattar L. 
Published: March 2010

Abstract
In pressure transient analysis, often the geological model is not known, or is ambiguous. Many well tests can be analysed using a composite reservoir model which assumes that the flow capacity (k*h) near the wellbore is different from that away from the wellbore. There are many naturally occurring reservoirs that can legitimately be modeled this way because the transmissivity is indeed varying laterally. However, there are many more reservoirs which have a different flow capacity near the well as compared to the bulk of the formation, not because of lateral permeability changes, but because of layering. In these situations, it is the net pay and reserves, not necessarily the permeability, that is changing.
This paper compares the pressure transient behaviour of a multi-layer system with that of a composite system, and illustrates the similarities and the differences in their respective derivative signatures. It also investigates the extension of these two different models to pseudo-steady state forecasting. Even though the behaviour of these two systems may be similar during transient flow (which is the time domain of most well tests), the long-term performance is significantly different if the improper model is used (which is typically the time domain of many engineering and economic decisions). The role of the geological model in well testing and deliverability forecasting is discussed, as it can have a significant effect on some parts of the analysis, and an insignificant effect on other parts.

Introduction

Multi-Layered System
It is commonly known that if two or more layers of a reservoir are open to a wellbore, and are initially at a common pressure and constant drawdown, the general characteristics of the drawdown response is similar to that of a well producing from a single layer reservoir(1, 2). Specifically, each layer will contribute production which is proportional to its transmissibility (kh/ µ). Therefore, the semi-log slope (m) calculated from the infinite acting flow*?data will be nearly proportional to the sum of the individual layer transmissibilities (any modification of this slope would be due to unequal diffusivities or skin factors). For example, if a well is producing commingled at the wellbore from a layer of 2 m and a layer of 3 m net pay (both with a permeability of 20 mD), the semi-log analysis of the radial flow data (refer to Figure 1) will show a flow capacity of 100 mD.m
If one layer of a two-layer model is limited in drainage area, a depletion of the limited layer will eventually occur. Upon depletion of this layer, a semi-log straight line with a slope "m" that is inversely proportional to the transmissibility of the more extensive layer may be observed. On the derivative analysis, after the initial radial flow, a unit slope develops followed by a transition to a second radial flow characterized by the typical zero slope.
Modelling Sand Production Within a Continuum Mechanics Framework
Authors: Wan R.G. , Wang J. 
Published: March 2010

Abstract
The paper presents a continuum mechanics framework in which sand production can be modelled on the basis of an erosional mechanism. A representative elementary volume, comprised of three constituents namely solid, fluid, and fluidized solids, is chosen upon which mass balance and particle transport equations are written. The erosional process is described by a particle generation constitutive law. The coupled non-linear governing equations are finally solved using the finite element technique with a Newton-Raphson scheme. In order to illustrate the capabilities of the model, the evolution of controlling field variables, such as porosity, fluidized sand concentration, and pressure, are computed for a wellbore subjected to a pressure gradient corresponding to fluid draw down during pumping. In the case of anisotropic permeability conditions, sand production is at its peak value at different points around the wellbore, and there is a time lag between the times at which each point reaches its peak. This is due to the averaged fluid and fluidized sand fluxes being non-radial.
Sand production from unconsolidated formations occurs when the well fluid being produced under a high pumping rate dislodges a portion of the formation solids, leading to a continuous flux of formation solids. In Alberta, the formation from which the fluid (hydrocarbon) is being produced is oil sand, while the solids comingout with the fluid is sand, although solids can be produced from a variety of other formation types, such as sandstones. Sand in the well fluid can erode casing, pipes, and pumps, or plug the well if sufficient quantities are produced. The distinct periods of sand production in the well and reservoir life as pressure is being depleted were discussed by Morita et al.(1)

Introduction
There are a number of schemes to address sand production. Exclusion schemes involve the installation of gravel packs or screen filters in order to catch the sand as it enters the well. However, by doing so, the flow rate of heavy oil in the well can drastically fall from 7 – 15 m3/day to maybe 0.5 – 5 m3/day. On the other hand, avoidance schemes include pressure and fluid rate control, selective perforations, and resin injection to coat the sand.
As operators are following more aggressive production schedules, this has led to a demand for understanding the phenomenon of sand production mechanisms so that correct predictions of the anticipated amount of produced sand as a function of time, applied stress, and fluid flow rates can be made. The challenge is to develop a mathematical tool with a predictive capability that will allow oil operators to devise pumping schemes that produce hydrocarbons at a flow rate just below one that will produce sand.
The physics of sand production is not clearly understood. However, oil rate enhancement is often linked to solution gas effects, sand movement, and growth of large high permeability regions or cavities known as wormholes(2).
Transport of Fine Sand From a Wellbore
Authors: Mazurek K.A. , Chalaturnyk R.J. , Rajaratnam N. , Scott J.D. 
Published: March 2010

Abstract
This paper presents the results of an experimental study on the transport of fine sand in the entrance region of a progressing cavity pump. The study was performed to provide additional information on the behaviour of the sand slurry flow within a heavy oil well. Tests were carried out with both glycerine and water flows, with the addition of sand in the form of slugs or as a continuous feed to form a sand slurry. Several geometries of the pump intake were used. The different flow regimes observed suggest modes of operation of heavy oil wells that may be used to better avoid sanding or shutting in of wells. These results, in addition to being useful to industry, should also inspire more theoretical studies to explain the formation of the various flow features.

Introduction
The flow in a heavy oil well consists of a mixture of very viscous heavy oil, gas, water, and fine sand. For these wells, sand production can be a costly problem(1). Within the pump entrance area, there is potential for the sand to choke the flow within the well ("sanding") and production equipment. Sand may form bridges or arches within the annulus of the well to reduce flow tothe pump. Sand may also restrict flow at the intake to the pump, which can result in pump damage. It is possible that the problems associated with sand production are so costly that the well does not operate within economic limits, and is subsequently shut in or abandoned. Field monitoring of solids production in heavy oil wells typically classifies sand entrance into the wellbore to be either "continuous," where a reasonably constant value of sand is produced, or "sluggery," where slugs with high sand concentrations enter the wellbore(1).
This paper presents the results of a visualization study to investigate the mechanics of slurry flow in a heavy oil well in the area around the entrance of a progressing cavity pump(2, 3). The purpose of the study was to investigate the flow regimes created in the pump entrance area by changes in the flow rate and properties of the sand slurry fed into the well, and to assess the impact of each on sand removal in the area around the pump intake. Both a very viscous glycerine-sand slurry and a water-sand slurry were used in the experiments to examine the effect of fluid viscosity. The transport of sand was observed in a single liquid phase, with the sand added in slug form or as a continuous feed. The study also investigated the effect of the geometry of the pump intake region on sand removal from the area. Several interesting flow phenomena were observed, and are described herein.

Experimental Arrangement and Experiments
The visualization model, shown in Figure 1, examined a 1.35 m section around the pump entrance and was close in size to typical heavy oil wells in Western Canada.
Phase Equilibria Relevant to Acid Gas Injection: Part 2-Aqueous Phase Behaviour
Authors: Carroll J.J. 
Published: March 2010

Abstract
The purpose of this paper is to review the literature for the available experimental data and briefly survey methods for calculations of the aqueous equilibria of acid gas mixtures; notably, the water content of the gas and liquified acid gas. In addition to water, this study will include the following components: hydrogen sulfide, carbon dioxide, methane, ethane, and propane.
The design engineer should be fully informed of the capabilities of the model selected to perform the calculations. If uncertain, it is wise to verify the chosen model by comparing it with experimental data. However, as will be demonstrated, the design engineer should be critical when interpreting the available data.

Acid Gas Injection
As was stated in the first part of this paper, acid gas injection has become an important method for dealing with unwanted acid gas.
A common approach in the design of an acid gas injection scheme is to take advantage of the thermodynamics of these systems. The water content of acid gas mixture has a minimum as a function of the pressure. The design of an acid gas injection project should attempt to take advantage of this minimum, in order to eliminate the need for dehydration(1).

Water Content
An essential aspect of the design of an acid gas injection scheme is the water content of the acid gas mixture. In addition, it is important to know the effect of the state (gas or liquid) of the acid gas on the water content. Table 1 lists experimental investigations into the water content of mixtures containing hydrogen sulfide and/or carbon dioxide.
The study of Selleck et al.(2) is considered the benchmark investigation of the system hydrogen sulfide + water. They published tables of smoothed data, which are commonly quoted in the literature. However, these tables are based on relatively few and scattered experimental data points. Carroll and Mather(3) re-evaluated the phase behaviour in this system, presenting a clearer picture of the equilibria and accurately reflecting all of the available experimental data.
There have been many investigations of the water content of CO2-rich fluids. In general, there is reasonable agreement amongst the various sets of data in the low and moderate pressure regions. The benchmark investigation of the phase behaviour in the system carbon dioxide + water was that of Wiebe and Gaddy(4–6).
Finally, the author of this paper has performed thorough reviews of the literature, and is unaware of any experimental data for the water content for binary mixtures of H2S + CO2 in the public domain. Such data, if available, would be very useful.
There have been several experimental investigations into the water content of hydrocarbons. Table 2 lists those of interest in this study. In this paper, we are not strictly interested in the water content of hydrocarbons, but in acid gas mixtures containing hydrocarbons. We require a model that accurately predicts the water content of hydrocarbons in order to have the confidence that it will work for multicomponent mixtures.
3D Physical Model Studies of Downhole Catalytic Upgrading ofWolf Lake Heavy Oil Using THAI
Authors: Tare T.X. , Greaves M. 
Published: March 2010

Abstract
THAI-"Toe-to Heel Air Injection" is an integrated horizontal process for the recovery and in situ upgrading of heavy crude oil. In addition to thermal upgrading, further upgrading can be achieved by emplacing a catalyst layer around the horizontal producer well, in effect creating a downhole reactor. A series of six catalytic tests was performed in two 3D combustion cells to investigate the degree of upgrading achievable with 10.5 ° API gravity Wolf Lake oil. The main factors investigated were the type of HDS catalyst (NiMo, CoMo), extrudate or crushed catalyst, and catalyst loading. The results of these tests show that the basic process is very stable over a 10-hour period, maintaining an average peak combustion temperature of 500 to 600 °C. Thermal upgrading alone (THAI) achieved nearly 10 points increase in the API gravity of the produced oil. This was increased by a further 4 to 7 ° API using the catalytic process. This indicates that it may be possible to convert a heavy crude oil to almost a light oil product in a one-step in situ reservoir process. The oil recoveries were consistently very high, at around 85% OOIP, with the produced oil having a viscosity as low as 10 mPa's at 20 °C, (i.e., mPa's). The process demonstrated robust stability when changes in the air injection rate were made, and there was also an oil productivity gain when operating at a low water air ratio, WAR &lt; 1.0.

Introduction
Unlike conventional light oil, the production of heavy oil is uch more difficult, mainly due to its high viscosity at reservoir conditions. When the oil viscosity is very high (&gt; 10,000 mPa.s) in the reservoir, the oil is virtually immobile. Cold production of heavy oil only recovers a small proportion of the original oil in place, typically about 5% to 10%. Improved Oil Recovery (IOR) or Enhanced Oil Recovery (EOR) methods are required to increase the oil mobility and improve heavy oil production. Steam injection, vapour extraction and in situ combustion (ISC) are the three main techniques, achieving oil recoveries of more than 50% OOIP. However, expensive surface upgrading processes are required to upgrade the produced heavy oil in order to satisfy refinery feedstock specifications.
ISC is achieved by burning a small fraction of the oil in the reservoir to release the combustion reaction energy between the injected oxygen and hydrocarbons. This greatly increases the temperature in the reservoir, mobilizing the heavy oil so that it can be displaced. The high temperatures (&gt; 500 °C) created during the in situ combustion process promote thermal cracking of the heavier components of the oil, which results in thermal upgrading. This advantage is normally not captured in the conventional ISC operation using vertical-injection and vertical-production wells (VIVP), or other conventional well patterns. This is because the thermally upgraded oil first has to bank-up in the downstream cold region before it reaches the producer well.