bluuebunny/crossref_metadata_2025 huggingface dataset:
An Empirical Correlation for Oil FVF Prediction
Authors: Abdul-Majeed Ghassan H. , Salman Naeema H.
Published: March 2010

A new empirical correlation for predicting oil FVF at bubble point pressure is developed from 420 experimentally obtained oil FVF on 119 oil-gas mixtures collected from four different unpublished sources.

When applied to all data, the newly developed correlation clearly out-performs the existing oil FVF correlations, based on low values of average per cent difference, absolute average per cent difference, and standard deviation.

The present and the existing correlations are evaluated within pre-determined ranges of oil API gravity. Five main ranges of this parameter are selected for best correlations.

Introduction

The oil formation volume factor, Bo, is a factor used to estimate the change in volume of oil as it undergoes a change in pressure and temperature. The change in volume is a combination of thermal expansion, compressibility effects, and mass transfer, which is represented by gas evolving from or going into solution. Therefore oil FVF is the volume of oil at P and T occupied by one stock tank barrel (STB) of oil and the gas in solution. Several empirical correlations have been published that can be used to estimate Bo at and below bubble point pressure (Pb). The most widely used correlations are shown in Table 1.

The scope of the proposed research consisted of developing a new correlation for estimating Bo at and below Pb.

Data Acquisition and Preparation

The analysis of 119 bottom-hole fluid samples were made available for this study. The data bank used (consisting of a total of 425 PVT tests), is obtained from four different unpublished sources. In these sources, the flash separation data were used in conjunction with the values of the flash and differential process to calculate the combination formation volume factor. The calculations were performed assuming that the relationship between the flash and differential liberation processes is constant at any reservoir pressure (the procedure of calculations is described, in detail, in Ref. 2, p. 18).

Each of the PVT tests is examined for unreasonable values. If the observed FVF for a PVT test seemed unreasonable when compared to the FVFs estimated by all the existing FVF correlations (Le. the per cent errors of all the correlations are greater than 10%), the PVT test is eliminated from the data set. As a result, five data points are removed. The revised data bank now contains 420 data points (Table 2). A brief description of the revised data bank is given in Table 3.

Development of the Correlation

Using non-linear multiple regression analysis, the following relation is developed from 420 experimentally obtained oil FVF on 119 different oil-gas mixtures:

Equation (Available In Full Paper)

The same units apply for Rs, Gag, Gao, and T as in the equations shown in Table 1.

The developed correlation meets approximately the requirement for the formation volume factor of 1.0 at 60 °F and atmospheric pressure (R=O). Figure 1 is a plot of the observed Bo values vs the estimated Bo values for the data used.
Surface Tension Of Petroleum Mixtures
Authors: Pedersen Karen Schou , Lund Torgeir , Fredenslund Aage
Published: March 2010

A new correlation has been developed where the surface tension of a petroleum mixtures is related to the viscosity. The calculated results compare well with experimental observations atboth atmospheric and higher pressures. Accurate results are also obtained using a modification of the procedure of Lee and Chien.

Introduction

The surface tension is defined as the partial derivative of the surface free energy with respect to the dividing area between the gas and liquid phases.

Proper estimation of the surface tension of oil-gas systems is important in a number of reservoir engineering calculations. The surface tension is required to predict the capillary pressure of the oil in a porous solid. The surface tension also influences the relative gas/liquid phase permeabilities.

For pure components it has been experimentally observed(1) that there is an almost linear dependence between the reciprocal of the viscosity, η, and the logarithm of the surface tension, σ:

(1) In ( J = In A + B / ρ )

A and B may for pure components be determined by a least

TABLE 1. Results for the surface tension at atmospheric pressure of oils 1–7 and of gas condensate 1. Available in Full Paper.

squares fit to experimental data relating the viscosity to the surface tension. For mixtures it is less obvious how to determine A and B. On the other hand it is desirable to be able to determine the surface tension from the viscosity. Viscosity data are more frequently available than are surface tension data. Also more reliable correlations exist for predicting the viscosity(2, 3) than is the case for the surface tension.

1. Experimental Data

The surface tensions have been measured of eight North Sea reservoir fluids (7 oil mixtures and 1 gas condensate mixture) flashed to standard conditions (1 atm and 15 °C). The surface tensions were measured with an MOM Lauda Ring Tensiometer. The thermalization time was chosen long enough to allow surface equilibrium. For the temperatures reported, repeated measurements on the same sample showed no time effect. The viscosity measurements were performed with a Contraves Low Shear 30 Viscometer. The reported viscosities correspond to a shear rate of 100 S-I. The densities were measured with an Anton Paar-DMA 602H apparatus. The surface tension results for the 8 mentioned petroleum mixtures are presented in Table. 1. The corresponding results for viscosities are shown in Table 2. In Tables 3–10 molar compositions of the 8 petroleum mixtures are given. In addition to the data of Tables 1 and 2, pure component data for ethane, propane, n-butane, n-pentane, n-hexane, benzene, toluene(1) and cyclohexane(4) have been used to develop the procedure of the following section.

Experimental surface tension data for a reservoir fluid(5) has been used to test the predictive capabilities of the calculation procedures at higher pressures. The results are given in Table 11 and the molar composition of the reservoir fluid in Table 12.
The Directly Ploughed Concept For Small-Inch Pipelines - A Modern Approach To Reducing Installed Costs And Minimizing Environmental Impact
Authors: Maki D.R.
Published: March 2010

Coiled and straight length metallic pipeline systems, installed by the direct ploughing technique, are in a period of rapidevelopment. These systems (in 33.4 mm through 168.3 mm sizes) are now available in operating pressures of from 690 to 6900 kPa and provide an economic means of delivering large volumes of gas and liquids to processing facilities at low installed costs.

This paper will deal with developments in installation (ploughing) techniques for metallic pipeline systems, typical cost reductions available through the use of the technique (vs straight length welding and ditching), plus offer suggestions as to further cost reductions available to operators from the land use/easement purchase and environmental reclamation points of view.

Introduction

Oil and Gas Production Operations in Canada – Pipelines and Line Pipe Sizes

The majority of pipelines installed each year in western Canada for direct production purposes by oil and gas developers are in the 60.3 mm to 168.3 mm range; pipeline expansions in large inch pipe are limited, although some are presently being undertaken to deliver more crude, an increased variety of crude blends, heavy crudes and natural gas to specific end markets(1). Crude oil delivery levels to major pipelines have been kept up in western Canada over the last several years due in great part to high drilling rates (in the late 70s, early 80s and 1985) and increased production from the operating Tar Sands Plants. The large-inch pipelines now in place are being debottlenecked and can handle the steady and declining volumes of rudes being delivered to them. This situation will change in the 90s (when there will need to be more large-inch construction projects to deliver reserves from the frontiers), but until then, pipeline construction in western Canada will likely be concentrated in the "small-inch" area and for the following applications:Delivery of oil and gas to existing and new surface facilities.Transport of oil, gas and NGLs to major pipeline facilities for delivery to end markets.Transport of commodities to enhanced oil recovery schemes (gas, water, solvents).Injection pipelines as part of E.O.R. projects (water, solvents).Water disposal pipelines.

In parallel with declining reservoir deliveries and productivity is a natural lowering of operating pressures for the majority of systems. In grid form, the following types of lines can be subjectively classified by their characteristics (operating pressure, burial depth, and corrosivity) and approximate (proportional to the whole) percentages assigned to their sub-categories:

Lines by Type of Characteristics (Table 1)

Table 1 Available in Full Paper.

These Types of Lines do not Need to be Overbuilt!

This analysis is very subjective, but the figure as generated for the above lines is probably not far off the mark and these types of lines also have one other characteristic in common – they can be directly ploughed.
Panther River Well Stimulations - A Case History
Authors: Milligan M.R.
Published: March 2010

During 1986 two large volume stimulation treatments were carried out on two low-permeability (<0.1 mD) Panther River wells. The formation treated was the Mississippian Turner Valley (Mt); a thrust-faulted dense dolomite containing sour gas (average 6% H2S) and found at about 4500 m (15 000 ft). Panther River No.2 was stimulated with a staged gelled pad, retarded-acid frac. Panther River No. 7 was stimulated with a massive propped frac using crosslinked HPG frac fluid and 40/60 sand. One of the objectives was to evaluate the response of low-permeability Panther River wells to these different stimulation techniques.

This paper reviews well and reservoir characteristics, selection of stimulation candidates treatment design and execution, and the stimulation results.

Introduction

The Panther River sour gas field is situated on the eastern slopes of the Rocky Mountains about 100 km northwest from Calgary and 12 km southwest from Shell's Burnt Timber sour gas field (Fig. 1). The Panther River field was discovered in 1958. Development has been gradual due to uncertainty in drilling he deep (up to 5100 m), expensive, low-deliverability wells, and the unavailability of suitable processing capacity and markets for the gas. Currently, Shell has ten wells drilled and cased in Panther River of which two are abandoned.

Total gas in place is estimated to be 58 E09 m3 (2 TCF); unfortunately, the reservoir exhibits low permeability (less than 0.1 mD) and low deliverability.

Two recent events sparked fresh interest in Panther River: 1. natural gas deregulation legislation in Canada provided new market opportunities for Panther River gas; and decline in deliverability from the Burnt Timber wells has created capacity at nearby Burnt Timber sour gas plant. As a result, Shell is proceeding with construction of facilities to connect five Panther River wells to the Burnt Timber gas plant with production to start in 1989.

Prior to construction of the gas gathering and compression facilities, two wells were selected as stimulation candidates to improve their deliverability and increase recoverable reserves. Massive hydraulic fracture (MHF) stimulations in similar tight gas reservoirs elsewhere had yielded promising resu1ts(1, 2).

Stimulation Candidate Selection

Hydrochloric (HCl) acid stimulations had been previously performed on all wens but one: Panther River No.2 was only drill-stern-tested (DST'd). Table 1 summarizes the acid jobs performed on Panther River wells prior to 1986 and some results calculated from post-frac pressure build-up test analyses.

These acid treatments were pumped at above formation fracture pressure, at the maximum pump rate possible and without leak-off control. It can be seen from Table 1 that the HCl acid stimulations were successful in removing near well bore damage and the creation of short conductive fractures (mostly less than 16 m). The short fracture lengths were believed to have been caused by: uncontrolled vertical fracture growth, small treatment volumes, and high leak-off due to acid wormholing and natural fractures.
A New Approach For Analysis Of The Nuclear Magnetic Log - Resistivity Log Combination
Authors: Aguilera Roberto
Published: March 2010

A new method is presented for analysis of the nuclear magnetic (NML)-resistivity log combination (NML is a Schlumberger Trade Mark). It is shown that a crossplot on logarithmic coordinates of effective porosity (Φe), as determined from neutron and density logs, minus free fluid porosity (Φft) as determined from the NML log vs true formation resistivity should result in a straight line with a negative slope equal to the water saturation exponent, n, for intervals which are at irreducible water saturation.

Extrapolation of the straight line to Φe- Φft = 1.0 yields the product aRw in the true resistivity scale. With these data, values of water saturation are readily calculated. Intervals with moveable water fall distinctly below the straight line, Gas-bearing zones plot above the straight line.

The method is illustrated with the use of a high-porosity sandshale sequence, Estimates of formation permeability and water cut are included in the analysis, A word of caution is raised with respect to the concept that the product ΦeSwi should remain constant for intervals of the same lithology at irreducible water saturation.

A major finding is that water resistivity can be calculated from the NML-Resistivity combination in reservoirs which (1) produce clean oil with no water, (2) have a poor SP development. (3) do not have a well established aquifer, and (4) do not have enough data so as to allow generation of water resistivity catalogues.

Introduction

The nuclear magnetic log (NML) has an approximate radius of investigation of one inch. It measures the earth's field proton free induction decay of formation fluids. As such the tool responds only to hydrogen protons associated with free or moveable fluids in the formation(l).

This characteristic allows the NML, when combined with other porosity logs, to calculate irreducible water saturation, Swi in turn can be used for estimating permeability based on empirical correlations.

A comparison of water saturation as determined from Archie's equation(2) and irreducible water saturation as determined from the NML permits a forecast of fractional water cut for an untested interval.

In carbonates, the NML tool reads close to total porosity due to the carbonates small surface activity(3). The tool is not affected by hydrogen protons in the matrix. This makes it valuable for determination of porosity in unusual lithologies containing extensive water of hydration (for example gypsum) where nuclear tools tend to give very large values of porosity(l).

In formations with light oil, the NML tool gives porosities that include this free oil. In formations with very heavy oil, the NML reads the free water filled porosity. Because the tool radius of investigation is only about 1 in, the NML reading might allow determination of hydrocarbon saturation in the flushed zone.

Neumann(4) has reported on the use of the NML for estimation of residual oil saturation. In this approach, the oil zone is invaded by mud filtrate containing paramagnetic ions.
Lanthanide Fingerprinting And Acidification Of A Glacial Till Soil
Authors: Thimm H.F. , Weleschuk I.T.
Published: March 2010

A glacial till soil from southwestern Alberta was examined in terms of its lanthanide, Th and Sc content in order to establish a lanthanide labelling technique or soil type. It is shown that this technique may also be applicable in acidic soils. The acidification of the soils tested showed that the soils were capable of at least partial, natural pH recovery. This behaviour was found to be due to the presence of two minerals, one of which war confirmed as monazite, a tertiary rare earth phosphate; calcite, dolomite or albite (feldspar) contributions to this pH control were not important. Some implications of this result with respect to environmental monitoring at sour gas plants are discussed.

Introduction

In a previous paper(1), we reported on the use of lanthanide (rare earth) element abundances as an investigative tool for estimating the degree of pollution of pond sediments at a sour gas plant. The original intent in that work was to use the lanthanides as markers for trace element migration in soils subject to the deposition of sulphuric acid precursors. Instead, the hypothetical migration could not be detected, and the lanthanide abundance data implied that even where there is a high acidification potential due to sulphur dusting, the elements may serve better as a fingerprint for the identification of soil strata.

The ability to label soils and sediments by lanthanide abundance might have numerous applications, apart from the utility in environmental assessment during decommissioning of gas plants which we have already reported(1).

The present work deals with the examination of soil data from the Pincher Creek area of southwest Alberta to confirm both the soil labelling ability and the implied lack of sensitivity to deposition of acids. Because it is known from the previous work that the metals in question are easily stripped off the soil with 2.5 M sulphuric acid, it is also necessary to know the soil pH range in which the lack of acid sensitivity can no longer be assumed. Finally, it is of interest to compare the ease of metal removal from glacial till soils with data from the acid precipitation work at Hubbard Brooks, New Hampsttire(2,3) and others(4,5). There have been reports of groundwater pollution by metals released from acidified soils(6). In Alberta, the occasional deficiency of copper in livestock feed has been speculatively linked to the deposition of acidic gases to soil(7).

Study Area

The area chosen for study (Fig. 1) is located in the extreme southwestern comer of Alberta. Two sour gas processing plants had been operating in this area for over 25 years at the time of soil sampling (1983). Emissions for both plants typically totalled 40 t/d SO2 with particulates at 200 kg/day. Prior to 1972, SO2 emissions were substantially higher, near 130 t/d.

The area shown in Figure 1 may be divided into two major soil Types(8). Soils developed from glacial lake bottom material extend to the southeast of Pincher Creek townsite, and then south to the Waterton Reservoir.
Computer Calculations Of Compressibility Of Natural Gas
Authors: Abou-Kassem J.H. , Mattar L. , Dranchuk P.M.
Published: March 2010

An alternative method for the calculation of pseudo reduced compressibility of natural gas is presented. The method applies the definition of reduced compressibility (Equation Available In Full Paper), where both Pr and (Equation Available In Full Paper) are variables available as DR and DP in both the Dranchuk et al. and Dranchuk and Abou-Kassem Z-Jactor subroutines. This method is incorporated into these routines by adding a single FORTRAN statement CR = O.270/(DR*DP}before the RETURN statement. This method is suitable for computer and hand-held calculator applications. It produces the same reduced compressibility as other available methods but is computationally superior.

Methodology

The methods of calculating compressibility of natural gas are derived from the following relationship between C and Z:

Equation (Available In Full Paper)

Trube(1) presented a graphical correlation of cr as a function of Pr and Tr based on equation (2) using the Brown et al. (2) Z-factor chart. While this correlation is useful for hand calculation, it is not suited to computer usage. Mattar et al. (3) used the following expression for cr that was based on the manipulation of equation (2)

Equation (Available In Full Paper)

Although the last two methods are suited to computer usage; they require the Dranchuk et al.(4) Z-factor subroutine that calculates Z which in turn would be used to calculate Pro Both Z and P, are used in equations (2), (4), (5), (7) and (8). Close examination of the Dranchuk et al.(4) Z-factor routine reveals that this routine solves for Pr for a given Tr and Pr using the Newton-Raphson iteration. The form of the equation used is

Equation (Available In Full Paper)

The suggested approach is applicable to all equation-of-state based romines for calculating Z-factor (e.g. Hall and Yarborough(6), Dranchuk and Abou-Kassem(7). Because of the similarity between the Dranchuk et al. (4) equation and the Dranchuk and Abou-Kassem(7) equation (based on BWR EOS), and the wide-spread use of these two routines for predicting Z-factor, the following is an account of why and where to incorporate necessary modifications to calculate cr in both routines using the suggested approach. These two equations can be expressed in a general form as:

Equation (Available In Full Paper)

Finally, the numerator in the right-hand-side of equation (13) is represented by DP in these routines. Therefore, A statement for Cr that is based on equation (11), may be incorporated in both routines by inserting the following FORTRAN Statement before the RETURN statement:

Equation (Available In Full Paper)

The modified versions or both the Dranchuk el al. (4) and Dranchuk and Abou-Kassern(7) routines, which were tested and verified to reproduce the Mattar et al.(3) graphical correlation for er are presented in Appendix I and Appendix 2 respectively. The results of the various method considered in this paper are compared in Table 2 for T, = 1.05, l.5, 2.5 and 3.
Wellbore Flow Resistance In Steam-Assisted Gravity Drainage
Authors: Ong Tee S. , Butler R.M.
Published: March 2010

The potential for the more economic recovery of heavy oil has encouraged many researchers to investigate the steam-assisted gravity drainage process. These studies have usually involved physical models. One problem which is encountered is in the scaling of a field well to a laboratory well. In this paper, from considerations of the pressure gradient along the well, it is shown that the scaling factor for the radius of the horizontal well Is not proportional to the geometrical ratio for the laboratory model and the field but to the one-fourth power of this ratio.

A computer program was developed to predict the pressure profile of the production well, the oil flow rate along the well and the gravity head of the heated oil backed up by the flow resistance of the well. The computer program was used to study the effect of the viscosity of the fluids (or the wellbore temperature) within the well, the well size and the well length. Calculations performed by the computer program shows that the drainage of the produced fluids can be Impeded if the wellbore temperature is too low or if the well size is too small.

Introduction

Canada has abundant deposits of heavy oil. The potential of using horizontal wells for the recovery of these deposits has encouraged many researchers to investigate the steam-assisted gravity drainage (SAGD) process using physical models. In the SAGD process steam is injected continuously so as to form a "steam chamber". Oil drains from around the perimeter of the chamber to a production well which is located below. Gravity provides the driving force which causes the heated oil to flow. Because gravity drainage is relatively slow, a horizontal production well is employed so as to provide more reservoir contact and greater production. As the steam condenses the condensateis removed along with the draining oil. The steam chamber grows in size as the process continues. The process is illustrated in Figure 1.

he principal driving force for the drainage of produced fluids toward the perforated horizontal well from around a constant pressure steam chamber is the fluid static head (or gravity head). Some of the available head must be used to drain the produced liquids that flow along the wellbore. It is crucial that the size of the horizontal well be sufficiently large so that the head dissipated in moving the produced fluids along the well is not excessive. Erroneous experimental results (oil production rate or steam chamber propagation rate) can be obtained in laboratory models if the wellbore flow resistance is excessive compared to that in the field.

In this paper, the effect of wellbore flow resistance has been studied and it is found that laboratory models require surprisingly large wellbore radii.

Scaling the Horizontal Well

For scaling of field conditions to laboratory conditions, Butler(1) proposed that the dimensionless number. B3 and the dimensionless time, T', must be equal for both field and laboratory conditions.
The Changing Nature Of The Canadian Oil And Gas Business
Authors: Slagorsky C. , Fraser B.
Published: March 2010

Introduction

The international petroleum industry ranks as one of the most important industries in the world. In 1989, the value of total world trade in crude oils and refined products alone exceeded US$2.0 trillion. More than 11 billion barrels of crude and products were traded internationally. In addition, more than 10 Tcf of natural gas crossed international boundaries (Fig. 1).

Over the last 20 years, the industry has gone through a series of unprecedented changes. The structure of the industry has evolved from an ordered world managed by the majors, through a transitional period in which OPEC controlled prices, to the uncontrolled and highly volatile world of commodity pricing today. Over this period, oil has also become less important to the industrialized economies as an energy source. Between 1973 and 1988, the OECD countries cut their energy use as a proportion of output by 25%. Their oil use as a percentage of output fell by 40%.

These changes have had a profound impact on the North American industry. For instance, in the U.S., one half of the 25 largest oil companies in 1950 were no longer in that grouping by 1980. Of the 25 companies listed in 1980, only 17 exist today. In Canada, concentration of reserves ownership increased. The largest companies controlled 68% of total oil reserves and 53% of total gas reserves in 1984. By 1988 these figures had increased to 80% and 63%, respectively.

The two price shocks in 1973/74 and 1979/80 gave the North American upstream industry a boost. In the U.S., higher prices perpetuated oil exploration in a region which ranks as one of the highest cost producing areas in the world and is the world's most drilled up geological province. In Canada, exploration expenditures and reserves increased. The oil price collapse of 1986 again changed the business fundamentals. In a "low-price world ", it forced industry to change once more and embark on a long and painful process of restructuring, asset rationalization and cost cutting.

The considerable challenge for the North American industry is that the bulk of world proven reserves can be produced profitably at US$15.00/bbl or less. This sets a target long-run cost ceiling for the North American oil industry. This is a tremendous challenge. Both oil finding costs and the cost of doing business generally are higher in North America relative to the rest of the world. Thus, the main challenge facing the North American oil industry is how to prosper in a low oil price environment.

In Canada, the policy response to the two oil price shocks during the 1970s was a sharp rise in industry regulation. The federal government followed a policy of "made in Canada" pricing (i.e. an oil price lower than the world price). This generated bitter disputes over fiscal transfers between the producing provinces which owned the resource and the consuming provinces, and between the federal and provincial governments. It also discouraged exploration and development investment in conventional areas.
Well Testing In Alberta — 1990s Style
Authors: Warren A.
Published: March 2010

This paper presents the highlights of a new guide for well pressure and deliverability testing in Alberta. The guide was developed by a joint Industry-ERCB committee to reduce test costs, improve test quality, and clarify testing regulations. New requirements define quality pressure survey methods, and the minimum number of tests that should be run for prudent reservoir management. Relief from testing is provided for advanced depletion, small reserves, low permeability, heavy oil, low productivity, and reduced spacing. In addition, testing costs are reduced by accepting pressures from shut-in wells, acoustic methods, and drill-stem tests, under certain conditions. Operators can choose the type of deliverability test they run: single- vs multi-point. Tests can be scheduled to optimize field operations. The new well testing environment for the 1990s should become less regulated but this requires that the operating industry be committed to quality testing in accordance with the new guide. The industry, the ERCB, and the public stand to gain from this new approach to data gathering.

Introduction

In 1989, it cost over $250 million dollars to run pressure and deliverability tests for Alberta's oil and gas wells. This cost is expected to increase significantly, throughout the 1990s, as more wells are needed to supply existing and new markets for oil and gas. The time has come to ensure that we get the most from future testing dollars by carefully examining our data needs and test procedures.

The Energy Resources Conservation Board (ERCB) has a mandate(1) to provide for the gathering and dissemination of information regarding the energy resources of Alberta. Accordingly, it developed regulations(2), as early as 1961, for the taking and reporting of well tests. The purpose of these regulations is to ensure adequate quality pressure and deliverability data, for use in engineering and economic studies of Alberta's oil and gas pools. Over the years, these regulations were revised a number of times in response to the changing needs of the ERCB, and the operating industry.

In 1987, a joint Industry-ERCB technical committee (the committee) was formed to review the ERCB's well testing regulations. The review has resulted in the development of a new guide for well testing(3). A draft of the new guide was distributed to several industry associations: IPAC, CPA, SEPAC, and CIM, for their comments. Their responses suggest that the guide was well received but that further effort is needed to clarify its contents.

The ERCB decided to release a first edition of the guide in the second quarter of 1990. This was done to give both the ERCB and the industry an opportunity to work with the revised requirements, and benefit from them without delay. The ERCB has asked the committee for a review of well testing under the new guide in mid-1991. Any problems encountered can be addressed in a second edition of the guide. Assuming no major problems remain, the ERCB will formally adopt the second edition or the guide as part of its regulations.
Correlations Developed To Predict Two-Phase Flow Through Wellhead Chokes
Authors: Abdul-Majeed Ghassan H. , Maha R. Abdul-Ameer
Published: March 2010

The predictive accuracy of ten critical two-phase flow correlations in combination with four PVT property correlations, is tested against field measured production data, from 210 well tests, covering a broad range of production rates, choke sizes, upstream pressures, gas-liquid ratios and oil API gravities. Test data are divided into four selected categories based on choke size (D) : D <6, 6 ≤D <10, 10 ≤D <30, and D ≥30/64 ".

The average per cent error, absolute average per cent error and standard deviation are computed for each correlation combination.

It is observed that the choice of empirical PVT correlation appears to have only a minor effect on final calculated statistical results. Also it is found that most of the compared correlations yielded unsatisfactory results, therefore an attempt is made to find correlations that best fit the measured data. As a result, four new correlations are developed (a correlation for each diameter category).

Based on the statistical results, the new correlations clearly outperformed the original correlations.

Introduction

Several correlations have been published for describing critical two-phase flow through wellhead chokes. Most of these correlations were based on limited ranges of flow variables. Their validity is limited by the quality and scope of the data upon which they are based.

The objectives of this study are:to determine the optimal combination of critical flow and PVT correlations for predicting flow rates; andto modify the existing correlations if necessary or develop new correlations that best fit the measured data.

The correlations compared are those of Gilbert(1), Ros(2), Baxendall(3), Achong(4), Poettmann-Beck(5), Omana(6), Ashford(7), Pilehvari(8), Sachdeva et al.(9) and Hazim-Ghassan(10). Some of the correlations require values of fluid physical properties, combinations of the following PVT correlations are used to estimate them:

Oil FVFStanding(11)Vazquez-Beggs(12)Ghassan-Naeema(13)

Solution GORStanding(11)Lasater(14)Vazquez-Beggs(12)

In addition, other PVT properties are calculated using the following correlations:

Gas Compressibility : Hall-Yarborough(15)

Gas-Oil Surface Tension : Baker-Swerdloff(16)

The performance of each critical flow/PVT correlations was checked against the measured well data. Statistical tools were used to determine the optimum correlation combination for predicting flow rates.

Well Test Data

Fifty-six tests from Iraq wells, 108 from Poettmann's study(5), 27 from Ashford's study and 37 from Omana's study are combined in a data bank for this investigation. The approach developed by Sachdeva et al.(9) (Eq. 1) is used to verify that the test data collected are within the critical flow regime rather than subcritical flow regime.

Equation (1) (Available In Full Paper)

Where

Yc = critical pressure ratio

x1 = free gas quality

VG = gas specific volume, ft3/lbm

VL = liquid specific volume, ft3/lbm
Gravity Drainage To Horizontal Wells
Authors: Butler R.M.
Published: March 2010

Pressure depletion and high water-oil ratios limit the recovery which can be obtained from many oil reservoirs using conventional methods, to disappointingly low values.

The maintenance of pressure by water injection (waterflooding) or by gas injection can be relatively ineffective because of the tendency of the injected materials to finger through the oil.

Although the density difference between oil and gas allows gravity segregation to improve the picture for downward f/ooding with attic gas injection, the tendency for the gas to finger down to the production well for practical production rates, limits the improvement with conventional wells. Horizontal wells can change the picture because of their much lower drawdown requirements.

In this paper, the production of heavy oil reservoirs by gravity drainage with a gas cap advancing down toward horizontal wells is analyzed theoretically. It is assumed that reservoir pressure is maintained by the injection of gas at the top of the reservoir and that the production rate is controlled to just below the critical rate for gas coning. The theory indicates that, for such conditions, recovery rates of the order of several hundred B/day are possible and that relatively high recoveries can be achieved. By maintaining the pressure of the production well equal to that of a lower aquifer, it is possible to carry out the above operation without excessive water production.

Introduction

This paper discusses the production of oil by displacement created by the downward expansion of a gas cap. The displaced oil flows to parallel horizontal wells located near to the base of the reservoir. It is assumed that the gas pressure is maintained constant by injection and that the low viscosity of the gas, compared to that of the oil, maintains a constant pressure within the cap. The conditions are chosen so that gravity effects prevent the flow of free gas to the production wells; i.e. the process is carried. out below the critical coning velocity(l). The process is one of gravity drainage and can be expected to give high recovery(2,3).

While such a process can be carried out using arrays of vertical wells, it is much more effective with horizontal ones, particularly if they are closely spaced. The effect of pattern size and shape for horizontal wells has been analyzed in recent papers(4,5) and it has been shown that for close spacings (but not so close as to be economically unfeasible) the productivity index for pseudo steady-state flow to horizontal wells can be as high as 50 to 100 times that for vertical wells drilled on the same aereal spacing.

The practical significance of this, for the situation considered here, is that operation below the critical production rate may be feasible for horizontal wells in situations where it would be impractical with vertical ones. In such situations, the gas injection which is required for pressure maintenance is simply that to replace the produced oil on a volume basis plus a minor amount which is dissolved.
Applications Of Mixed-Wet Pastes In Gravity Drainage Experiments
Authors: Catalan L. , Dullien F.A.L.
Published: March 2010

Mixed-wet pastes consisting of a mixture of water-wet grains, oil-wet grains, brine, and oil can be used to overcome some of the limitations generally associated with gravity drainge experiments in the laboratory. Semi-permeable membranes made with mixed-wet pastes having grain sizes no larger than a few microns are able to prevent the gas breakthrough and eliminate capillary end effects. Pastes with larger grains are suitable to establish capillary continuity at the junction between short reservoir plugs in a composite core.

Prevention of the Gas Breakthrough and Elimination of Capillary End Effects

During gravity drainage experiments assisted by inert gas injection and carred out in vertical cores initially saturated with oil and brine it has been shown that the gas breakthrough occurs before the totality of the oil bank has been produced, even if the production rate is kept very small(1,2). After gas has broken through, some additional oil can be produced, but nevertheless, a part of the oil initially present will remain in the bottom part of the core. Experiments done in our laboratory with a four-fool long vertical Berea sandstone core have shown that the oil saturation at the bottom end is approximately 80% at gas breakthrough, and it decreases with height. Naylor and Frorup(2) used radioactive tracer techniques to measure fluid saturations within a 0.885 m long aeolian sandstone core during a tertiary gravity drainage experiment in which nitrogen under low pressure was flowed continuously through the core. After 86 days of gasflood, the oil saturation was 8% in the top half of the core and increased in the bottom half to reach 31% at the bottom end. The phenomenon of this oil retention in the bottom pan of the core is a capillary end effect. It is due to the gas pressure and therefore the gas-oil capillary pressure being low near the bottom when gas is flowing through the core. A detrimental consequence of the end effects is that, everything else being equal, the percentage of recovery of residual oil increases with the length of the core. Indeed, as the length of the core increases, so does the thickness of the oil bank, compared with the vertical distance over which capillary retention takes place (approximately 40 cm in Berea).

The most obvious solution to producing the remaining oil is to eliminate the capillary end effects, and this can only be achieved by preventing the breakthrough of gas_ A semi-permeable membrane, which is put in contact with the producing face of the core, was developed for this purpose. This membrane must be mixed-wet, that is, permeable to oil and brine, but impermeable to gas. With the membrane in place, it is possible to establish a sufficiently high oil-gas capillary pressure in the bottom part of the core to eliminate the capillary retention of oil.

In order to prepare the mixed-wet paste from which the semi-permeable membrane is made, very fine powders of calcium carbonate (water-wet) and active carbon (oil-wet) need to be obtained.
Detection Of Gas Migration Behind Casing Using Ultrasonic Imaging Methods
Authors: Forbes D. , Uswak G.
Published: March 2010

Failure of the cement, providing zonal hydraulic isolation on the outside of the production casing, occurs in some wells and can result in upward migration of gas behind the casing. Such a cement failure might result in a gas flow from the surface vent connected to the production by surface casing annulus. Or, if the vent is closed, the gas might build sufficient pressure at surface to break down the formation strength at the casing shoe and thereby migrate up around the wellhead itself.

Prior to attempting repairs, both the location of the gas source and the potential to displace the annular space with cement must be evaluated. These may be determined from an ultrasonic image obtained from the Cement Evaluation Tool (CET*).

Temperature and audio logs attempt to detect the actual movement of the gas flow which may be very small and difficult to detect. In such cases the CET image has shown a significant presence of gas filled channels from the source zone up to the surface. Log examples pinpoint probable gas sources and identify annular materials enabling successful remedial cementing strategies to be developed.

Introduction

The Problem of Surface Gas Migration

There are a significant number of wells today leaking gas to surface. In Alberta, Energy Resources Conservation Board statistics indicate that, in 1988,4.7% of wells in Alberta had surface casing vent flows compared to 2.6% in 1931(1). Potential environmental effects include ground water contamination and release of hydrocarbon vapours to the atmosphere.

How much gas is a serious problem? What is the cause of the leak? Can it be repaired? How? When should it be repaired? immediately or if not serious, at time of abandonment? Many of these questions are being evaluated by regulatory agencies as well as energy companies. As we enter the 1990s, the onus will be on energy companies to reduce the number of wells that have surface gas leaks.

Data is needed to evaluate these problem wells and develop remedial action plans. Part of the data required can be obtained through wireline logging techniques. These measurement techniques have had a measure of success detecting movement near the completed interval in a well. Figure 1 illustrates subsurface gas migration resulting in a surface flow at the casing vent valve.

The Gas Migration Advisor (GMA) is a new wireline logging technique that employs ultrasonic imaging to identify the contents of the casing annulus as gas liquid or solid.

Quantifying and Measuring the Problem

Historically, gas leak detection has been accomplished with varying degrees of success by logging with noise and temperature tools(2). The noise tool responds to audio signals. Detectable signals are caused by fluid or gas moving turbulently through a sufficient pressure differential. By examining the tool response at different locations in the well, significant movement behind casing can be detected leading to an identification of the source of the gas (Fig, 2).

The temperature tool measures the temperature in the wellbore.
Carbon Dioxide Flooding As An Enhanced Oil Recovery Process
Authors: Mungan N.
Published: March 2010

Synopsis

In earlier work(1–5), the fundamental and the field applications of carbon dioxide flooding were described. The presentation(5) at the Western Regional Meeting of SPE in 1991 focussed on a comparison of CO2 flooding for light and heavy oils, with examples from the field showing that CO2 flooding has recovered significant amounts of incremental oil under miscible as well as immiscible conditions. Carbon dioxide flooding for the enhanced recovery of heavy oils is important for Canada since it provides an alternative to thermal recovery. In this article the author will attempt to illustrate the state-of-the-art on CO2 flooding in general and how CO2 flooding relates to the recovery of heavy oils in particular.

Introduction

There is a great deal of industry interest in CO2 flooding as evidenced by the large number of field applications which have been initiated in the past decade(6). Additional field tests are certain to be carried out when CO2 supplies of acceptable purity and volumes are found. All major petroleum research centres, institutes, universities and government research institutions have projects relating to CO2 flooding. With two exceptions, the process normally involves the injection of CO2 initially, followed by a period in which CO2 is alternated, as small slugs, with another fluid, and terminates, with the injection of the principal driving or chase fluid which would be either water or gas. The two exceptions are the carbon dioxide stimulation process which is carried out in producing wells and is a stimulation technique very similar to a ""huff-and-puff' scheme. The other exception occurs in reservoirs which have such low pressure that they must initially be pressurized prior to the injection of CO2. Normally, such pressurization is by injection of water.

Carbon dioxide flooding may be carried out either as a miscible or as an immiscible oil recovery process and has been studied in the laboratory or practiced in the field in the following modes:carbon dioxide stimulation;continuous CO2 injection;simultaneous injection of CO2 and water;alternating slugs of CO2 and water;injection of CO2 with H2S;injection of CH4 and CO2;CO2 and N2 mixtures;the CO2, SO2, combination;CO2 and LPG mixtures; andLPG followed by CO2.

The most common way that CO2 flooding is being applied in approximately 60 depleted light oil reservoirs in the United States has been to initially repressurize the reservoir to the minimum miscibility pressure by injecting water. In a few cases, repressurization was accomplished by injecting CO2 from the start. Of course, this can be costly. For a reservoir depth of, say. 2500 m, one can expect the minimum miscibility pressure to be about 16 MPa and the reservoir temperature to be 90 °C. At these conditions, 350 m3 of CO2 would approximately equal 1 m3 in reservoir volume. Depending on the size of the reservoir and the cumulative past production the CO2 requirements can prove to be prohibitive.