bluuebunny/crossref_metadata_2025 huggingface dataset:
Revitalization Of The Pembina
Authors: Krasey Rusell , Jackson Marc
Published: March 2010

Over the past eight years, 1981 to mid-989, Canadian Occidental has invested $16,300,000 in the revitalization of the company's Pembina properties. A total of$3,800,000 was invested in 83 fracture stimulations yielding an average payout period of just over one year and incremental reserves per job of 2130 m3. The stimulated wells are currently producing 45 m3/day of incremental oil yielding $1,650,000/year of additional revenue/or the Pembina operation. A total of $12,500,000 was invested in 33 infill wells and their associated facilities. The infill wells have an average payout period of 2.5 years and the estimated incremental reserves per well of 10 930 m3. The infill wells are currently producing 80 m3/day of incremental oil yielding $2,000,000/year of additional revenue. Canadian Occidental's program has increased the current annual revenue to $5,550,000 from an estimated $1,900,000 if none of the work had been Carried out. The increase is significant considering the majority of the work has achieved payout. The work carried out by Canadian Occidental ensures continued profitability and life from the field in the future.

Introduction

The main purpose of this paper is to prove to the industry that the Pembina Oilfield can be a source of significant reserves and revenue in the future. Huge gains in productivity cannot be expected but sustained economic development can take advantage of the already existing infrastructure with excellent returns in both production and profit.

Cities-Service/Canadian Occidental has been active in the Pembina Oilfield since 1956 and was instrumental in setting up many of the units in the field. The company's first waterfloods were initiated in 1961. The company also experimented with gas/LPG injection in both Bear Lake and Keystone. By 1965, most of the Pembina Cardium had been unitized and the majority was under waterflood.

Canadian Occidental currently operates 412 wells in the field with 15 batteries and 76 satellites and one gas plant located in Keystone, Of the 412 wells, 282 are producing, 65 are injectors and 65 wells are shut-in. Production from the field, on a Lease Gross Basis, currently averages 420 m3/day of oil, 112 103/m3day of gas, and 1850 m3/day of water as of November 30, 1989. Production on a per producing well basis averages of 1.5 m3/day of oil, 0.4 l03m3/day of gas, and 6.6 m3/day of water.

The average producing well operating cost, including battery, shut-in well and injector costs, currently averages $28,800/year. Using a price of $120/m3, the break-even production rate for a Pembina well is 0.7 m3, /day. Over-all, the field is still profitable, but every means had to be taken to increase production. Because the operating cost is not directly proportional to production rates, a 50% increase in production may only equate to a 10% increase in operating costs. Canadian Occidental's Engineering staff in Drayton Valley used the following criteria when choosing fracture stimulation candidates. Explanations into what was looked for in each criteria is also included.
Reservoir Simulation Integrated with Geomechanics
Authors: Tortike W.S. , Ali S.M. Farouq
Published: March 2010

Petroleum reservoir simulation has reached a point where it is desirable, and often necessary, to couple fluid and heat flow with the geomechanics of thereservoir and the surrounding rocks. The first step in this direction was Geertsma's hypothesis concerning pore compressibility in an elastic porousmedium, and its local relationship to fluid pressures. The evolution of thiscoupling of the solid matrix response to the changes in fluid pressure isdiscussed for materials with more complex behaviour than linear elasticity, andfor when temperature changes add new loads to the structure. A general coupledreservoir geomechanics model for thermal reservoir modelling is presented. Theresults of an implementation of this model are presented for coupled anduncoupled analyses of the stress and fluid pressure responses to cyclic steaminjection in a tar sand, a material with elastoplastic behaviour. The materialand fluid response to coupling was moderately different to that withoutcoupling, with principal stress rotations occurring at later times. The model, however, was also providing the complete distribution of stresses throughoutthe simulated domain, and the changes in porosity appropriate to a sandundergoing shear failure. These changes were noticeably different from thevariations in porosity obtained when only considering linear elastic porecompressibility.
MTBE: A Carrier For Heavy Oil Transportation And Viscosity Mixing Rule Applicability
Authors: Anhorn J.L. , Badakhshan A.
Published: March 2010

The pipeline transportation of bitumens is made difficult by the excessive viscosities of the heavy oil. The current solution to this problem has been the addition of C4+ paraffinic liquid hydrocarbons. There are a number of drawbacks, however, to the use of this diluent. To overcome these difficulties the alternate use of MTBE (methyl tert-butyl ether), a gasoline additive, as a liquid solvent has been investigated. With the potential for Alberta to become a substantial exporter of both bitumen and MTBE, the prospect of transporting the two constituents simultaneously is promising.

A liquid viscosity model has been utilized to calculate the component viscosities as a function of temperature, and then use a mixing rule to determine blend viscosity as a function of composition. It was found that the addition of 25–30% MTBE (mass basis) was sufficient to reduce the viscosity of the Cold Lake bitumen to meet pipeline specifications. The viscosity model was found to be accurate over the entire range of compositions and temperatures examined. A simple distillation was performed on a 35% MTBE (mass basis) blend to study the ease of separation of the liquid diluent from the heavy oil phase at atmospheric conditions.

Introduction

The most detrimental factor in the production and transportation of bitumen is its excessive viscosity. A typical Cold Lake heavy oil will have a viscosity greater than 500,000 mPa-s at 4 °C, while the viscosity of a typical conventional oil may be 3–4 orders of magnitude lower(1). An increase in temperature of the bitumen has been shown to greatly reduce its viscosity(2). This temperature-viscosity relationship is used in many enhanced oil recovery (EOR) techniques to produce heavy oil and bitumen at economical Rates(2). However, to adequately heat an entire pipeline for the length of the transportation is clearly unrealistic. The current solution to this problem has been the addition of liquid diluents to the bitumen to reduce its viscosity.

The most common diluent used in this manner is a C4+ paraffinic liquid hydrocarbon (or condensate) obtained from natural gas processing. This solvent generally achieves the needed viscosity reduction, but also has some inherent drawbacks. The availability of this liquid hydrocarbon is sometimes in question, and there may not be sufficient buyers to purchase the solvent at the end of the transportation. In fact, many suppliers of the bitumen consider the diluent to be a lost expense, and do not expect to be reimbursed. Also, the solubility of the solvent in the bitumen may pose some difficulties. The bitumen can be diluted with the condensate up to a critical dilution ratio, after which asphaltene deposition occurs(3,4). Therefore it can be seen that the ideal solvent choice is one which would achieve the required viscosity reduction, not cause the asphaltene fraction to precipitate, and also possess a substantial consumer market.
"Is There a Future For the Canadian Oil And Gas Industry?"
Authors: Cleland N.
Published: March 2010

My answer to the question, "Is there a future for the Canadian oil and gas industry?" is a plain, straight-forward and absolutely positive "YES!" Now, before you accept my confident answer on the future of this industry, you'd no doubt like to know why I am so optimistic. There are a number of very good reasons why my answer to the query. "Would you recommend a career in the oil business?" is an unequivocal "yes. "

Industry Maturity

Everybody recognizes that the industry is different now than it was during the first 40 years after the Leduc discovery in 1947. Remaining reserves of oil have been declining since the early 70's, while remaining gas reserves have been on the way down since the mid-80's. The combination of these two events has caused the industry to move from the "development stage" of its evolution to the "depletion stage" of its existence. This new stage reflects the maturing of the development of the Western Canada Sedimentary Basin. It results from the increasing difficulty in finding new reserves.

The mistake a lot of people make is to assume that the change from development to depletion heralds the end of industry activity. This is not the case. The industry will have the cash flow to continue its exploration and development at a high level for the next half century. The sunset years are still a long way away. With time, the Basin will change from being weighted towards oil production to being weighted towards gas production. This merely reflects the earlier development of the oil reserves in the Basin.

Remaining Reserves

How much all and gas do we, currently have left to produce and what can we expect to add in the future? It's important to note that more than 70 per cent of the remaining gas reserves forecast in 20 years' time have not yet been discovered. The situation for oil is less dramatic, but new oil discoveries will still be very significant in the future.

If crude oil is considered to include Light, medium and heavy crude, bitumen, synthetic crude and pentanes plus, there were 7.5 billion barrels left to produce at the end of 1992 from the 25 billion barrels discovered to that date. We've produced 70 per cent of the oil discovered so far. There were 68 Tcf of natural gas remaining to be produced at the end of 1992 from the 145 Tcf of gas discovered to that time. Cumulative production of gas is only 55 per cent of discoveries to date.

In addition to these discovered reserves, it is forecast that 75 Tcf of gas reserves will be added in the next 20 years. New oil reserves to be discovered in the next 20 years are expected to amount to 4 billion barrels. The amount of exploration and development required to add 75 Tcf of gas and 4 billion barrels of oil will keep the industry very busy during the next 20 years.
Analysing Pressure Buildup After a Multiple-rate Drillstem Test In a Well Near a Fault
Authors: Exall D.I.
Published: March 2010

The analysis of pressure buildup data in a well following a multiple-rate flow test is made more difficult if the well is near a fault. Although both these cases have been treated independently in the literature, the combination leads to a more complicated expression for the predicted pressure behaviour after shut-in.

The theoretical expressions for the post shut-in pressure and the skin on the well are derived from first principles. The predicted pressure response is compared with the measured pressure buildup data from a well in the Apiay field in Colombia, and values are obtained for the permeability of 615 mD and distance to a fault of 160 m that provide a good fit to the observed, data. The distance to the fault obtained from the model matched exactly the distance to the main Apiay fault determined from :independent seismic data. Data is also presented in the form of the response surface on which the objective function minimization takes place.

Introduction

In most instances, drillstem testing (DST) of a well to determine productivity and reservoir properties in the vicinity of the well is completed before a thorough analysis can be made of the results. Where there are reservoir heterogeneities in the area, such as a sealing fault this often leads to a change in the slope of the usual Homer-type plot near the end of the test and it is not clear whether this increase in slope is due to the effect of the fault or is an artifact of the measurement.

As several instances of this late-time increase in slope had been found in analysing drillstem test data from the Kl and K2 formations of the Apiay field in Colombia, the theoretical behaviour of a well near a fault has been analysed in order to compare this with the observed pressure behaviour in the final buildup period of a multi-rate DST The Apiay reservoir is particularly suitable for testing this type of theoretical response as it is a very clean and uniform sand of fairly high permeability with some well-defined faults and possible minor faults in the area.

Theoretical Pressure Response

We consider initially a DST carried out in an infinite-acting reservoir for times where wellbore storage effects have become negligible.

The usual methods for treating the pressure buildup in a DST with multiple rates before shut-in are described in Earlougher(1), Matthews and Russell(2) and Lee(3). The first method, used for rates that do not vary substantially, is to calculate a production time defined by(1): Equation. (Available In Full Paper) where Vp is the total volume produced since the last pressure equalization and q is the constant flowrate just before shut-in. This is used in a Homer-type plot of PW5 as a function of Equation. (Available In Full Paper) where δt is the time since the shut-in of the well. When the flowrates before shut-in vary considerably, it is necessary to use a more elaborate multiple-rate analysis.
Countdown To 97
Authors: Kerr A.
Published: March 2010

As I stood there that cold winter afternoon 49 years ago, little did I realize, let alone understand, the significance of those hundreds of barrels of crude (light gravity 38 degrees, lube stock, I'll have you know) going up in smoke. This was to herald the new knowledge of millions of barrels which we would soon start finding in astonishing amounts.

As a junior geologist, to paraphrase Gibby Gibson, "we did not speak unless we were spoken to." I was totally ignorant of the machinations of Imperial Oil's Geophysical Department and had to wait until 1977 when I saw the October 1946 super secret plat. Ray Walters, the Wizard, had selected the well site from this plat (though even he did not know what the anomaly meant).

Hundreds of farmers showed up with horse blankets spread over their 1929 Essexs, possibly with the idea that they were going to share in the mineral wealth. But this privilege had been granted to relatively few homesteaders, none of whom realized their good fortune prior to September 1946 (when Imperial started trying to sign them up).

Now, with nearly 50 years behind us, several major disturbing conclusions must be drawn:The main Devonian Reefs were found within 7 years of Leduc and within a 50 mile radius of Edmonton. They comprise 20% of the known crude reserves of the Province. These giant accumulations are all but depleted.Alberta, the home of the Devonian Reef, has been unable, over the past 30 years, to discover any accumulations on the scale of Leduc or Redwater.So-called ‘statistical experts’ may be allowing Rome to bum as the crude pipeline capacity to the east is increased. These additions are no longer required because of conventional reserve additions, but rather from such arcane items as horizontal drilling and sliptivity chemicals to counteract the viscosities of the heavier crudes which are replacing conventional.

In broad historical perspective, the 50th anniversary of the discovery of Leduc should be observed next February (1997), as less of an achievement than a "blip" on the reserve curve, the direction of which will continue to climb due only to tar sands and heavy oil.

And what of 2047, the 100th anniversary of Leduc? All the conventional crude will have long since been exhausted, and the Leduc "blip" on the reserve curve will have lost its significance.

Instead of airy promises of undiscovered conventional crude, all eyes should be focussed on the growing importance of the tar sands. They were there 250 years ago when the first explorers tramped through northeast Alberta. They are now required to assure Canada's future liquid hydrocarbon self-sufficiency.
Decentralized Continuous-flow Gas Anchor
Authors: Podio A.L. , Mccoy J.N. , Drake B. , Woods M.D.
Published: March 2010

A new gas separator has been developed and successfully field-tested in more than 40 beam pumped wells which were subject to severe gas interference.

The new design is based on several innovations:Decentralization of the gas separator in the casing ensures that a maximum amount of liquid enters the separator.The presence of two or more ports on the gas separator near where it touches the casing wall.Construction of the gas separator so that the outer tube of the gas separator is pressed against the casing wall to prevent cross-flow of liquid and gas.The addition of a diverter at the bottom of the separator to direct most of the gas flow, towards the wide side of the annulus.

These innovations have resulted in a gas separator efficiency much greater than that of conventional designs.

Introduction

Numerous studies have been performed in recent years in an attempt to improve the performance and efficiency of a beam pumped system [see References (1) through (8)]. The studies include the motor or power unit, the surface pumping system, the rod string and the downhole pump. In wells which produce gas, the inefficient separation of gas from liquid at the pump inlet often results in very poor pump performance and low overall efficiency of the entire pumping system. This can be verified by obtaining a dynamometer pump card which indicates considerable free gas in the pump even though liquid is present in the casing annulus in the form of a high gaseous liquid column.

Terminology

When discussing downhole gas separators in pumped wells, there appear to be various terms which are used indiscriminately: gas anchor, mud anchor, dip tube, perforated sub, etc. In order to avoid confusion, the terminology adopted in this paper is as follows:Gas Separator: The complete assembly of elements installed below the seating nipple and the pump intake with the purpose of maximizing the amount of liquid entering the pump.Outer Barrel: The outermost element of the gas separator which is connected to the tubing (often called mud anchor).Dip Tube: The innermost element of the gas separator which is attached to the pump intake (often called gas anchor).

Natural Gas Separator

The preferred technique for separating gas from the pump is to place the tubing fluid entrance ports (or gas separator ports) below the bottom of the formation's perforated interval as shown in Figure 1. The natural separation of gas and liquid by gravity will result in relatively gas-free liquid entering the pump intake if the downward liquid velocity in the casing/tubing annulus is less than approximately 6 in./sec. The gas separator inlet should be placed at least l0ft. below the formation gas entry zone to allow free gas separation from liquid between the tubing outer diameter and the casing inner diameter See Table 1 for natural gas separator capacities.

For greater capacity, it is necessary to use a modified gas separator with an outer diameter smaller than the tubing (see Figure 2).
Effect of Gravity On Movement of Water-oil Interface For Bottom Water Driving Upwards to a Horizontal Well
Authors: Butler R.M. , Jiang Q.
Published: March 2010

In a previous paper from our laboratory, an equation was developed to predict the movement of the water-oil interface produced by bottom water driving upwards to a horizontal well; the oil and water were assumed to have the same viscosity and density. If the oil has a lower density than the water, as is usually the case, the interface will be flatter due to the effect of gravity. This will improve the performance. In the present study, the effect of gravity on the movement of the interface and on the oil recovery has been studied physically and theoretically. The new theory allows the effect of gravity to be included.

Two sets of experiments were carried out in a Hele-Shaw cell to investigate the effect of gravity on the movement of the water-oil interface. The first set involved upward displacement of oil by bottom water to a horizontal well. It was found that the higher the flow rate, the lower the oil recovery at breakthrough even when the two fluids have the same viscosity. This effect is caused by gravity. In the other experiments, a water crest established previously in the Hele-Shaw cell was allowed to fall driven by gravity alone, with both the injection and production wells shut in. The interface fell at the centre and rose at the two ends and thus became progressively flatter. The interface was photographed periodically.

Analytical and numerical studies were carried out to predict the movement of the fluids. The predictions from both techniques are in agreement with the experimental results. These equations can be used to predict the relaxation of water crests in the field and a numerical example is given.

Introduction

Gravitational segregation due to the density difference between displacing and displaced fluids is one of the important factors affecting oil drainage from the reservoir. The overriding of the injected gas or steam and the down-flow of injected water, for example, usually reduce the vertical sweep efficiency. In some cases, the effect of the net gravitational force to assist the oil drainage has been utilized commercially for both conventional and heavy oil reservoirs. The process of steam-assisted gravity drainage (SAGD)(1,2,3,4) by using a horizontal production well at the bottom of the reservoir, with either a parallel horizontal injection well or several vertical injection wells located above in the reservoir, has been applied successfully to the tar sands in AOSTRA's UTF project in Fort McMurry, Alberta, and to the Tangleflags North heavy oil reservoir in Saskatchewan. The Vapex process(5), which uses a vapourized hydrocarbon to extract the bitumen, is an analogue to SAGD but a non-thermal process. Downward displacement of oil from the depleted reservoirs by gas cap or injected gas(6) is another example to take the advantages of the density difference between gas and oil phases.

Gravitational forces can act as either a de-stabilizing force or a stabilizing force for the interface(7), depending on the sequences of two fluid layers.
Gas Production Modelling-A Case Study
Authors: Smith Steven
Published: March 2010

Computer models are increasingly used in production optimization of gas fields because they offer a practical way to detect all potential bottlenecks. A single model takes into account reservoir performance, sandface inflow performance, well bore pressure losses, gathering system pressure losses, and field facility performance. Furthermore, many scenarios can be quickly evaluated without incurring significant expense.

This article presents a case study of an actual Alberta gas-condensate field evaluated with computer models three times over the course of more than a year.

February 1996–0riginal Model

A study was commissioned by the minor partner in an Alberta gas-condensate field when the major partner wanted to install additional compression in hopes of accelerating drainage in a competitive situation. The minor partner, whose share of the cost was expected to be approximately $250,000, doubted the value of installing the compressor.

Field A included a plant with compression, three wells, and the associated gathering lines (see Figure 1). Each well is completed in a tight Glauconite formation and all wells were thought to be in competitive drainage with Field B to the south and west.

Reservoir Characterization

A review of the static bottomhole pressures (BHP) for the wells in Field A suggested that the three wells did not share a common pool. On May 29, 1995, the static BHPs of Wells A, B, and C respectively, were 11.79 MPa, 11.59 MPa, and 8.27 MPa. On September 12, 1995, the static BHPs of the three wells were 11.73 MPa, 11.56 MPa, and 8.03 MPa respectively.

Static BHPs for Wells A and B were both below the expected initial reservoir pressure for the Glauconite formation. While the pool may have experienced some drainage, the pressure decline over 106 days, as noted above was very small and close to recorder accuracy. It seemed unlikely that there was any significant drainage during this period. Wells A and B were modelled as sharing a common pool (Glauc AB) with no competitive drainage.

Reserves for the Glauc AB pool were calculated by both material balance and the volumetric method. The original gas in place (OGIP) calculated by material balance was 160 E6m3. The OGIP calculated by the volumetric method, based on an assumed areal extent of two sections, was 500 E6m3. As a conservative estimate an OGIP of 160 E6m3 was initially assumed for this pool.

Well C static BHPs were also below the expected initial reservoir pressure of the Glauconite formation. Unlike the Glauc AB pool, this pool continued to exhibit some drainage, with a modest pressure decline of 242 kPa over 106 days during which Well C was not producing.

As an example of the observed pressure variations across Field B, a well in the extreme south of Field B had a measured static BHP of 11.80 MPa in July 1971, while a well adjacent to Well C had a measured static BHP of 11.84 MPa in October 1981. Although Well C may be in communication with wells in Field B, pressure data like those noted above suggested that the communication was not strong.
Prediction of Gas Phase Volumetric Variations In Diphasic Reservoir Oils
Authors: Varotsis N.
Published: March 2010

The gas and liquid phases present in diphasic mixtures often have distinctly different physical properties. Hence, the ability to predict the changes in their relative saturation as the conditionsvary during their flow in a conduit or in the porous media is highly desirable.

This work presents analytical expressions relating the gas phase volume variations with physical properties of the reservoiroils. It was established that the gas phase volume variations, as pressure changes, can be correlated with the saturation pressure of the fluid and the dimensionless pressure regardless of thetemperature and the kind of fluid at conditions far from the critical state. These equations proved to provide the volume variations with remarkable accuracy and can be applied to surface separation processes, surface multiphasic pumping and flowmetering and e prediction of variations in the phase saturation in the reservoir.

Introduction

In several petroleum engineering applications gas and oil coexist, having established equilibrium either in the pores of the reservoir or as they flow in the production tubing or t1rrough the pipes and the surface separation unit. As a result of the reservoir depletion or of the fluid flow, the pressure of the system varies with time and distance. Hence, it is considered useful to be able to estimate the influence that the pressure change bears on the gas phase volume, acting both with the compressibility of the gas and with the incremental volume of the condensed liberated gas. This piece of information helps to evaluate variations of the fluid saturationsn the reservoir and the possible displacement of fluid interfaces, under certain conditions, during depletion or prolonged testing. For the applications concerning the flow at the surface, it can be used to determine the variations of the flowrates of each phase and consequently, the phase cuts as the stream passes through valves and restrictions and is subjected to subsequent pressure drops. The prediction of the gas void fraction (GVF) at operating pressure is reported as a key parameter in the design of the recently developed subsea multiphase pumping systems (1).

The change of the gas phase volume can be quantified in two ways:as the fractional change that the fraction Vfg of the total volume of a mixture occupied by the gas phase undergoes as the pressure drops:Equation (1) Available In Full Paper.as the fractional change of the gas volume Vg of a mixture as the pressure changes:

Equation (2) Available In Full Paper.

The first expression relates the change of the gas volume to the total volume of the mixture and is used to express the change in the gas phase cut. The second expression, however, deals exclusively with the changes in the volume of the gas phase and is used to express the incremental volume of gas available in the system. Obviously the fractional changes of Vfgand Vg obtain the same values when a given mass of a mixture continues to occupy practically the same volume (Vt1, Vt2 even after it was subjected to a pressure change Δp.
Atlantic No. 3 1948
Authors: Kerr A.
Published: March 2010

Atlantic 3 was to be the signal for the world to really understand the fury of the new hitherto unknown Devonian reef which catapulted Alberta into the oil age. The above date marked the "point of no return" for what should have been the completion of this otherwise ordinary development well. That was the day Atlantic No. 3, just one mile east of Imperial's 1947 discovery well, blew out of control. It would continue its wild caper until Labour Day 1948 when the well caught fire sending media shock waves literally around the world.

The drama of Atlantic No. 3 - 1948 began shortly after Imperial's Devonian discovery in the spring of 1947 when Frank McMahon, a down and out promoter, somehow or other detected a flaw in a quarter section freehold title leased to Imperial Oil. Imperial's drilling of their step-outs No. 3 and No. 4 virtually proved up this parcel (NW 23-50-26-W4M). Frank with his optimistic stance paid the Rebus family over #x0024;200,000 bonus (where he obtained the funds is a mystery). His company, Atlantic Oils, then hired a contractor (Cody Spencer, also on the edge of bankruptcy) to drill up the lease with an old steam rig.

Atlantic No. 1 and No. 2 were completed as D-3 oil wells without incident, providing Frank with much needed revenue. The rig then moved over to No. 3 wellsite, spudding in, January 21, 1948. Only 300 feet of surface casing were set. When the hole reached the D-3, severe loss of circulation prevented the deepening to the production casing point. Many cement plugs later (none of them successful), the decision (not unanimous) was to "drill dry" (using water) hoping to make a run for the casing point. The bottom dropped out of the water column and No. 3 blew out March 8, 1948, spewing 15,000 bbls/day over the frozen ground.

The next two months were spent trying to kill the well. Finally with pressure from Imperial Oil (they owned 80% of the reservoir) the Conservation Board bit the bullet, seized the well on May 12 and retained V.J. "Tip" Moroney to take complete charge over the project. Tip was a veteran of hole problems in South America. In January 1948, he had just been transferred (providently!) to Imperial's Calgary office. Quoting Tip: "I said I would take the job if I was to be absolutely in charge." He immediately contracted two more steam rigs with a remote boiler location and drilled two directional holes to intersect Atlantic No. 3 pay zone.

After many trials and tribulations (much of it self-inflicted) the two relief wells whipstocked their way to near their D-3 targets. West Relief ran casing and started pumping 36,000 b/d of water from the North Saskatchewan. This watered out the formation. The wild well caught fire Labour Day, September 6, and only burnt three days-but it was a spectacular fire, the word travelling around the world.
Effect of Nitrogen On the Solubility And Diffusivity of Carbon Dioxide Into Oil And Oil Recovery By the Immiscible WAG Process
Authors: Nguyen T.A. , Ali S.M. Farouq
Published: March 2010

In the immiscible displacement of oil by carbon dioxide gas, the solubility and diffusivity of carbon dioxide are important factors that determine the efficiency of the process, because an increase in the carbon dioxide solubility and diffusivity into oil leads to an increase in oil recovery. It is shown by experimental studies that the solubility and diffusivity of carbon dioxide into oil are governed by the saturation pressure, reservoir temperature, composition of the oil and purity of the gas. The solubility and diffusivity of carbon dioxide into Aberfeldy heavy oil were measured, using impure carbon dioxide gas containing nitrogen as the main contaminant gas. It was noted that increasing the concentration of nitrogen in the carbon dioxide stream decreased the solubility and diffusivity of carbon dioxide in oil, consequently leading to a reduction in the swelling of the oil by carbon dioxide.

Displacement experiments were also conducted to observe the effect of using impure carbon dioxide in place of pure carbon dioxide in the immiscible displacement WAG process. It was noted that the presence of nitrogen in carbon dioxide adversely affected oil recovery by the process and that increasing the nitrogen concentration up to 30 mole% could result in 10% loss in oil recovery.

Introduction

The solubility of carbon dioxide is the most important effect in the immiscible displacement of oil by carbon dioxide gas since it was found by Rojas(1) that among other mechanisms, an increase in the carbon dioxide solubility in oil leads to an increase in oil recovery. This is true because the solubility of carbon dioxide greatly reduces the viscosity of the oil and promotes the swelling of the oil. Viscosity reduction and swelling of the oil lower the water-oil mobility ratio, consequently leading to an increased oil recovery.

Early work in 1926 by Beecher and Parkhurst(2) showed that carbon dioxide was more soluble on a molar basis in a 30.2 °API oil than air and natural gas. Svreck and Mehrota's data(3) for carbon dioxide, methane and nitrogen showed that and Mehrotra's data(3), carbon dioxide is the most soluble and nitrogen the least soluble in bitumen.

The solubility of carbon dioxide in oil is governed by the saturation pressure, reservoir temperature, composition of the oil and purity of the gas. Miller and Jones(4) and Chung, Jones, and Nguyen(5) measured the solubility of carbon dioxide in Canyon and Wilmington heavy oils and found that the solubility of carbon dioxide in heavy crude oils increased with pressure but decreased with temperature and reduced API gravity. Briggs and Puttagunta(6) reported sets of data for carbon dioxide solubility in Aberfeldy oil and swelling of oil at 20.6 °C. Their data showed that both carbon dioxide solubility and oil swelling increased when pressure increased. Later, Sayegh and Sarbar(7) established that carbon dioxide is more soluble in oil at lower temperatures than at higher ones.
Oil Recovery From Tarmat Reservoirs Using Hot Water And Solvent Flooding
Authors: Okasha T.M. , Menouar H.K. , Abu-Khamsin S.A.
Published: March 2010

The existence of tar accumulations (tarmat) beneath the oil zone in some reservoirs creates productivity problems through restricted aquifer support during the primary recovery stage. It also affects the performance of peripheral water injection when the tar/oil boundary is irregular.

The objective of this study was to investigate and evaluate combined solvent and hot water injection beneath the tarmat to improve aquifer support by displacing and dispersing the tar. Displacement runs were conducted in one-foot long Berea sandstone composite cores, simulating a tar zone and an oil zone in series, at injection rates of 1 ml/min. and higher.

The results show that although the oil recovery from hot water displacement is lower than cold water displacement in the absence of tar, the gain in recovery for hot water over cold water is substantial in the presence of tarmat. Driving a slug of solvent with hot water to displace tar increases the hydrocarbon recovery even further. However, for each of the two solvents studied, there is an optimum slug size with which the hydrocarbon recovery is maximum. Moreover, the recovery was found to increase further when the optimal slug is divided into portions separated by small slugs of hot water.

The injection rate had a profound effect on the recovery for all hot-water flooding schemes. The results showed consistently that the recovery increased at lower injection rates.

Introduction

Many oil reservoirs are characterized by the presence of a highly viscous hydrocarbon layer (tarmat) at the oil/water contact. Such tarmats are found in many major oil reservoirs in the world and, particularly, in the Middle East. They are reported in the literature to vary widely, ranging from highly viscous hydrocarbon fluids to near solid materials(1). The thickness of the tarmat varies from place to place in the same reservoir and sometimes reaches few hundred feet; while their extent can reach several kilometres. In Ghawar field, for example, the tar zone extends more than 25 km and reaches up to 150 m in thickness(2).

Several geochemical studies presented by various authors attribute tarmat formation to gravity segregation which leads to a compositional grading with depth(3–5). Depending on reservoir conditions and tar viscosity, field experience shows that some of these tarmats can become mobile under conditions of moderate differential pressure(2).

The presence of tar deposits at the oil/water contact in a tarmat reservoir can have serious adverse effects on the effectiveness of natural water drive as well as secondary recovery projects. When the tarmat completely surrounds the oil zone, the oil reservoir behaves like a finite lens where the pressure decreases rapidly as soon as the first well starts producing. This leads to an alarming increase in gas/oil ratio during the primary stage of depletion which has been the case with Minagish reservoir in Kuwait(2). Another such example is El Bundug reservoir in Qatar(6).
Shrinkage of Oil Well Cement Slurries
Authors: Backe K.R. , Skalle P. , Lile O.B. , Lyomov S.K. , Justnes H. , Sveen J.
Published: March 2010

Gas leakage into and through the cemented annulus in oil and gas wells is a safety problem. The conditions for gas migration develop when the hydrostatic pressure of the hydrating cement slurry column slowly declines and finally falls below the pore pressure of a gas bearing formation. This pressure decline is mainly caused by chemical shrinkage of the cement. A low shrinkage will reduce the pressure decline and hence the risk of gas migration.

A new and simple method for measurement of total chemical shrinkage at high temperatures has been developed. It has proved to be reliable and sensitive for monitoring the cement hydration process. The equipment was used to show that there is a marked difference in shrinkage behaviour for the tested slurries up to 180 ° C, probably due to a temperature effect on the cement hydration chemistry. The results confirmed the correlation between total shrinkage and cement content, and thus it follows that using more extender will reduce the likelihood of gas migration.

Introduction

Cement slurries are used in oil and gas wells for cementing the steel casing to the wellbore and thus sealing the rock formations from the well. Gas leakage into and through the cemented annulus is still a problem, in particular where shallow gas sands are penetrated and in deep gas wells, i.e., under high temperature and high pressure (HTHP) conditions. The leakage may manifest itself either as vertical communication between permeable gas reservoirs or migration all the way to the surface. Gas pressure in excess of the cement hydrostatic slurry pressure is the driving force behind gas migration.

Reasons and mechanisms of gas migration are discussed by Levine et al.,(1) Sabins et al.(2), and Cheung and Beirute(3). Annular gas flow may be initiated when the hydrostatic pressure of the cement slurry declines and falls below the pore pressure of a gas bearing formation due to the combined effect of shrinkage, fluid loss to the porous well bore and gel strength build up. Normally a slurry volume reduction would be compensated for by contraction and downward movement of fluids from above, thus maintaining its hydrostatic head. However, during the setting process the cement slurry develops a gel structure causing it to stick to the wall thus hindering compensation of the shrinkage. The second requirement for gas migration is that the cement must enable gas flow into the cement either by permeability, channels, microannuli or microfractures before the slurry has reached a sufficient strength. Thus, the gas migration phenomenon is thought to be initiated during the transition state, from being fluid to becoming hard, i.e., between initial and final set of the cement.

A low shrinkage is preferable because the resulting hydrostatic pressure decline will be lower than for a slurry with high shrinkage, i.e., pressure equilibrium between gas and slurry column is reached at a later point of time.

The chemical shrinkage may be divided into two parts: external shrinkage and total shrinkage.
Rock/Bit Imbalance Force Prediction
Authors: Ziaja M.B.
Published: March 2010

It is important to be able to predict the instantaneous forces and moments at the bit during drilling, but the rock/bit interaction process is not thoroughly understood. It is commonly accepted that the forces acting on a drag bit should be balanced to avoid excessive bit vibrations called whirling and uncontrolled well deviation resulting from non-symmetric side cutting. However, the relationships between drilling forces and bit design features are uncertain because of the difficulty in obtaining reliable, quantitative measurements of cutting forces at the bit.

A series of single cutter PDC (Polycrystalline Diamond Compact) experiments were conducted in the laboratory; in which three components of drilling force were measured. A rock was cut at the speed and load corresponding to the same parameters while PDC bit drilling. The variations in the value and direction of the resultant force were compared with the variations of the depth of cut and the simulated wellbore pressure. The relationship between the cross-section of cut rock and the measured forces at a PDC cutter were analysed and used in the rock/bit modelling. A model for the resultant force at the bit was developed by integrating the effects of individual PDC cutters into geometry of a given PDC bit design. The model describing kinematics of the PDC bit, as well as the imbalance force resulting from the non-symmetric distribution of drilling forces was developed. Then, simulations of the rocklbit interaction forces were run for the different depth of cut and a given rock described by the index of rock strength and coefficient of friction between the rock and PDC cutter. The predictions obtained of imbalance force and moments at the bit are presented for the conventional and bi-centre PDC bit designs. The results clearly indicate the differences between these two designs, as well as the ability to predict the magnitude and orientation of the imbalance force generated while drilling with different PDC bit designs in different rock lithologies.

Introduction

The unexpected and excessive PDC cutter wear, as well as the problems related to uncontrolled and/or unintended well deviations were recognized in the late 1980s. In 1989, a new theory of PDC bit failure was presented and called "bit whirl." It has been recognized that the bit stability is influenced mainly by lateral force causing a bit to walk around the wellbore. Since that time, research has focussed almost entirely on modelling the whirling motion of the centre of the bit and modelling the low static imbalance force at the bit. Some improvements have been obtained by developing techniques that stabilize the bit and generate the restoring force necessary to prevent the start of whirl. However, the mechanism of rock cutting is still not well enough understood to accurately predict the distribution of forces and moments at the bi-centre PDC bit and the resulting bit behaviour on instantaneous time scale while drilling. The main reasons are the following: 1) the directional tendencies of PDC bits have not been clearly defined to this point.
Solubility of CO, NO, CH, And CH In Polar Solvents
Authors: Henni A. , Mather A.E.
Published: March 2010

The solubility of carbon dioxide, nitrous oxide, methane and ethane in a physical solvent, triethylene glycol monomethyl ether (TEGMME) was recently measured by Henni and Mather(1–4) at 40, 70, and 100 ° C at pressures up to 10.9 MPa. TEGMME was found to be the best solvent for CO2 removal among the physical solvents used in the gas processing industry. In order to compare these solubility data with those of other polar solvents, a literature search was done to gather solubility data in solvents with a wide range of dielectric constants. The solubility data compiled were for pressures higher than atmospheric pressure and the Peng-Robinson(5) equation of state was used to correlate the data for the solubility of CO2 in these polar solvents. The Henry's Law constants are then derived using the Kritchevsky-Kasarnovsk(6) or the Kritchevsky-Iliinskaya(7) equation. The results show that ethyl acetate and propyl acetate are the two solvents that have the highest capacity for CO2 absorption. Among the solvents that absorb CO2 the most, TEGMME has the highest boiling point; this translates into lower solvent losses in the regeneration section. Dimethyl ether is among the best solvents for CO2 absorption but it is also among solvents that absorbs methane the most. Diethyl ether comes at the top of the list in its ability to absorb.

The study confirms the fact that the best physical solvents for absorbing acid gases have the disadvantage of absorbing the largest amounts of ethane. It also recommends the use of this new solvent TEGMME as a new solvent for acid gas removal.

The solubility data in the CO2, N2O, CH4 and C2H6 systems were generally well-correlated by the Peng-Robinson equation of state even for those systems that are highly non-ideal.

Introduction

The Government of Canada has been an active participant in the development of international agreements and protocols for emissions reduction. It has committed the country to meeting national emission caps for anthropogenic air emissions. Just how these national targets will be met is a critical question to provincial governments but also to oil, coal and utility companies in Canada. Since carbon dioxide is a major contributor to the global warming phenomenon, the process of carbon dioxide removal from coal-fired power plants and its utilisation as a flooding agent for enhanced oil recovery (EOR) is the focus of considerable of attention. The CO2 captured will generate revenues and will help reduce emissions that contribute to the greenhouse effect.

Zawacki et al.(8) have screened more than 100 solvents for their potential of removing acidic gases (CO2, H2S). The dimethyl ether of tetraethylene glycol (DMETEG) was chosen as one of two most promising solvents. In an attempt to provide the industry with better physical solvents, a study was initiated to test new physical solvents.

Triethylene glycol monomethyl ether [TEGMME, C.A. Registry No. 112-35-6] was chosen in the initial study as it belongs to the same chemical family as DMETEG but it costs four times less.