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Evaluation and appraisal Introduction At this point in the quest for petroleum, the exploration well would have been drilled to total depth (TD) and probably the primary, secondary and ancillary targets reached and evaluated by geologic and petrophysical means. If an oil show was encountered, the core analysis results were good and the petrophysical log analysis encouraging, the decision to proceed with a test (e.g., DST) would seem to be the next logical step towards evaluating reservoir potential (Figure 161). However, it is worth while reviewing some of the factors that should be considered at this time. Perhaps the most fundamental objective of any appraisal activity is the reduction in uncertainty concerning the description of the hydrocarbon reservoir and the provision of sufficient information with which to make subsequent decisions. Such decisions may be to conduct further data gathering and extend the appraisal, to cease activities altogether and abandon, or farm-in, farm-out, or hasten 'first oil'. However, it is reasonable to state that not every well drilled is tested. Why? Some reasons are obvious! The absence of an oil or gas 'show', the absence of detectable hydrocarbons through log analysis and or due to discouraging geological analysis of primary and ancillary targets. Other factors include cost and safety. To run a drill stem test or production test has a cost factor, which may be 10% of the total exploration budget. For a deep well and/or an offshore well those costs will be greater. In general, exploration activity costs increase with increasing depth by a factor of two for on-shore exploration activities. Some of the deepest on-shore wells drilled in N. America (e.g., Anadarko Basin) cost approximately $5,000,000 to $6,000,000 each to complete, in contrast to the shallower wells in the Williston Basin (approx. $1,500,000). Testing wells is potentially dangerous, since the formation to be tested is encouraged to flow, consequently the potential for a blow-out exists and preventative precautions must be taken in advance.

Drill Stem Testing

Introduction A drill stem test (DST) is a method of determining the potential of a well to produce oil and or gas (Borah, 1992; Lancaster, 1992). The formation to be tested is sealed from the rest of bore hole by inflatable packers (Figure 162) and indigenous formation fluids are encouraged to flow by exposing the formation to reduced pressure or atmospheric pressure. There are two general types of DST; non-flowing and flowing DST's. Flowing DST's permit the flow of fluids to the surface and are analogous to production tests. The data from a DST can include samples of fluid, reservoir pressures (P*), formation properties such as permeability (k), skin (S), and radius of investigation (radius of depletion) and estimations of flow rate. DST's can be run in either open hole or in perforated cased hole, although the optimal time to run a DST is just after drilling into a potential reservoir when the formation is relatively undamaged. An important consideration in planning a DST is the location of the 'packer seats', which should be a competent formation with low porosity, low permeability and adjacent to the test zone.

Figure 161. A 24hr production test on the NW Dome, Qatar.

Figure 162. (a and b) Bottom Hole Tool: (a) packers uninflated; (b) packers inflated and tool open. (c) Straddle Test Tool: packer inflated and tool open.

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Test tools The test tool consists of packers, a downhole shut-in valve, a safety joint, pressure recorder and gauges (Borah, 1992). The testing tool is lowered into the bore hole, on the end of the drill string. Once at the desired depth, the hydraulic check valve is closed to prevent fluids from working up the drill pipe; the opening/closing of various check valves is achieved by a set number of drill string rotations. The packer is inflated against the walls of the bore hole (Figure 162). Once expanded, the packers support the hydrostatic pressure of the drilling fluid within the annulus. Formation fluids, either below the packer (Bottom Hole Tool) or between the packers (Straddle Test Tool), are allowed to produce when the hydraulic check valve is opened. The amount of fluid that flows into the drill pipe is a measure of the reservoir's potential to produce fluids. After a short period of time, the tool is shut-in and the formation pressure recorded. The shut-in valve can be opened and closed 3 times, if required. Once complete, the hydraulic valve is closed and the pressure equalized for packer unseating. Formation fluids are then reverse circulated out of the hole and fluids recovered. The recorded pressure provides information regarding formation pressures, and the permeability and recharge capacity of the reservoir. In general terms, the permeability can be 'eyeballed' by looking at the radius of curvature of the shut-in pressure curve; however, the viscosity of the fluids also influences the curve (Borah, 1992).

DST Charts Please refer to Figure 163. The DST tool is run into the borehole (RIH), during which the steady increase in hydrostatic pressure is recorded by the tool. (1 to 2) The packers are set and the formation is allowed to 'pre-flow', clearing the pores of mud cake and filtrate. (2 to 3) The tool is then shut-in and the formation pressure recorded, the height of the curve reflects pressure while the slope reflects rock permeability. (3 to 4) The shut-in valve is opened, the pressure drops and (4 to 5) the formation allowed to flow for a period of time. (5 to 6) The shut-in valve is closed again and the formation pressure recorded, any change in height or slope compared to the slope for the initial shut-in period (2 to 3) may signify low formation transmissibility. At the end of the test, the tool is opened (6 to 7), the packers released and the tool pulled out of the hole (POOH). The analysis of data is conducted using algorithms and a Horner type plot to determine static reservoir pressure (Borah, 1992). Some example DSTs and relevant data are given below and in Figure 164.

Figure 163. Example DST chart. The numbering is also used on subsequent charts (1) Initial hydrostatic, (2) Preflow, (3) Initial shut-in pressure, (4) Initial flow pressure, (5) Final flow pressure (6) Final shut-in pressure, (7) Final hydrostatic (after Lynes, 1981; Borah, 1992; Baker Hughes, 2005 and others) .

Figure 164. Two example DST charts and data for the Sparky B, Manville Fm, Saskatchewan.

DST Number 1 High permeability

Formation Sparky B

Depth (m) 677 Pressures (Mpa) PF = 0.903 1, ISI = 3.350 5, IF = 1.041 0, FF = 2.137 1, FSI 3.000 7 Times (min) PF = 5, ISI = 60, FF = 60, FSI = 90, PF = fair IP V good air blow decreasing to fair steady throughout Recovery 207 m heavy gassy oil Remarks Heavy crude oil

DST Number 2 High permeability formation

Formation Sparky

Depth (m) 623 to 627 Pressures (Mpa) PF = 0.648 0, ISI = 5.377 3, IF = 0.978 9, FF = 1.323 6, FSI 5.156 7 Times (min) PF = 5, ISI = 60, FF = 60, FSI = 90, PF = fair to strong Strong decreasing to dead in 45 min Recovery 112 m heavy crude oil, 4.6 m mud cut oil Remarks Heavy viscous oil

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Completion and production Open hole completion If the decision is go ahead, complete the well and produce, there are a variety of options that can be pursued, depending upon cost, reservoir characteristics, local regulations, nature of the producing fluids, potential hazards and environmental concerns (Holditch, 1992). Several decades ago, typical completions were of the so-called open hole type (Figure 165a). That is production was from the open, unprotected hole without packers isolating the zone of interest. When the producing formation was penetrated and petroleum began to flow, drilling was stopped and the well was produced from the open (i.e., bottom) hole. Well stimulation was even sometimes achieved using nitroglycerin!

Liner completion This is a variation of the open hole completion technique, except that steel tubing, known as a liner, is hung from inside the casing. That is if the 339 mm (133/8 inch) casing shoe was set at 3,000 meters and TD was 3,200 meters, then a liner would be hung from 339 mm (133/8 inch) casing to TD. Therefore, the casing must in place before the liner can be set and prior to production. The liner has numerous holes through which fluids can enter the well bore; which includes the slotted liner, screen and liner, or a cemented liner. Slotted liners (Figure 165), although cheap this type gives very little protection. Screen and liner types are sometimes used when producing from an unconsolidated formation, the difference being the addition of aggregate (e.g., gravel) behind the screen (Holditch, 1992). They are also inexpensive and provide limited protection. Cemented liner. This type is used when there is a need to isolate and or protect zones of interest. Advantages of the Cemented liner: include (1) cost effectiveness, (2) can selectively perforate and produce from a portion of the reservoir and (3) a higher degree of formation integrity is maintained. Unfortunately this type of completion is dependent upon the integrity of the cement job (Holditch, 1992).

Perforated casing completion A perforated casing completion is commonly used in vertical wells or where multiple producing zones are encountered (Figures 166 and 167). The casing is cemented back to the shoe (if possible) and the casing subsequently perforated. Casing has a higher bursting pressure than a liner and it is easier to obtain a superior cement job with casing. This approach is also much more straightforward, relatively low cost and typically associated with fewer operational problems (Holditch, 1992). There are a number of completion options, known as single, multiple and alternate completions (Figures 166 and 167).

Single perforated casing completion This is the simplest completion approach, because production involves only one interval; this type of completion is also more common on land-based operations where drilling costs are less. This technique has also been used in some of the deepest wells drilled within the Anadarko Basin, USA (Holditch, 1992).

Figure 165. (a) Slotted Liner and (b) Screen and line completion. Producing zone in black (Holditch, 1992).

Figure 166. Variation of perforated casing completions with tubing; (Holditch, 1992).

Figure 167. Conventional triple tubing, multiple perforation completion (Holditch, 1992).

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Multiple perforated casing completion This type of completion is much more complex and allows for the simultaneous production from two or more zones (Figure 167). Multiple completions are often used offshore, in high cost areas or where the characteristics of the produced fluids are distinct or the formation pressures are markedly different. The differences are the number of isolated zones that are completed simultaneously and the concomitant number of tubing strings (Figure 166 a and b, Figure 167) Each zone of interest must be perforated before the tubing is run and the packer set. This approach allows for the simultaneous production from two or more reservoirs, but because production takes place through casing and through continuous tubing there is a higher degree of protection for producing and non-producing zones alike; individual zones can be isolated, fragile formations are protected and the tubing can be replaced if necessary; although, the more complex the completion, the greater the opportunity for a technical problem to arise (Holditch, 1992).

Perforating The main purpose of perforating is to provide conduits through the wall of the borehole that allow the effective flow of fluids from the reservoir. Holes are shot through the casing and cement into the formation (Figure 168 and 169). The perforating gun is a wireline device comprised of an array of explosive devices, developed from early armor piercing weapons! Upon ignition, a jet of burning charge plus a cone shaped liner generates a velocity of 20,000 ft sec-1 and a pressure of 5 106 psi, capable of punching a small diameter hole through casing, cement and into the formation (Figure 170). The main types of perforating gun include the expendable gun, the semi-expendable gun in which only part of the gun disintegrates and the retrievable hollow carrier gun which is the most widely used gun. It is rugged, strong, and reliable, it leaves no debris, creates little casing damage, has the highest performance and largest charges. All are available as casing guns or tubing guns (Holditch, 1992).

Producing from horizontal and re-entry wells Production from highly deviated wells, was previously touched upon, but deserves special consideration due to the technical nature of such wells. Three completion options are shown in Figure 171, the selection of which is based upon the geological characteristics of the reservoir, the length of producing interval and radius of curvature.

Figure 171. Types of horizontal well completion. (a) bare foot (i.e. no liner); (b) slotted liner and (c) a cemented liner (Jahn et. al., 1998; with permission from Elsevier)).

(a)

(b)

(c)

Figure 168. Perforation patterns (plan view) using: (a) symmetric casing gun and (b) an asymmetrically position tubing gun (Holditch, 1992).

Figure 170. A perforating gun and blast (Holditch, 1992).

Figure 169. (a) Casing perforating gun, (b) tubing perforation gun (Holditch, 1992).

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Bare foot The simplest and cheapest completion is the bare foot (Figure 171a). This is an open hole type completion and is only suitable for consolidated formations with a low collapse potential. Open hole completions are still used, for example in the Austin Chalk (Texas), because it is the easiest solution for short to medium radius horizontal wells. Disadvantages include lack of well control, a reduced ability to control the injection profile and the possible disintegration of the producing formation!

Slotted line The slotted liner (Figure 171b) is a non-cemented section of casing with slots cut into it, as discussed above. This type of liner provides some support, whilst permitting the formation to produce fluids, but because the slotted liner is slotted along its length there is often little control as to which part of the reservoir will or will not produce.

Cemented liner The cemented liner (Figure 171c) involves a cased and cemented bore hole within which the producing intervals are perforated, similar to a conventional well although because of the technical complexity of this type of completion, it is considerably more expensive. However, none of the examples given above are suited for production in unconsolidated- to poorly-consolidated sands. To complete such formations gravel packs or tailor made completions would be required (Jahn et. al., 1998).

Off shore production Producing oil and or gas from an off shore field is typically more complex than on land. Because production must be accomplished by self contained facilities, often out of sight of land, production is typically facilitated via an oil platform, which unlike drilling rigs and drill ships, are traditionally attached or anchored directly onto the ocean floor. Production platforms are generally self-sufficient industrial units that support a deck with space for a derrick (or two). Production platforms (Figure 172) can accommodate the crew, generate their own electrical power, process water, and the have the equipment required to process oil and gas for onshore delivery via pipeline or tanker. Such platforms are, because of their immobility, designed for very long term use. There are numerous challenges that must be met when developing an off shore oil and/or gas field. Environments, such as the North Sea, Canadas East Coast, the Gulf of Mexico and South China Sea for example, are often hostile environments in which severe storms are a regular occurrence. This aside, water depth alone presents a formidable challenge. Modern off shore drilling rigs have enabled exploration in water depths that was unthinkable 40 years ago. In contrast, the water depth capability of the production platform has always lagged behind the exploration rig, as technology catches up (Figure 173). For many years, fixed platforms were the most common type of production facility. Fixed platforms are attached to concrete and/or steel legs that are anchored into the seabed. Fixed platforms are feasible in water depths up to approximately 500 m (1,500 ft). Many of the original production facilities in the North Sea (e.g., Piper Platform, Troll West), Gulf of Mexico (e.g., Baldpate platform), Santa Clara field, USA, (Platform Gail), South China Sea (e.g., Malampaya platform), Bass Strait, Australia (e.g., Barracouta platform) are of this type.

Figure 172. A production platform topsides awaiting deployment in the Gulf of Mexico.

Figure 173. Plots of water depth for off-shore exploration and production facilities showing a technological lag between the two (data from Veldmann and Lagers, 1997; M.M.S., 2004)

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The Troll platform (Norwegian North Sea) operates in 305 m of water, which is generally acknowledged to be the limit for this type of platform because of the stresses placed upon such structures during storm conditions. Therefore, in water depth greater than 300 m different structures are required, the industry has begun to use compliant (i.e., not rigid) structures and subsea production systems (Figure 174). Floating production systems, tension-leg platforms, subsea systems and SPAR platforms are all considered suitable in water depths up to 1650 m (6,000 ft), 1,900 m (7,000 ft), 1,900 m (7,000 ft) and 2,700 m (10,000 ft) respectively (IMMS, 2004).

Floating production systems (Figure 174) can be either semi submersible drilling rigs or ships anchored to a location for a long period of time and equipped with processing facilities. There are three main types of floating production systems, known as: (1) floating production, storage, and offloading system (FPSO), (2) a floating storage and offloading system (FSO), and (3) the floating storage unit (FSU). The Shell and BP Na Kika floating production system, within the Gulf of Mexico, operates in 1,736 m (6,350 ft) of water. Tension-leg platforms (Figure 174) consist of a tightly tethered floating rig system that allows side-to-side movement but effectively eliminates vertical movement. Tension-leg platforms are used in water depths up to about 2,000 m (~7,000 feet). Subsea systems are designed to operate in water depths of 2,000 m (~7,000 feet) or more but do not have the ability to drill, only extract and produce oil and/or gas. Subsea systems are either linked to an existing production platform or a subsea pipeline. The Camden Hills subsea production facility in the Gulf of Mexico, was set in 1,971 m (7,209 ft) in 2002. Similar to the tension-leg platform, spar platforms are tethered using conventional mooring lines. The large hull (Figure 175 a and b), which is typically over 190 m (700 ft) long, supports the production facility (Figure 175c). The hull acts like a counterweight, giving the whole structure a greater degree of stability than the tension-leg platform. Spar platforms currently operate in some of the worlds deepest water. Dominion Oil's Devil's Tower is located in 1,710 m (5,610 feet) of water, in the Gulf of Mexico, and Kerr-McGee's Red Hawk is the first deep-water cell spar.

Figure 174. A comparison of various off-shore production facilities ranging from those suited to in-shore and shallow water (i.e., Mono-pod and Jack-up), through the fixed platform types (includes the concrete gravity-based platform/caisson) that operate in water depths up to approximately 300 m, and more recent deep water facilities (floating platform systems, tension leg platform, sub-sea systems and SPAR platforms). NB: water depth is not to scale.

Figure 175. (a) Lifting the hull of the Red Hawk cell spar, and (b) the Gunnison spar platform in the Gulf of Mexico. Images Anadarko Petroleum Corporation. All rights reserved.

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Reservoir drive mechanisms Natural driving forces

Introduction The Field Appraisal aims at determining the revenue stream that will result from production. Production behavior is largely a function of reservoir characteristics, the type of fluids to be produced and their behavior under the dynamic conditions of production. One key aspect is to determine what type of driving mechanism exists within a given reservoir and the optimal means of enhancing or maintaining production during the anticipated life span of the well or field.

Recovery efficiencies The efficient recovery of oil/gas from a pool or well is not only dependent upon the natural driving mechanism that causes fluids to be produced from the reservoir (i.e., drive mechanism) but upon a number of factors which include:

Reservoir quality (e.g., porosity, permeability) and continuity Duration allowed for production Type of fluid (e.g. methane, condensate, heavy oil) Well spacing The possible need to assist the natural drive mechanism.

The influence of well spacing alone can be determined by a simple examination of development costs versus the net revenue for the well, pool or field. If well spacing is not determined by the local government, the optimization of well spacing will depend upon all of those factors. This is illustrated in Figure 176, in which 'profit' factors in: number of wells, cost of wells, recovery efficiency, porosity, K, Ko or Kg, drive mechanism, time, inflation, flow rate, type and value of the oil or gas.

Primary production Reservoir fluids (gas, oil and water) are under high pressure and elevated temperature; any drop in pressure (such as opening the borehole to near atmospheric pressure) will result in an increase in volume, producing flow. Removing a volume of fluid will also lead to drop in pressure. However, the amount of pressure drop depends upon the type of fluid. Gas is highly compressible, so removing a small volume of gas will not appreciably affect reservoir pressures. In contrast, oil is not very compressible, so removing oil will create a measurable drop in reservoir pressure, unless the volume removed is replenished by another fluid (e.g., water). The natural expansion of reservoir fluid is the primary energy source for initial production (Sills, 1992).

Types of drive mechanisms There are two basic types of primary drive mechanisms; water drive and gas drive. They have very different characteristics. If the reservoir pressure (and production) declines rapidly it is probably gas depletion drive, if the reservoir pressure declines, then levels off (and perhaps recovers), it is a water drive mechanism (Sills, 1992).

Gas drive There are two types of gas drive mechanism: gas-cap and solution-gas (depletion) drive. Both mechanisms function through the expansion of gas and the volumetric displacement of oil, the difference between them is the presence or absence of an initial gas cap. The gas-cap drive is a reservoir containing free-gas in the highest point of the trap, as a gas-cap. Reservoir pressure is maintained by expansion of the gas within the gas-cap. The gas-solution (depletion) mechanism lacks an initial free-gas cap. A pressure drop, due to the initial withdrawal of oil from the reservoir, causes gas to come out of solution. The dissociation and expansion of gas drives the oil. The movement of the gas within the reservoir can be complex, but will generally be upwards towards the crest of the trap to form a gas cap, or towards the producing well (a local low pressure zone) under the influence of hydrodynamic flow. If a gas cap forms, then production switches to the gas-cap drive mechanism. Video 22 shows a simplified gas-solution (depletion) drive mechanism. The placement of production

Figure 176. A representation of net revenue (profit) versus oil well spacing, showing the possible relationship between well spacing and net revenue.

Video 22. Gas-solution ( depletion) drive.

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wells is of great importance. Wells drilled on the crest may remove some of the initial gas prior to the formation of a gas cap. This can be avoided by re-injecting the natural gas into the reservoir. For the gas depletion drive mechanism to work efficiently, as oil is removed the expansion of gas in the gas cap should exert pressure on the oil/gas contact.

Water drive In contrast, the water drive mechanism requires a different well placement strategy. This is because the natural hydrodynamic flow into the structure maintains pressure beneath the pooled oil, driving the oil upwards. A natural water drive mechanism occurs when the underlying aquifer is large and capable of undergoing recharge. A common practice is to initially produce the reservoir using the natural depletion drive, subsequently switching to a water injection mechanism as an enhanced recovery method (discussed below).

Enhanced oil recovery

Introduction Enhanced oil recovery (EOR) techniques such as a water flood and gas injection have traditionally been regarded as secondary recovery techniques and other techniques (i.e., chemical flood, polymer flood, caustic flood, steam flood, steam drive, cyclic injection, in-situ combustion) were regarded as tertiary techniques. The current preferred term enhanced oil recovery encompasses all former (and future) secondary or tertiary recovery techniques. However, because water and gas injection techniques remain the most common techniques they will be discussed first and individually. Other EOR techniques are discussed according to category.

Water flood Water flooding (Figure 177) is used on a fairly regular basis in many pools to supplement the natural hydrodynamic flow of ground water as a means of maintaining reservoir pressure, driving oil to the production wells (Sam Sarem, 1992). The injected water should always be drawn from an aquifer, because of the oxidizing effect of meteoric water. The chemistry of the injected water must approximate the chemistry of the oil-field water within the producing formation to prevent the swelling of clays, prevent the in-situ degradation of oil within the reservoir (see Chapter 3 p32-32; Chapter 5 p72) and maintain similar levels of wetability to prevent channel-breakthrough and improve sweep efficiency (Figure 178).

Figure 177. 'By-passed' oil in a heterogeneous reservoir (Jahn et. al., 1998).

Figure 178. Oil, connate water and flood water (i.e., waterflood) moving through a laboratory scale reservoir. The reservoir is water wet (connate water), Sw >0.60, connate water occupies small and medium sized pores and surrounds the mineral grains. The flood water, flowing left to right, has a different water chemistry and as a consequence a different interfacial tension to the connate water and does not readily mix (i.e., immiscible) with either the connate water or oil, hence the visible interface between the flood water and connate water. Consequently, the waterflood has formed a micro-channel (blue arrow) and has bypassed the oil in the upper and lower pores. The scale bar is approximately 500 m. (after Dong and Liu: with kind permission)

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Water is injected via a separate injector well, or more typically via a number of wells arranged in a set pattern. Injector wells are always down dip from the producing wells. As oil is withdrawn the oil/water contact will rise. As producing wells 'water-out', during production (Video 23), they would most likely be converted to an injector well (Sam Sarem, 1992; Jahn et. al., 1998). Of course in plan view, the pattern of injector wells should reflect the geometry of the trap, the porosity and permeability distribution throughout the reservoir and known changes in facies, although typically producers use set injector patterns (Figure 179). Geologically inhomogeneous reservoirs are the norm, and a poorly designed injector pattern will produce less than ideal recovery, leaving behind by-passed oil (Figure 177), which can be difficult and expensive to recover. In the example given in Figure 177, injected water appears to have effectively swept oil from two high permeability zones and successfully produced oil. However, there are two low permeability zones, associated with a significant amount of oil remaining within those reservoir partitions as by-passed oil (Jahn et. al., 1998). Any attempt to recover the by-passed oil by continued injection of water would be futile, since the injected water would preferentially travel through the more permeable zones (Figure 178). The geologist can contribute significantly in the optimization of production through the application of his/her knowledge and understanding of the reservoir rock, facies variation, type and depositional setting of the reservoir rock, trap geometry, variations in porosity and permeability and water saturation (i.e., Sw, Swirr) etc., all of which have great relevance when determining the optimum injector pattern.

Gas injection Producing oil wells can be assisted by injection of (compressed) solution gas back into the gas cap, in order to maintain pressure. Sometimes producing companies can inject unwanted gas back into the reservoir; this depends upon local regulations. Another option allows for the injection of gas into the annulus, with the aim of lowering the density of the produced oil and aiding production (Jahn et. al., 1998).

Thermal techniques Thermal techniques are used to reduce the viscosity of oil within the reservoir, in an attempt to increase mobility and displacement by reservoir drive mechanisms. Sources of heat include steam flood or hot water flood. The injection of a heat source may require separate injector wells or, the producing well by cycling between production and injection. In-situ combustion is an extreme example of heat injection (Breit, 1992).

Chemical techniques Chemical techniques utilize reagents that change the physical properties of the produced fluid or the displacement fluid. There are two general sub-types, polymer flooding and alkali-surfactant flooding. Polymer flooding aims at increasing the viscosity of the displacing fluid (i.e., connate water) and increasing the sweeping efficiency of that fluid. Alkali-surfactant and surfactant flooding is used to reduce the amount of residual oil left in the pore space of the reservoir by reducing interfacial tension between water and oil. This is achieved by a reduction in oil droplet size, thereby permitting the oil to pass through smaller pore throats (Breit, 1992; Jahn et. al., 1998). Emulsifiers can also be used in situations where oil to water ratios are unfavorable, or to assist with the production of heavy gravity crude oils, i.e., low API gravity (Liu, 2006; Dong and Liu, 2007) (Video 24).

Figure 179. Water injector arrangement patterns. Shown here are the 4-Spot and the 5-Spot patterns. Single wells are typically associated with simpler patterns, whereas large pools demand complex patterns.

Video 23. The animation shows the sequential transformation of producing wells into water injector wells.

Video 24. Oil, connate water and alkali-surfactant flood moving through a laboratory scale reservoir. The alkaline flood reduces the interfacial tension between the flood water and oil, increasing sweep efficiency. (after Dong and Liu: with kind permission).

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Miscible processes Miscible fluids are utilized to produce oil that could potentially become residual oil. This is achieved by injecting a fluid that mixes with the produced fluid. Typical miscible fluids are organic-based solvents, hydrocarbon gases, CO2 and N2 (Breit, 1992; Jahn et. al.,1998)

Artificial lift systems Some wells will produce throughout most of their life without the need for EOR. However, most wells will require some form of recovery method to enable or accelerate production. Many wells require some form of artificial lift as reservoir pressures drop and production declines. Artificial lift is not an EOR technique, although it can augment the specific application of EOR. Artificial lift may also extend the life of a pool or field, or become the only means through which a well can become economic. Prior to the option of running horizontal legs, production from stripper wells (i.e., production less than 1.5 m3 p.d.) was only feasible by using a pump jack (beam pump) (Figure 180), the cost of which may represent one third of the total cost of drilling and developing some wells in N. America. In the case of offshore ventures, the cost of production can easily exceed exploration costs. When is the best time to install an artificial lift system? The obvious need is when production rates decline, or when the well is in danger of becoming sub-economic. However, probably the most intelligent time to install an artificial lift system is prior to first oil; because the cost of installation can be covered by the increased production rate throughout the life of the well, and the cost of installation written down over a longer period of time (if advantageous). Although, there may be cases when the optimal type of artificial lift changes during the life of a well or field. The types of artificial lift discussed here include: the pump jack (beam pump), the progressive cavity pump, the electric submersible pump, hydraulic reciprocating pump, hydraulic jet pump, continuous flow gas lift and intermittent gas lift (Figure 181) (Smallwood, 1992; Jahn et. al., 1998).

Gas lift Gas is injected into the producing fluid column, which decreases the hydrostatic pressure within the well bore, thereby stimulating natural flow (Figure 181a). In the continuous gas lift type, a constant stream of gas aids the production of fluid and the gas becomes dispersed within the produced fluid. However, in the intermittent gas lift variant the gas is injected as 'pulses' generating a 'piston-like' or pulse lift. The gas is removed from the produced fluid at the end of each 'pulse'.

Lift capability (gross / BPD) 100 to 1,000 Hydraulic efficiency 2 to 30% Continuous gas lift Lift capability (gross / BPD) 1 to 800 Hydraulic efficiency 2 to 10% Intermittent gas lift

Figure 180. A pump jack in the Midale field, Sask., Canada.

Figure 181. Examples of artificial lift systems. A gas lift, B hydraulic jet pump, C pump jack, D progressive cavity pump and E electric submersible pump (after Jahn et. al., 1998; with permission from Elsevier)).

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1 2 3

Figure 182. A generalized three phase separator (redrawn and modified after Jahn et. al., 1998).

Hydraulic jet pump A downhole hydraulic motor, driven by a hydraulic medium under pressure, achieves lift (Figure 181b). Energy for the motor is delivered via the hydraulic medium by a surface motor. There are no moving parts in the downhole hydraulic motor.

Lift capability (gross / BPD) 80 to 12,000 Hydraulic efficiency 10 to 30% Hydraulic Jet pump Lift capability (gross / bpd) 80 to 10,000 Hydraulic efficiency 2 to 30% Hydr. reciprocating pump

Pump jack Also known as the beam pump and affectionately as a 'nodding donkey' (Figure 181c). Lift is achieved by a downhole plunger, which is connected to the counter-balanced reciprocating beam by sucker rods. A small motor drives the beam at the surface. Differing rates of production are achieved by varying the beam speed, the dimensions of the plunger and stroke length; all of which should match the permeability characteristics of the reservoir and viscosity of the produced fluid.

Lift capability (gross / BPD) 1 to 5,000 Hydraulic efficiency 50 to 60%

Progressive cavity pump Based upon the Archimedes screw, the progressive cavity pump is a downhole motor driven by a small surface motor (Figure 181d). Variations in production rate can be achieved by changing the dimensions of the stator rotor and pump speed.

Lift capability (gross / BPD) 1 to 2,000 Hydraulic efficiency 50 to 70%

Electric submersible pump This is a centrifugal type of pump driven by a downhole motor powered by electricity (Figure 181e). Typical units consist of more than one pump, arranged as a series of pumps to aid lift.

Lift capability (gross / BPD) 100 to 50,000 Hydraulic efficiency 40 to 50%

Surface production facilities Introduction It is an exceptional oil-field fluid that can be produced from the reservoir ready to export. Typically the produced fluids will exist as a mixture of oil and gas, oil and water, oil plus gas and water or even condensate and hydrogen sulfide etc. Therefore, the produced fluids must be separated and the unwanted fluids or gases disposed. Separation is achieved at the surface in an oil and gas processing facility near or adjacent to the producing well and such facilities are tailored to the specifics of the producing well, pool or field (Jennings, 1992; Jahn et. al., 1998). Off shore facilities may employ three separate fluid separators; consisting of a high pressure, medium pressure, and low pressure separators to remove gas and water. In comparison, land-based operations often use a single three phase separator (Figure 182).

Separators The single three phase separator uses differences in density to remove gas, free-water and oil from the produced fluids (Figure 182). The inlet section [1] separates most of the liquid phase from the produced mixture. The dissolved gas comes out of solution and rises within the vessel as a gas phase. Because small amounts of liquid may exist as droplets within the gas phase, a demisting section [2] or device is utilized to remove any fluid phase. Demisting can be achieved by ether a centrifuge demister or an impingement demister. The centrifuge type utilizes high velocities to separate the phases whereas the impingement device is composed of either a screen or series of condensing plates upon which the fluid phase condenses. The fluid phases are separated at the base of the tank by a weir [3], which causes the liquid phases to 'back-up', separation of oil and water is achieved by differences in density. Water-free oil spills over the weir and is collected as gas- and water-free oil.

Production and recovery

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