6.2.1 Facilities Location and Well Numbers

The process that links appraisal and production is called development. For petroleum accumulations that are offshore, development is a distinct phase that accompanies construction of the offshore facilities. For an onshore field, appraisal, development, and production can form an overlapping spectrum of processes that take a field from discovery to peak production. This is because, in many land locations, it is possible to produce and sell oil soon after discovery. In such situations, development might reasonably be taken to cover the major period of well drilling between discovery and plateau production.

Appraisal of an oil- or gasfield has delivered a measure of petroleum in place. At the onset of development, extensive modeling of the reservoir will have been completed to give an estimate of how much oil or gas is likely to be recovered and how many wells will be needed. However, such modeling of the reservoir will have used little or perhaps no dynamic data. For example, many of the recent field developments in the deep-water Gulf of Mexico were not production-tested during the exploration or appraisal phases. Companies are reluctant to test such wells because of the high expense. Instead, analog data are used to predict the flow characteristics of the field. This is a high-risk strategy.

A model, life of field, production profile is shown in Figure 6.1. It is divided into three phases: production build up, plateau production, and decline. During the phase of decline much effort is put into finding additional reserves. Such reserves are likely to include improvements in recovery from the original field as well as tie backs of satellite fields. All oilfields will produce gas as well as oil and many will also produce water (Figure 6.2). This first production forecast is of particular importance for the design criteria for the production facilities. The estimated plateau oil production rate will naturally define the size of the export facility for the oil. The estimate of gas production in an oilfield will be used to determine whether a separate gas export facility is required, whether compression is required for gas reinjection, or if there is just sufficient gas for power generation at the facility. For oilfields where the production of associated gas is low, it may be necessary to import gas to the facility. The timing and quantity of water production will control how and when water handling will be installed. For example, preliminary modeling may indicate that water will not be produced for a few years after field start-up. In consequence, it may not be necessary to install the full water-handling capacity for the first day of production. The total production profile thus controls the whole design of the facilities. During the period of design and construction, much work is done on the reservoir. Indeed, it is common nowadays for production wells to be pre-drilled from a template during construction of the production facility. Such wells clearly provide a wealth of information about the reservoir. They also allow a rapid buildup of production, so as to enable an early start to paying-off the cost of development.

The position of production and injection wells will be optimized using the reservoir model. The factors that will be taken into consideration are the position and strength of aquifers, the distribution of gas caps, the dip of the reservoir, its quality and the degree of layering and lateral heterogeneity, and the location and number of potential baffles and barriers to fluid flow (faults, cemented horizons, and sealing lithologies). The well positions will also depend upon the chosen method for production, which itself may in part be influenced by the distribution of the natural factors listed earlier.

For example, in the super giant oilfields of the Zagros fold belt of Iran and Iraq, production wells are often placed on the crest of the fields. Many of the fields are without primary gas caps, oil columns can be measured in kilometers, reservoirs are fractured, and aquifers are poor. Without the thick oil column one would expect rapid production of water as it floods up fractures into the production wells. However, with such large fields and such thick oil columns it is possible to produce oil wells at a high rate, and it will still take many tens of years (perhaps more than 100 years) for water cut to become appreciable. In smaller fields, it may be necessary to be less cavalier about well placement. Fields deemed to have very active aquifers might need to have production wells placed not just at their crests but in lower-quality reservoir. In such situations, high-permeability conduits could cause much oil to be bypassed, such that production wells quickly run to water. This situation is a progressively greater problem as oil viscosity increases.

Oil reservoirs with gas caps require a different well placement strategy. A reservoir containing a large gas cap, a poor aquifer, and an oil rim may be exploited by placing production wells low in the oil column or even at the top of the underlying water interval. However, if the aquifer is large and active, wells tend to be drilled in the lower part of the oil leg. In this instance, it is commonly easier to manage a downward migration of the gas/oil contact by injecting gas into the gas cap.

If the field is to be produced using secondary recovery techniques, the position of wells for water or gas injection must also be planned. Water injection is commonly planned either as line drives or pattern floods. These terms are reasonably self-explanatory (Figure 6.3). Line drives are commonly used in dipping reservoirs, while pattern floods may be used in complex reservoirs or near flat-lying reservoirs. If a reservoir is heavily segmented, it may be necessary to treat each segment as a separate accumulation and use paired production and injection wells for each segment. In recent years, some less than obvious water-flood techniques have been tried with considerable success. In the giant Prudhoe Field (Alaskan North Slope), water has been injected into the gas cap. Because the oil and water legs are laterally separated in this low-dipping reservoir, this method has compromised neither the oil nor the gas production, but has helped to sustain reservoir pressure and thus oil production. The injected water sinks to the base of the reservoir section and then flows down dip, so displacing oil toward the production wells.

Fields with natural gas caps are often considered for gas cap drive (Figures 6.2 and 5.52). Associated gas, that exsolved from the oil during production, can be injected into the gas cap to maintain pressure. Even in reservoirs that lack natural gas caps, gas may still be put into field crests because it is an extremely efficient displacement process, enabling production of attic oil that may otherwise be inaccessible. This technique has been used in the western panel of the Douglas Field (East Irish Sea Basin; Yaliz and McKim 2003). In the Lennox oil- and gasfield close to Douglas, wet gas (methane plus higher homologs) has been injected into the gas cap to maintain pressure (Yaliz and Chapman 2003). Preliminary analysis of the data for Lennox indicate that gravity segregation of the “heavier” components within this gas may limit gas breakthrough in oil production wells by reducing the viscosity contrast at the gas/oil contact. In some fields, a combination of water and alternating gas injection (WAG) may be chosen.

The development team uses the reservoir model to determine the number of wells required. The reservoir model will also yield the expected volume of petroleum that is recoverable from each well. Although every effort will be taken to ensure that the reservoir model mimics the behavior of the field when in production, it is of course not conditioned to the actual performance of the field for which it has been built. However, after the field has been on production for some time, it will become clear just how much each well is capable of producing and the degree to which the model was able to forecast the behavior of the field. Naturally, the new production data can be used to modify or rebuild the reservoir model and so refine the forecasts for production from both individual wells and for the field as a whole.

The quantity of petroleum that can be recovered from a well depends upon a range of criteria. These include the permeability of the reservoir, the viscosity of the oil, the degree of reservoir heterogeneity, well management (pressure drawdown history), the presence or absence of aquifers or gas caps, and well longevity. The most prolific wells in the world’s giant fields can deliver over 50 million barrels during their lifetimes, while the productive history of most wells can be measured in hundreds of thousands of barrels. For example, wells in the Magnus Field (UK North Sea) need to deliver on average 50 MMBO; while Helena-1, the discovery well for the Forest Reserve/Fyzabad complex (Trinidad), celebrated its 75th birthday in 1995 having delivered about 750 000 bbl. In reaching this quantity of oil, the well has been worked over about six times in its 75-year history. The ultimate life-of-field productivity for gas wells is commonly measured in tens to hundreds of billions of standard cubic feet.

6.2.2 Well Geometries

Most exploration and appraisal wells are vertical. Few development or production wells are vertical. A vertical or near-vertical well is the natural choice during exploration. The aim of the well will be to penetrate a primary, and possibly several secondary, target horizons. A vertical well cuts across the stratigraphy. It is easier to plan on the sparse seismic data commonly available during most exploration programs than would be a well with more exotic geometry. A vertical well will also allow collection of data such as pressure gradients and it will possibly penetrate fluid contacts (gas/oil, gas/water, and oil/water).

Quite clearly, a development/production well has quite different requirements. The aim for such wells is to produce as much petroleum as possible, and to produce that petroleum at economic rates. This can be achieved in a variety of ways, although ultimately the effect is much the same; optimization of permeability × height (measured in millidarcy-feet, mDft, or millidarcy-meters, mDm). Such optimization may mean that the field has many vertical wells (Figure 6.4a) or a few high-angle or horizontal wells (Figure 6.4b). The decision on the type of well to be drilled will be a function of the location, the petroleum distribution, cost, and the reservoir properties. In an onshore location, vertical wells may be easy to locate, shallow, and cheap to drill. In such situations, it would be perverse to try to drill expensive and complex geometry wells. Offshore, the situation is different. It is rarely possible to have lots of wellheads scattered over a large area, except in shallow lakes and seas subject to mild weather conditions (e.g. Lake Maracaibo, Venezuela; the Gulf of Paria, Venezuela/Trinidad). In offshore settings such as the Gulf of Mexico, offshore West Africa, and the North Sea, wellheads will be clustered at the production facility (Figure 6.5). Well tracks will be deviated away from the facility location to cover the productive area of the field. The angle of the wells as they pass through the reservoir can vary from vertical to horizontal. As discussed earlier, high-angle and horizontal wells will tend to be more productive than vertical wells insofar as they have longer sections in reservoir than do equivalent vertical wells. The choice of high-angle versus horizontal is commonly made depending upon the vertical heterogeneity of the reservoir. Strongly layered reservoirs in which there are barriers to vertical fluid flow may not benefit from horizontal wells – or, more properly, those that are parallel to the stratigraphy – because the barriers will prevent petroleum from being produced from horizons not specifically penetrated by the wellbore. In such instances, it is commonly the practice to drill wells that cross-cut the reservoir stratigraphy.

High-angle and horizontal well technology was developed during the 1980s. The product of the 1990s is the multilateral well. In such wells there are two or more branches in the reservoir section. Clearly, although such wells are complex to drill, much money is saved in drilling the top-hole section. It is drilled only once for each multilateral cluster. An example of multilateral wells being used in field development comes from the Lennox Field in the East Irish Sea Basin (Figure 6.6; Yaliz and Chapman 2003). The field is a broad domal structure, with a thick gas cap of about 700 ft and a thinner oil leg of about 150 ft. The unmanned platform lies approximately above the center of the field, from which wells are drilled vertically downward toward the field, before being deviated to horizontal within the oil leg. The field contains one trilateral well drilled in the east and south and several bilateral wells.

6.2.3 Well Types

Wells can be divided into three broad categories; production wells, injection wells, and utility wells. We have already covered production wells. Injection wells may be required for either water or gas, depending upon the recovery method used or the field. Utility wells can include those drilled as a source of water for injection, those drilled such that produced water and cuttings can be disposed of, and those used for observation.

The primary purpose of injection wells, be they for water or for gas, is to maintain the pressure in the reservoir as petroleum is extracted. The efficiency with which the water or gas will sweep oil from the reservoir is also important. Water injection will be of little value in a field if the injected water runs from injection well to production well and bypasses much of the oil in the reservoir. Most oils are more viscous than water and the problem is exacerbated as the viscosity contrast increases. Thus attempts are made to place injection wells where pressure support can be maximized and the potential for water breakthrough minimized. Whether or not this can be achieved will be determined by the segment size of the field and the permeability heterogeneity. Clearly, it is best to avoid high-permeability intervals with injection wells, as these can often be conduits direct to production wells (Figure 6.7).

The injection of cold water into hot rock can lead to thermal fracturing as the rock shrinks around the wellbore area. The direction of fracture propagation can be determined by measuring the local stress field in the subsurface. Clearly, fractured rock will allow greater injectivity for a given injection pressure. This natural phenomenon is commonly used to help injectivity in hot and deep reservoirs that have low matrix permeability.

The design of injection wells, like that of production wells, has become highly sophisticated. For example, paired groups of multilateral production and injection wells are being used to produce oil from poor-quality carbonate reservoirs in the Middle East. In this particular example, productivity was improved by two orders of magnitude compared with the production rate in the original, vertical wells. This has allowed development of hitherto uneconomic oil. All of these injection wells need to be designed by a team that includes drilling engineers, reservoir engineers, and petroleum geoscientists.

Utility wells, be they for injection of produced fluid waste or cuttings or for source water, tend to be simple and are likely to be near vertical. Although such wells will be simple in geometric terms, the geologist will be involved in determining their position in much the same way as would be required for production and injection wells. For example, the distribution of Paleocene submarine-fan sandstones overlying the Jurassic-age reservoir of the Gyda Field (Norwegian North Sea) was studied from the point of view of cuttings injection.

Observation wells are rarely drilled in their own right, except to monitor flood fronts in enhanced oil recovery (EOR) pilot projects. More often, pressure gauges are inserted in an old wellbore.

6.2.4 Drilling Hazards

In addition to determining the best locations for production and injection wells, it commonly falls to the geoscientist to identify potential drilling hazards for a well. It is most important for the geologist while planning a well to identify possible sources of danger to human health. In many instances, the singularly most important and abundant shallow hazard is gas (methane). It is most usual to conduct high-resolution (seismic) site surveys to enable identification of such gas. Other hazards include seafloor instability, shallow water flows (especially in deep-water) and gas hydrates, often difficult to detect from conventional seismic data.

Mobile mudstones and those that are chemically unstable with respect to drilling fluids are also commonly mapped. Similarly, hard horizons such as flint layers tend to be identified and their abundance calculated. Once the potential hazards have been identified, the drilling engineer can plan to minimize their effect. This may be manifest as a decision to change the drill bit before entering hard lithologies, to manage the mud weight in sensitive formations, or to modify casing schemes (the process of stabilizing an open hole by cementing a pipe in place).

6.2.5 Well Completion and Stimulation

The process that takes place between the drilling of a well and the production of petroleum from it is called completion. The type of completion can vary from the most simple – open hole – to rather more sophisticated methods using slotted liners, wire mesh screens, gravel packs, and fracture stimulation methods. The main aim of completion is to optimize petroleum production while maintaining the integrity of the wellbore. In many instances, the technology required to stabilize the wellbore has a detrimental effect upon the productivity. For example, in poorly consolidated formations it may be necessary to place a gravel pack (a sheath of clean, monodisperse sand, or glass beads) across the producing interval, so as to reduce or eliminate the tendency for the well to produce sand as well as petroleum. Clearly, in placing a gravel pack across the production interval, the permeability in the wellbore has been compromised. The role of the geoscientist is to describe the rocks penetrated by the well in terms of their physical properties, such as permeability, the degree of consolidation or cementation, and the natural stress regime.

Well-stimulation technology is designed to improve the near-wellbore permeability. Such stimulation may be either through physical or chemical methods. Acid washes can be used to dissolve minerals in the near-wellbore region. Hydrochloric acid is used for carbonates, while hydrofluoric acid may be used for low-permeability sandstone formations. Apart from the intrinsic health hazards of using such acids, work is also required on the reservoir formations prior to acid treatment, to determine their suitability for such treatment. For example, direct treatment of the Rotliegend Sandstone of the North Sea’s Southern Gas Basin with hydrofluoric acid can result in reduction of permeability, as the hydrofluoric acid reacts with calcite and dolomite to produce insoluble calcium fluoride (fluorite). In consequence, such sandstones are commonly pretreated with hydrochloric acid to remove calcium carbonates before the hydrofluoric treatment. Problems may also be encountered with the production of iron hydroxide gels following acid treatment. It is therefore important to have a mineralogical analysis of the formation prior to any chemical treatment.

Physical stimulation of reservoirs commonly involves fracturing. In this instance, fractures are created hydraulically, using a suspension of tough beads in a proppant gel. The mixture is injected into the formation until the rock fractures. The mix of proppant gel plus beads migrates along the fractures. At the end of the fracture process, the pressure is reduced but the fractures are kept open by the injected beads. The proppant gel is then broken down. This may require further chemical treatment. Alternatively, the proppant may be designed to degrade naturally.

Quite clearly, the important geoscience work to perform prior to any “frac pack” treatment is that of analyzing the local stress regime. The ideal fracture geometry is one that is parallel to the wellbore, rather like a pair of “Mickey Mouse” ears (Figure 6.8). This can normally be achieved when the principal stress direction is vertical (gravity). However, in neotectonic areas the principal stress direction may not be vertical, and in consequence the fracture may open up perpendicular to the wellbore. This leads to minimal improvement in near-wellbore permeability (Figure 6.8). Indeed, this is believed to have happened when attempts were first made to reactivate the Pedernales Field in eastern Venezuela (Jones and Stewart 1997): a wrongly designed frac-pack is thought to have led to complete loss of productivity in the first of the reactivation wells drilled.

6.2.6 Formation Damage

Formation damage is the inadvertent and opposite effect to well stimulation. Permeability is reduced and the flow rate of the well diminishes or is stopped altogether. Two categories of mechanisms can be responsible for formation damage; reduction of absolute permeability, or reduction of relative permeability in the near-wellbore region. Although the overall effects of formation damage can be categorized simply into one of these two mechanisms, the individual causes are multifarious and a whole array of individual terms has been developed to describe various situations. Just a few of these are water block, condensate block, fines migration, asphaltene drop-out, and scaling (mineral precipitation). Some effects may be cured or reduced by remedial action, but the best option is to reduce the likelihood of the problem in the first place. As will be clear from some of the terms described above, formation damage results from the physical effects on the reservoir and fluids caused by drilling, or by the interaction between the drilling fluids and formation fluids or reservoir minerals.

The degree of damage to a well is referred to as the “skin factor.” This skin effect can be considered as a rate-proportional steady state pressure drop, given as a product of a flow-rate function and a dimensionless skin factor (Archer and Wall 1986). The numerical value of the factor is only a semiquantitative measure. Nonetheless, such numbers do help to describe formation damage. For example, for a vertical, unfractured, and undamaged well, the skin factor would be zero. As the degree of damage increases, so does the skin factor. Skin factors of less than about five indicate a little damaged well. Skin factors reported as many tens or even hundreds are obtained from severely damaged wells. It is possible to calculate a negative skin factor. This can be real, insofar as it is a product of a naturally or artificially fractured well, or simply a product of the calculation, as can be the case in a high-angle or horizontal well. In both instances, it implies that the flow into the wellbore will be greater for a given pressure drop than would be the case in an undamaged, equivalent vertical well.

Absolute permeability reduction occurs when pore throats in the near-wellbore area are blocked. Such blocking can occur when fines such as clay minerals become detached from their host grains and migrate toward the wellbore. Both chemical interaction between the drilling fluids and the rock and the physical effects of fluid flowing from formation into the wellbore may be the cause. The same absolute reduction can occur when drilling fluids and formation fluids react to produce insoluble precipitates. A particularly dramatic example of such formation damage occurred when the discovery well of the Miller Field (UK North Sea) was drilled in December 1982. One of the authors was involved in the detective story associated with tracking down the problem of a nonproductive well test on the Miller discovery well.

The Miller reservoir is almost pure quartzite and is one of the cleanest sandstone reservoirs known (Gluyas et al. 2000). However, on test the discovery well failed to flow at an appreciable rate. The initial reaction of the drilling, completions, and testing teams was that the rock was of poor quality (permeability). This was not compatible with either sedimentological or core analysis data. The porosity was known to range between about 13% and 25%, and the absolute permeability was measured in hundreds of millidarcies and darcies. Routine analysis of the rock using a scanning electron microscope showed that although it comprised quartz-cemented quartz grains, many of the pores were partially filled with patches of a microcrystalline solid. Coincident with the work on the Miller discovery well, an EDAX (X-ray elemental analysis) facility had been fitted to the microscope. The microcrystalline mass was found to contain barium and sulfur. At first, it was thought that this barium sulfate (barite) was a contaminant from the drilling mud. However, this proved not to be so. The formation waters in Miller were found to contain between 1000 and 2000 ppm of dissolved barium, and the exploration well had been drilled with a seawater-based (sulfate-rich) mud system. Barium and sulfate had reacted to yield a near-impermeable membrane around the wellbore. But for this work on formation damage, a cooperative venture between geoscientists and completion engineers, the barite problem might never have been properly appreciated, the research work on scale prevention not initiated, and the full quality of the Miller reservoir never recognized.

Reduction of absolute permeability can also occur when drilling fluid filters into the formations and solids are deposited around the wellbore. Such formation damage is commonly very difficult to remove or reduce during the well-completion process.

Reduction of absolute permeability can also occur as a result of precipitation of asphaltene from the reservoired oil. Such precipitation can occur in some oils when the pressure is reduced. This is a very common problem in production strings. Here it can be removed, albeit with difficulty, by scraping the production string or giving it a chemical wash with a nonpolar solvent such as toluene or xylene. However, if precipitation occurs in the reservoir close to the wellbore, amelioration of the problem can be near impossible. The well may have to be abandoned. The propensity for asphaltene precipitation needs to be studied by the geochemist, using fresh oil samples taken, if possible, at reservoir conditions. Asphaltene precipitation, both natural and induced, is a problem in parts of the El Furrial Province in eastern Venezuela.

Relative permeability reduction is a product of having several phases of fluid (gas, oil, and water) in the near-wellbore region. The relative permeability to the desired phase, usually oil, can be impaired or even reduced to zero by the presence of another phase. The use of water-based drilling fluids can in some reservoirs lead to so-called “water block,” in which only water can be produced back into the wellbore. A similar situation can be induced if the pressure drawdown during testing and production causes gas to break out in the reservoir.

Formation damage can occur in injection wells just as easily as in production wells. The former leads to a loss of injectivity and the latter to a loss of production. Although here we have concentrated on near-instantaneous effects caused by drilling, formation damage can progressively reduce the productivity/injectivity of a well. Particularly acute problems are commonly encountered once injection water starts to break through into production wells. Many formation damage problems can be avoided or minimized by appropriate geoscience work on formation mineralogy, formation fluids, and the physics of the reservoir and fluid system.

6.2.7 Well Logging and Testing

In the preceding chapters, a variety of well logs and the data obtained from them have been described. These data have in all instances been static data, rock properties, and fluid properties. However, it is also possible to take measurements in flowing production and injection wells. The aim of such measurements is to obtain information on the rate of fluid flow, the type, and locations of different fluids as they enter the wellbore and where fluids are flowing (inside the well casing or behind pipe). It is also possible to measure pressure data from wells during flow periods or pressure changes when a well is not flowing. In this section, we will concentrate on the geologic information that can be obtained from such logging and well testing. Such data can help the geoscientist to improve his or her description of the near-wellbore region, as well as yielding data on the reservoir architecture and the proximity to barriers such as faults.

Production logging methods are highly varied. They include mechanical devices (spinner surveys) and radioactive methods to detect fluid flow in the wellbore. The fluid type can be measured using density tools or fluid capacitance instruments, in which the dielectric properties of the fluid are used to differentiate between petroleum and water. Temperature data are also very useful in allowing the identification of flowing and nonflowing units within producing wells, injecting wells, and even shut-in wells.

The spinner type of survey uses an instrument that contains an impeller. As the instrument is pulled up the well, across the flowing reservoir interval, the impeller spins ever faster in response to the flow into the wellbore. If particular intervals are not contributing to flow, then the rate of spin does not increase as the tool passes across them. In an undamaged well, with all zones contributing, there will be a close match between a composite permeability height plot for the interval and spinner results. The radioactive devices depend upon the injection of a slug of radioactive material into the wellbore. The radioactivity is then measured across the reservoir interval and the results may be interpreted in terms of flowing and nonflowing intervals. Given the obvious environmental and health issues of such a process, the application of such technology is commonly limited to injection wells.

The capacitance and density methods allow identification not just of petroleum versus water but of where the different fluids are entering the wellbore. In a geoscience context, such information will enable improved reservoir description, the application of which may help to avoid water inflow in subsequent wells, as problem intervals need not be perforated.

In much the same fashion that mechanical spinner tools can be used to measure fluid flow, so too can temperature response tools (Figure 6.9). For example, in an injection well, cold injection water is introduced into a hot formation. If a particular horizon is accepting most of the injected water, then it will be cold relative to those horizons in which injection is limited. In much the same way, temperature data in a shut-in well can help to identify cross-flow between formations.

Pressure data from wells are used to define local and field-average reservoir pressures. Such data, when combined with production information on petroleum and water, and with fluid and rock property data, can be used to calculate the petroleum in place and the expected recovery factor. Unlike measurements based upon core or well logs, which only yield direct data from within or close to the wellbore, the depth of investigation of time series pressure data can encompass an entire field or field segment.

Pressure tests (e.g. RFT™s and MDT™s) can be made in flowing wells in addition to static wells (Chapter 2). Data from such tests can be used to indicate the boundaries to individual flow units, barriers to flow, and compartments in the reservoir. The interpreted data from the pressure tests can then be used to aid field development design.

Pressure data from wells, rather than individual formations, may be obtained in a variety of situations. Data can be collected during constant production from a well (pressure drawdown), while a well is shut in (pressure buildup), during multiple-rate flow periods, in one or more shut-in wells while producing from another, in injection wells, and in drill stem tests (DSTs). The essential feature of all of these different situations in which pressure is measured is that a time series of data may be obtained. The temporal response of the field to a pressure disturbance is being measured. We will concern ourselves here with the description of such test data. The mathematical background is given in Matthews and Russell (1967).

Reasons that pressure buildup tests tend to be performed more often than drawdown tests include: (i) during buildup the well is responding only to the natural restoration of pressure and is not under the influence of “man-induced” flow, and therefore the more subtle pressure changes are likely to be captured, and (ii) a combination of legislation and much greater awareness of environmental issues means that waste emission during testing of exploration and appraisal wells (flaring) is minimized. As a consequence wells tend to be flow-tested for short periods and then the pressure is allowed to build up over a few days.

Whether during drawdown or buildup, the pressure change through time can be divided into three periods, characterized by different pressure change behavior. In the period immediately following the pressure disturbance (test), the wellbore pressure is unaffected by the drainage boundaries of the well and the pressure buildup behaves as if it were occurring in an infinite system. This interval of time is often referred to as the “transient period.” At some time later, the influence of the nearest boundary is seen in the wellbore pressure response. Other boundaries may then be observed during this so-called “late transient period.” Finally, the pressure buildup (or drawdown) reaches steady state (the rate of change of reservoir pressure is constant with time) once stabilized flow conditions have been established.

The change from transient to steady state depends in particular upon reservoir geometry, reservoir compartmentilization, porosity, and permeability. Ideal behavior (Figure 6.10) is rarely achieved, and a number of techniques have been developed for analysis of the data in the absence of constraining geologic information (Figure 6.11). Naturally, the corollary is that when combined with geologic data (fault distributions, reservoir pinchout maps, and fluid composition data), the pressure data provides a very powerful tool for reservoir description.

Most tests are performed at a constant production rate. However, it is possible to derive much of the same data by performing tests on a well that is subject to multiple-rate flow periods. This is particularly common on gas wells, which may require such testing to satisfy regulatory bodies. This method is also used on wells where a shut-in prior to a drawdown test or for a buildup test may not be economically desirable.

One further category of well test, the interference test, deserves particular mention. In a single well test, although the pressure buildup information may be highly accurate, it is commonly difficult to interpret the data in geologic terms because it is scalar: the distance to boundaries may be observed, but the direction to those boundaries is not known. Even when high-quality geologic data are available, it may not be easy to identify the likely geologic features responsible for particular effects on the pressure buildup. The value of time series pressure data can be maximized in interference tests. In such tests, a well is put on production or subject to injection while one or more surrounding wells are shut in, with pressure gauges installed. The effects of the production or injection can be recorded in the surrounding wells. Clearly, the response in these wells will be delayed relative to initiation of flow in the production/injection well. Factors that will influence the response time and response effect are distance, permeability, connected porosity, and directional reservoir flow patterns. That is, when combined with the geologic data, it should be possible to describe the location and nature of baffles and barriers to fluid flow and the permeability anisotropy of the reservoir system.

Where pressure data are not available, it may be possible to use the production history of wells to effect a similar analysis of reservoir performance behavior. The technique is simply one of observing the effects on existing wells when a new well is brought on stream. The method is particularly useful when applied to old fields with many closely spaced wells. Often in such situations, the production data and well histories are the only recorded data for the field. Such production data are a valuable tool for the geoscientist.

The petroleum production rate obtained during a well test is an important indication of how the well, and indeed the field, will behave when on production. An important derivative of a production test is the productivity index (PI). This is because the actual production rate in a test varies as a function of the pressure drawdown imposed upon the reservoir as well as the intrinsic properties of the reservoir and its oil. The PI is thus a measure of the performance of the reservoir, normalized for the pressure difference between the reservoir and the wellhead (drawdown):