Abandon a Field

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6.3.1 Introduction

A hydrocarbon reservoir is described as technicallydepleted when, at a given point in its life, the sale of its products no longer covers production costs. Thisdoes not mean that all hydrocarbons contained withinthe reservoir rock have been produced. Usually, whenthe limits of economically viable production have

been reached, the reservoir still contains a fair amount of hydrocarbons, some of which may berecovered with appropriate workovers on wells or

assisted recovery techniques. However, this involvesadditional expenditure, which must be carefullyevaluated before work begins. From a technical and economic point of view, the decision to abandon afield cannot be made with ease until everyeconomically viable effort has been undertaken to

prolong its productive life. A decisive factor in thisdecision, however, is the predicted price scenario for its products, which often fluctuates. In addition, thedecision may be influenced by strategic, political and logistical factors. The oil company may have a vested interest in maintaining its presence in a given

geographical area, in order to better exploit futuredevelopment opportunities from a privileged position(for example, the exploration or participation in theconstruction of oil pipelines, etc.). This clearlydepends on the strategies of the company, which may

be willing to produce at a loss in one sector with the prospect of future benefits in other projects.

A delay in the decision to abandon a f ield may also be due to logistical factors, − for example, themaintenance of a base (at a loss) and its storagefacilities, offices, etc. − so as to operate inneighbouring geographical areas where the

construction and maintenance of a new base would beextremely expensive or even impossible.

This chapter will conclude the presentation of thevarious phases of a production cycle from explorationto development and production. To better understand the reasons that usually lead to the decision to abandona field, some concepts and topics already discussed inearlier chapters will be covered.

A mature field (i.e. in an advanced stage of production) is usually characterized by medium-low pressures, relatively high levels of water saturationand high levels of gas saturation (in oil reservoirs)near the wells. A pressure decrease in the reservoir,

due to the production of the fluids contained withinit, leads to a reduction in hydrocarbon rates over time. The presence of formation water (or gas, in oilreservoirs) may hinder the flow of hydrocarbonstowards production wells: water may be produced alongside hydrocarbons, making it difficult to bringthem to the surface and causing treatment plants towork inefficiently.

Due to this progressive deterioration, themechanical condition of wells and surface facilities(plants, tubing, platforms, etc.) may decrease in termsof efficiency, leading to sudden drops in production.

Insufficiently drained areas of the reservoir mayalso exist, with signif icant amounts of hydrocarbonsstill to be produced.

To achieve proper management of reservoirs,mathematical simulations with numerical models areincreasingly applied. If historical production

parameters are monitored appropriately, and one has arough knowledge of the geological and petrophysicalcharacteristics of the reservoir rock and thehydrocarbons it contains, through this type of simulation it is possible to redefine these propertieswith greater accuracy, using the technique known as

history matching (see Chapter 4.6). Generallyspeaking, the larger the number of historical

761VOLUME I / EXPLORATION, PRODUCTION AND TRANSPORT

6.3

The decision to abandon a field



parameters matched, the greater one’s knowledge of the reservoir. This results in the apparent paradox thata field can be best understood only at the end of its

production life. When a field is almost depleted, and an increasingly high number of historical production

parameters becomes available, it must be studied morecarefully to ensure that significant amounts of hydrocarbons are not left underground. It should bestressed that the cost of a reservoir study withnumerical models is usually much lower than the costof workovers on a well.

6.3.2 Economic reasons

It is obvious, given the above, that workovers onwells and facilities, and actions aimed at prolongingthe life of a field, are undertaken as long as they can

be justif ied economically by increased production. Inmaking this economic calculation, fundamentalimportance is attached to the sale prices of thehydrocarbons produced, whether oil, gas, or Liquid Petroleum Gas (LPG). These in turn depend on thequality of the oil (density, viscosity, asphaltene and

paraffin content, sulphur content, etc.), gas and LPG(composition, and above all calorific value). When

prices are reasonably stable, a simple economiccalculation taking due account of essential

parameters, such as interest rates on the capital

invested and the f iscal regulations of the countryconcerned, may indicate the suitability of a givenoperation. Clearly, when prices are particularlyunstable, it is crucial to predict hydrocarbon pricesfor a certain number of years, corresponding to

production forecasts.In this context, it is worth recalling the events

following the great oil shock of 1973, after the Arab-Israeli conflict (Yom Kippur War). Between the end of 1973 and the beginning of 1974, petroleum pricesunderwent a sudden and drastic increase. On the onehand, this led to considerable upheaval in the

expenditure budgets of industrialized petroleumimporting countries, and, on the other, provided anenormous incentive for hydrocarbon exploration and

production. Fields due for closure, having reached their economic limit, were suddenly reactivated; wells,closed due to low productivity, were reopened;extremely expensive secondary recovery operationsfound an economic justification, as did deep onshoreand offshore petroleum exploration.

In general, when economic calculations indicatethat production is no longer profitable, the oilcompany may decide to abandon the f ield. This

decision leads to the closure of the wells, thedismantling of surface facilities and the rehabilitation

of pre-existing environmental conditions. Inevitably, asmentioned before, this occurs towards the end of the

production lease, when there is no doubt that further economically viable operations, aimed at prolongingthe life of the f ield, are not feasible.

6.3.3 Technical reasons

There are many reasons why all of the hydrocarbonscontained within the reservoir rock in a depleted, or almost depleted, field have not been produced. Themost important are linked to the efficiency of thevolumetric displacement of the hydrocarbons bydisplacement fluids (water or gas) and the inability of wells to lift the hydrocarbons to the surface, due to the

progressive decrease in reservoir pressure and theinevitable production of formation water.

Effects of displacementAs already explained in previous chapters (see

Chapters 4.1, 4.3), the efficiency of the microscopicdisplacement of oil and gas within the pores of thereservoir rock never reaches 100%, due to interactions

between the rock and the fluids contained within.These interactions determine the amount of hydrocarbons (residual saturation) that remainstrapped behind the displacement front (gas and water in oil reservoirs, water in gas reservoirs). Where

movable water is present near the wells, relative

762 ENCYCLOPAEDIA OF HYDROCARBONS

FIELD PRODUCTION PHASE

gas-oil contactoriginal oil-water contactoil-water contact after several years of productiongas zone

production wells

oil zoneswept area (by water)low permeability zone (poorly drained)fault

Fig. 1. Mature fieldwith low permeability areas (poorly drained).



permeabilities cause a reduction in the oil (or gas)rates, and a gradual increase in the flow of water towards the wells.

When the pressure in an oil reservoir falls belowthe bubble point, the gas dissolved in the oil isliberated near the wells. When this reaches criticalsaturation, it becomes movable. Due to relative

permeabilities we observe a drastic reduction in the oilrate, as well as a sudden increase in the gas rates. If,on the other hand, there are conditions of high

permeability, a remarkable thickness of reservoir rock,low oil viscosity and low gas density, the gas liberated

by the oil may migrate towards the upper part of thereservoir and generate a gas cap (secondary gas cap).During production the gas in this cap expands, helpingto displace the oil towards production wells, whichmay be significant for the recovery of oil from thereservoir. This occurs because residual oil saturations

behind the gas front are generally lower than those behind the water front.

If the location of the wells is not optimum, thenumber of wells is insufficient, or the reservoir rock isnot homogeneous, ‘islands ’ of rock containinghydrocarbons may remain unswept or not completelyaffected by the displacement process ( Fig. 1).

Reasons for the pressure decline in a reservoirGenerally speaking, hydrocarbons accumulate in

subsurface porous structures, characterized by

pressures higher than atmospheric pressure, with theexception of extremely superficial accumulations(such as the tar sands of the Athabasca in Canada,where the extraction of hydrocarbons is essentially amechanical mining process, followed by recoverythrough distillation). The difference in pressure

between the reservoir and the well leads fluids to flowtowards the latter; if this flow is able to overcome the

pressure losses along its way to the surface, the resultis a natural flow. In so-called ‘volumetric ’ gasreservoirs (which lack a natural water-drive), themechanism providing the energy to drive the

hydrocarbons to the surface depends exclusively onthe expansion of the entire system (pore volume,connate water and gas) as a result of a decrease in

pressure. This expansion is linked to the value of thecoefficient of isothermal compressibility (the variationin volume of a unit volume, following a unit variationin pressure), expressed by:

ct = c g S g + cw S w + c f

where ct is the total compressibility, c g thecompressibility of the gas, cw the compressibility of the water, c f the compressibility of the pore volume, S g

the fraction of the pore volume occupied by gas andS w the fraction of the pore volume occupied by

connate water (i.e. interstitial water present inside therock from its formation).

In volumetric oil reservoirs, the productionmechanism is similar as long as reservoir pressureremains above the bubble point. At lower pressures thesituation becomes problematic, since the oil liberatesgas into the reservoir, and thus decreases in volume. Inthis case, the compressibility of oil, free gas, connatewater and pore volume contribute to productionmechanisms. Furthermore, the total compressibility of the entire system (pore volume, connate water, oil and gas) is:

ct = coS o + c g S g + cwS w + c f

where ct is the total compressibility, co thecompressibility of the degassed oil, c g thecompressibility of the gas, cw the compressibility of the water, c

f the compressibility of the pore volume, S

othe fraction of the pore volume occupied by oil, S g thefraction of the pore volume occupied by gas and S wthe fraction of the pore volume occupied by connatewater.

In the case of reservoirs characterized by finiteaquifers, the production mechanism remains theexpansion of the entire system (reservoir and aquifer):the total compressibility is calculated as shown above,with the volume fractions for oil, gas and water beingattributed to the total volume. Therefore, it becomesapparent that when the volume of the aquifer increases

notably in relation to the volume occupied byhydrocarbons, the impact of water compressibility may become significant. The compressibility valuestypically found in hydrocarbon reservoirs are asfollows:• 40 to 120 GPa 1 for pore volume;• 30 to 50 GPa 1 for reservoir water;• 70 to 1,500 GPa 1 for undersaturated oil;• 700 to 3,000 GPa 1 for gas at high pressure (35

MPa);• 13,000 to 20,000 GPa 1 for gas at low pressure (7

MPa).

For the relationship linking pressures to reservoir volumes and produced volumes (material balanceequation), see Chapter 4.3.

At the beginning of a reservoir ’s productive life, pressure is usually sufficient to overcome theresistance encountered by the fluid during its journeyfrom the reservoir to a production well, and thencetowards treatment plants. However, at a certain pointin its productive life, due to the natural decrease in

pressure caused by the fluid production, resistancemay be such that the well is no longer able to raise thefluids to the surface. The reasons for the fluid ’s

pressure drop within the reservoir up to the surfacewill be addressed below.


THE DECISION TO ABANDON A FIELD



Pressure drop in the porous mediumThe production of reservoir fluids through a well

causes the pressure inside the porous medium todecrease. If the porous medium forming the reservoir is characterized by extremely high absolute

permeabilities (above 1,000 mD) and low fluid viscosities, the pressure gradients inside the reservoir during production are extremely low, and the pressurein any point of the reservoir is quite homogeneous.By contrast, where permeabilities are low and fluid viscosities high, there may be extremely significantdrops in pressure inside the reservoir between a given

point distant from producing wells, and another pointclose to the wells. These differences in pressure may

be such that an initially undersaturated oil mayremain undersaturated at a distance from wells, and

become saturated, or even liberate gas, in their vicinity.

Pressure drop at the interface between the reservoir and bottomhole

In its journey towards the surface, the reservoir fluid flows first in the porous medium, and thenthrough an area of the reservoir close to the wellbore,which was initially disturbed during the drilling(invasion of drilling muds and mechanical effects of drilling), and later by the cementation of the steeltubes protecting the hole (casing). Further disturbanceis caused by casing and cement perforations with

explosive charges to create a communication betweenthe wellbore and the reservoir. During the production,these disturbances cause a pressure drop between thedisturbed area and the wellbore. Furthermore, if theholes in the casing are insufficient, one can observenear the holes an abrupt increase in fluid velocities,which may cause turbulence and a further decrease in

pressure. This turbulence may cause sand problems(see Chapter 6.2) and the formation of stableemulsions, which may even block the flow through the

perforation holes (e.g. when reservoir water is produced alongside hydrocarbons).

Pressure drop inside production stringsTo be produced, the hydrocarbons must overcome

the force of gravity (weight of the fluid column in thewell) in their journey from the bottomhole to thesurface. They must also overcome the loss of pressurecaused by the friction losses of the fluids movinginside the production string, and the pressure decreasedue to changes in velocity (reduction of the section,valves, etc.).

The weight of the fluid column (which diminisheswith decreasing depth), depends on the density of the

fluids involved, which in turn is a function of pressure.While for the formation water produced, the

dependence of the density on pressure is negligible,for oil, however, the dependence of density on pressureis greater, at least as long as gas remains dissolved within. For gas, on the other hand, density is stronglydependent on pressure. It is clear that the presence of water in the reservoir fluids produced increases the

pressure drop inside the production tubing, due to itshigher density.

The pressure drop in the well, as a result of friction losses in the wellbore, increases with thesquare of the linear velocity of the fluids, with thelinear length of the string, with the roughness of itsinterior, with the decrease of its internal diameter and the increase in viscosity of the fluid mixture(see Chapter 6.1). In general, for the same rate, thegreater the section of the production string, thelower the decrease in pressure. It should be noted that the viscosity of the fluid mixtures dependsmainly on how they are interspersed. In the case of a mixture consisting of gas bubbles dispersed in theliquid phase (or bubbles of oil in water), if conditions are conducive to the creation ofa stable emulsion, viscosity may attain extremelyhigh values.

The pressure drop due to changes in velocity becomes greater when there are more restrictions present inside the production string. It should bestressed, however, that gravity is by far the mostimportant cause of pressure loss in the well.

Pressure drop between the wellheadand surface facilities

A choke valve is usually inserted between thewellhead and the surface equipment, allowing thefluid rate of the well to be regulated. The purposeof this valve is to mitigate the excess upstream

pressure in the well, thus obtaining an appropriate pressure value for the downstream flow to thetreatment plant.

Pressure drop in surface facilities

The reservoir fluids that enter surface facilitiesmust overcome further resistance to flow from thechoke valve at the wellhead to the treatment plants.The pressure drop along horizontal pipes may beminor over short distances. In the case of offshorefields with onshore treatment facilities, this may bemore significant, although it never reaches thelevels attained by pressure loss inside the well,where gravity is the dominant factor. Further

pressure drops in treatment plants are generallyextremely low, and depend on the different types of chemical and physical treatment undergone by the

hydrocarbons produced before they arecommercialized.





6.3.4 Actions to prolongthe life of a field

Natural flow from wells is ensured as long as thereservoir retains the necessary drive to overcome the

pressure loss encountered by the fluids along their journey. When this no longer occurs, the wells stop producing spontaneously. The reservoir engineer, byanalysing the production behaviour of the reservoir and the well, must be able to predict in good timewhen the wells will no longer be able to producespontaneously, and suggest solutions to prolong thelife of the field.

Below, several typologies of action will beaddressed that may enable the prolonged life of a field,thus increasing recovery and delaying the time of abandonment. Workovers on production wells, whichare generally inexpensive, will be covered first,followed by the benef its that may be obtained bydrilling additional production wells, and, finally, the

benefits obtained with enhanced recovery operations.

Workovers on wellsThe operating conditions of surface facilities

usually determine the operating conditions of wells,and in particular the pressure at the wellhead downstream the choke valve. It is clear that the wellcan produce as long as the pressure upstream thisvalve is higher than that imposed downstream. Over

the course of the life of a production well, this pressure differential inevitably tends to diminish.Therefore, it is important to intervene in due time withthe appropriate operations to reduce the pressure lossundergone by the fluid in its journey from thereservoir to the surface. Below the most commonoperations will be described.

StimulationAt a given point in the life of a production well,

the drop in pressure at the interface between thereservoir and the bottomhole may become critical

for numerous reasons. One reason for this decreaseis the damage caused by the movement of tiny

particles that accumulate inside the pores of the rock near the well, or even inside the holes, which allowthe geological formation to communicate with thewell, bindering them and thus creating an obstacle tofluid flow. Another reason is the formation of stableemulsions of oil and water, and the precipitation of

paraffins and asphaltenes inside the holes, whichmay hinder the movement of reservoir fluids. Themethod most commonly used to restore productionis to reperforate the casing adjacent to the producing

horizons, using high penetration explosive chargeswith high shot density per linear metre. This results

in removing those materials that hinder production, both in the formation adjacent to the wellbore and inside the perforations. At the same time, a larger number of drainage pathways towards the wellboreare created. This system is particularly effectivewhen, in the presence of poorly consolidated sand,the production of reservoir water drags the sand grains into the wellbore, causing a sand accumulation in the well. This phenomenon may becaused by the high velocity of the fluid (usuallywater) through the holes; increasing the number of holes in the casing may reduce the linear velocity of the fluid and solve the sand problems (see againChapter 6.2).

A different type of action, generally carried outunder similar circumstances, is stimulation byinjecting acid solutions or appropriate solventmixtures into productive horizons to dissolve thematerials obstructing the holes. Acid solution may alsohave the effect of dissolving the small particles thatobstruct the pores, and of partially dissolving the rock matrix, significantly increasing its permeability near the well. In some cases, justif ied by serious damage tothe formation and by the low permeability of the rock,the productivity of the well may be restored or evenincreased by the hydraulic fracturing of the rock

behind the casing.

Changing sections of tubing

In a production well, the natural decline of reservoir pressure and the production of water maymake raising the fluids produced to the surfacecritical. This is due to the decrease in pressure in the

production string caused by restrictions inside thetubing due to valves, joints or the presence of equipment for wireline operations. These restrictionsmay lead to abrupt increases in the fluid velocity, and thus to turbulence. Under some circumstances, thismay facilitate the formation of stable emulsions or the

precipitation of asphaltenes or paraffins near therestrictions, with a consequent increase in pressure

loss. However, this problem may be solved byinjecting appropriate mixtures of demulsifiers or solvents into the well. Though when the pressure dropin the production tubing is due to its diameter, therecompletion of the well with the appropriate sized tubing normally prolongs its life. However, an increaseof tubing size does not always improve production. Infact, in the case of gas wells, which also produce somequantities of formation water and where the flowregime consists of drops of water dispersed in thegaseous phase, if the linear velocity of the mixture isrelatively low (as may occur in large sized tubings), it

may be inadequate to lift the liquid to the surface.Under these circumstances a gradual increase in the





amount of water in the well may be observed,accompanied by a consequent increase in the weight of the fluid column, which may eventually stop the

production of gas. In this case, production may berestored by recompleting the well with smaller sized tubing.

Artificial liftIn oil reservoirs, where the pressure drop in the

production string may be considerably higher compared to gas reservoirs (due to the higher densityand viscosity of oil), an excessive pressure drop,which does not allow natural flow, may be overcome

by using artificial lift techniques. Among these, themost common include mechanical sucker rod pumps,hydraulic pumps, electric submersible pumps and thegas lift (see Chapter 6.2).

Reduction of wellhead pressureDespite stimulation or the changing of sections of

production tubing, wells often fail to produce becausethe static wellhead pressure has reached the samevalue as the backpressure in surface facilities. In thecase of gas reservoirs, this pressure is generally fairlyhigh in order to allow the plants to work and to treatgas with chemical and physical properties(composition and pressure) suitable for connectionwith the gas pipeline. If the working pressure in the

pipeline is high, the dynamic wellhead pressure of the

producing well must be even higher. In order tocontinue production from a well that is no longer ableto drive the gas produced into the distribution network,it is necessary to modify the treatment plants, so as tolower the working pressure, and use the compressorslocated downstream from them to dispatch the gas

produced.

Drilling new wellsIf the analysis of a mature field ’s performance

indicates that areas poorly drained by the wells potentially exist (see again Fig. 1), it may be necessary

to drill new wells. Due to the high cost of additionalwells, it could be preferable to drill horizontal wells, or even drain holes (wells, some of which may behorizontal, drilled from a single wellbore). Thesetechniques, inconceivable only a few decades ago,allow one to cover remarkable horizontal distanceswith an excellent control over the direction and deviation angle of the hole, even within relatively thin

productive levels. These holes allow one to achieve thedual objective of improving the drainage area of reservoirs and significantly increasing the productivityof wells. The pressure drops between the formation

and the well are thus reduced to a minimum, so as therequired number of drainage points.

Secondary recoveryIn undersaturated oil reservoirs, when the pressure

falls below the bubble point, gas is liberated into thereservoir. This initially remains trapped in the poresnear production wells, thus reducing oil saturation;due to the gas/oil relative permeability, the oil rate inthe wells tends to decrease. When the gas inside the

pores reaches critical saturation, it becomes movableand may be produced by the wells in large quantities,further decreasing the oil rate. It is important to stressthat, since the compressibility of gas has an order of magnitude ranging from ten to over one hundred timesgreater than that of oil, the undesired production of gasmay cause a further substantial drop in reservoir

pressure. Under these circumstances, reservoir pressure may fall too low and the oil production fromthe wells becomes negligible. To avoid this, generallyaction is taken in due time to compensate artificially,or at least in part, for the drop in pressure by injectinga fluid into the reservoir, which replaces the oil

produced volumetrically. This maintains the pressureat a level that allows commercially viable oil

production to continue.The fluid injected and the injection technique

employed permit a further increase in the oil recoveryfactor. The fluids generally used for this purpose are:water, injected into the aquifer in peripheral areas of the reservoir or inside the oil zone through wellsalternating with production wells, according to a

predetermined geometrical distribution; and naturalgas, not miscible with oil, generally injected into theupper part of the reservoir to exploit the effect of gravity on displacement mechanisms. Water is thefluid most frequently used, and usually available at amuch lower cost than gas, which in turn, given anequivalent number of calories supplied, is similar tothat of oil.

Tertiary recoveryBefore reaching the decision to abandon an oil

field, one must check whether it is economically

viable to recover a further quantity of oil remaining inthe reservoir (not recoverable by using the techniquesdescribed above) applying advanced recoverytechniques known as tertiary recovery, or Enhanced Oil Recovery (EOR). These techniques, which areusually very expensive and only justifiable when

prices of crude oil are relatively high, are described inVolume 3. However, it is now worth mentioning someof the techniques adopted and the chemical and

physical principles on which they are based. These principles are fundamentally based on an improvementin the mobility ratio between oil and water, and thus

on the displacement efficiency. This may be achieved by lowering the viscosity of the oil through thermal





processes and by mixing it with gas (miscible processes), or by increasing the viscosity of water through chemical processes.

In the case of reservoirs containing particularlyviscous oil, one method for improving recovery is thesteam injection. In addition to providingdisplacement benefits, similar to those of secondaryrecovery with gas injection, this allows a hot gasfront to advance through the reservoir. The frontexchanges heat with the oil, with which it comes intocontact, reducing its viscosity significantly and making it more mobile and thus producible.Displacement by injecting carbon dioxide into thereservoir works in a similar way. In this case, the gas

partially dissolves in the high viscosity oil,decreasing its viscosity and increasing its mobilityinside the porous medium. Among the thermal

processes, it is also worth mentioning in situcombustion, used especially for the tertiary recoveryof high viscosity heavy oils. This technique involvesactivation of the reservoir oil combustion at oneextremity of the field, sustained by the injection of air through dedicated wells. The heat developed atthe combustion front transfers to the oil in thereservoir by conduction and convection, lowering itsviscosity. In addition, the most volatile componentsof the crude oil (obtained through distillation)followed by a front of light hydrocarbons (obtained through the cracking of heavy hydrocarbons at high

temperatures of the combustion front) mixed with theoil improve its quality and mobility. Among thetechniques that improve the mobility ratio betweenoil and water by increasing the viscosity of water,one may refer to the injection of polymer solutions.These form a plug of so-called thickened water which, thanks to this property, improves the mobilityratio in favour of oil.

Transformation into underground gas storagereservoirs

Before abandoning a hydrocarbon reservoir

(especially a gas field), it is worth examining the possibility of transforming it into a gas storagereservoir, with consequent benefits for the productioncompany. Gas storage (see Chapter 7.4) basicallyconsists of the underground storage of gas during

periods of low demand and its production whenconsumption is higher, generally in the winter whenthe sale price of gas tends to rise. However, not alldepleted or nearly depleted gas fields are suited for this transformation. For this purpose the fields must,first, be located near an active gas distributionnetwork, and preferably not far from where it will be

utilized. Second, the properties of the reservoir must be such that the gas injected for storage can be

produced without losses. The reservoirs must be ableto guarantee productivity, promptly meeting thedemand for gas during the production cycle.

Reservoir engineers are able to evaluate whether or not a reservoir is suitable for transformation into astorage reservoir. On the basis of its productionhistory, they can reconstruct its geometry as well as its

petrophysical and production properties with a fair degree of accuracy, using the history matchingtechnique in the numerical simulations. Further simulations allow one to evaluate how the reservoir might respond to alternating cycles of injection and

production, with specific reference to the response of the aquifer and the corresponding cyclical movementsof the water table.

6.3.5 Abandoning a fieldA producing hydrocarbon field may consist of severalgeological horizons containing hydrocarbons. If thesehave different hydraulic regimes, they form distinctreservoirs. When a field is put into production, as arule the wells are completed to produce separatelyfrom the different reservoirs. Given the high costs of drilling, wells are generally situated in positions thatallow them to produce, simultaneously or at differenttimes, from more than one level. In the presence of more than one productive horizon, it is common

practice to produce first from the deepest ones. Whenthese are no longer able to ensure an acceptable levelof production (e.g. due to excessive production of water), it may be decided to carry out a workover atthe well. This reduces the amount of water produced

by isolating the area in question, through the injectionof cement or the use of mechanical plugs. If this typeof isolation is not possible, the level in the well isisolated mechanically and thus abandoned, and thewell is then put into production from shallower levels.Obviously, when no further levels are available, thewell is suspended or even closed.

In any case, due to the high cost of closure and theirreversible nature of these operations, it is generally

preferable to keep the wells available for potentialfuture recovery under different conditions, or for monitoring reservoir data. Closure is thus postponed toa future date, when abandonment of the field isinevitable due to the imminent expiry date of the

production lease.However, when the decision to abandon a field is

reached, complete well abandonment must take place.This entails isolating productive levels, securing thewell using appropriate cement plugs inside the casing,

recovering the more superficial part of the casing and cementing the hole up to the surface. After these





operations, a morphological and environmentalrehabilitation must be carried out, restoring the area to

pre-drilling conditions. For offshore reservoirs,rehabilitation also involves dismantling metal platformstructures, to prevent them from obstructingnavigation, and the total removal of any underwater storage tanks, which may corrode and releasedamaging fluids into the marine ecosystem.

Abandonment costsWhen a f ield is discovered, the operating company

generally presents the relevant authorities with adevelopment plan. This sets out in detail all theoperations that it intends to carry out in order to

produce hydrocarbons in an economically viable way.Usually when the development plan is approved, a

production lease is granted, which delineates the area,on the surface and at depth, where the company may

produce. This lease always specifies an expiry date(which can generally be renegotiated as it approaches)and a series of obligations pertaining to the oilcompany. Among these, particular importance is

placed on the obligation to cover all expenditureneeded to secure the wells definitively (wellabandonment), dismantle all surface facilities(wellheads, tubing, treatment plants, etc.) and restorethe environment to its prior condition preceding theexploration and production activities. Given thesignificant impact of this expenditure, the oil company

must predict these costs in its economic calculations

for the development plan. As far as the wellabandonment is concerned, this may also be carried out during the normal productive life of the field aslong as the wells, no longer able to produce, are notused for other purposes (such as observation wells,injection wells, starting points for deviations, etc.).

Bibliography

Aziz K., Settari A. (1979) Petroleum reservoir simulation ,London, Applied Science Publishers.

Baldini G . (1963) Elementi introduttivi alla coltivazione dei giacimenti di idrocarburi , Torino, Libreria EditriceUniversitaria.

Beggs H.D., Brill J.P. (1973) A study of two phase flow ininclined pipes , «Journal of Petroleum Technology », 25,607-617.

Craft B.C., Hawkins M.F . (1959) Applied petroleum reservoir engineering , Englewood Cliffs (NJ), Prentice Hall.

Frick T.C. ( editor in chief ) (1962) Petroleum productionhandbook , New York, McGraw-Hill, 2v.

Petalas N., Aziz K . (1997) A mechanistic model for stabilized multiphase flow in pipes , Stanford (CA), PetroleumEngineering Department, Stanford University.

Turner R.G. et al. (1969) Analysis and pred iction of minimum flow rate for the continuous removal of liquids

from gas wells , «Journal of Petroleum Technology », 21,1475-1482.

Gianfranco Altieri

Scientific Consultant



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Abandon a Field