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Journal of Natural Gas Science and Engineering 6 (2012) 14e23

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Journal of Natural Gas Science and Engineering

journal homepage: www.elsevier .com/locate/ jngse

Invited review

An unconventional mindset for shale gas surface facilities

M. Guarnone a,*, F. Rossi a, E. Negri a, C. Grassi a, D. Genazzi b, R. Zennaro a

a Eni Exploration & Production Division, Via Emilia 1, San Donato Milanese 20097, Italyb Eni Corporate, San Donato Milanese, Italy

a r t i c l e i n f o

Article history:Received 10 November 2011Accepted 19 January 2012Available online 2 March 2012

Keywords:Shale gasSurface facilitiesEngineeringUnconventionalLife-cycle costsLean supply chainSustainable development

* Corresponding author. Tel.: þ39 02 520 61148.E-mail address: [email protected] (M. Gua

1875-5100/$ e see front matter � 2012 Elsevier B.V.doi:10.1016/j.jngse.2012.01.002

a b s t r a c t

Following the “gas revolution” occurring in the USA, where shale gas is contributing to abundant andlow-priced domestic gas production, many companies and countries all around the world are consid-ering investing in this type of gas source. Key elements of shale gas production include the extensivedrilling campaign, the need for hydraulic fracturing (with its implication on the whole water supply/handling cycle) and the realisation of a continuously growing network of geographically scatteredproduction facilities and flowlines, which accompany gas from wellheads to the final customers.

Exporting shale gas experience from the USA to new promising basins will not simply mean cus-tomising subsurface technologies (such as drilling & completion or hydraulic fracturing) to a geologicallydifferent area; it will especially imply adopting an unconventional mindset for surface facilities. First ofall, there may not be a context as fertile as in the USA in terms of existing infrastructures (pipelines,treatment plants) or abundance of local contractors/providers, therefore an efficient engineering andfast-response procurement and construction chain will be more crucial for life-cycle-cost minimizationthan it is for conventional gas production.

Moreover, standardized and repeatable production facilities will likely be the most economically viableway to handle gas flow from hundreds or thousands of wells, designed in parallel with step-by-stepterritorial studies to locate those facilities considering geographical, infrastructural and legislativeconstraints and opportunities. Finally, the passage from exploration to extensive commercial productionwill likely require a proper appraisal campaign through a pilot development, especially in new areas,with the objective to “long-test” shale gas wells performances and optimize full-developmentapproaches in an environmentally friendly way.

� 2012 Elsevier B.V. All rights reserved.

1. Introduction

1.1. Shale gas: what’s and why?

Geologists in the oil & gas sector have always looked at gasshales mainly as the source rocks fromwhich hydrocarbons migrateand accumulate into geological structures. Conventional reservoirs,indeed, are being exploited economically provided that sufficienthydrocarbon volume is trapped by the cap rocks and thata sustainable number of wells can be drilled to efficiently drain thatvolume. Gas shales, instead, act at the same time as source, reservoirand trap.

A shale formation is a sedimentary rock composed of fine-grained detrital mineral (silt-size particles of quartz and calcite)and flakes of clay and it is characterised by the presence of about 1%

rnone).

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to over 20% of Total Organic Carbon content (TOC). The amount,type, and thermal maturity of this organic matter determine thetype and quantity of hydrocarbon in place, with gas contentincreasing with TOC. Usually shale formations have very lowhorizontal permeability and negligible vertical permeability, typi-cally in the order of 10�2 to 10�4 md in thematrix, whichmean thatgas is trapped and cannot move easily within the rock itself.

This type of hydrocarbon is currently contributing to about 25%of domestic gas production in the USA after a production boom thattook place in very few years; moreover its share in the energy mix,as shown in Fig. 1, is predicted to continue growing (Annual EnergyOutlook, 2011).

Shale gas also becomes a topic of interest for mass media,defined as a game changer, with tangible effects on the energymarkets fundamentals not only in the USA but generally in theAtlantic basin: it certainly played a role in the drop of Henry Hubgas prices, downmore than 40% in the last 2 years while WTI crudeprice remained in the 80O 100 US$ region during the same period(CME Group,).

Fig. 1. US EIA Annual Energy Outlook (2011) (TCF/year).

Fig. 2. Statistical variability of decline curves.

M. Guarnone et al. / Journal of Natural Gas Science and Engineering 6 (2012) 14e23 15

It is therefore interesting to understand which drivers led to therevolution that, in less than a decade, transformed gas shales intoa direct supply of abundant and commercially competitive shalegas, inducing many oil & gas companies and investors to switchtheir attention to the so-called unconventional resources.

The key solutions to unlock shale gas value are all aimed atcounterbalancing the low permeability of shales: the wells shouldbe drilled horizontally to maximise well/reservoir contact surfaceand drainage area and they should also be stimulated to increasethe productivity of the shale, which is extensively done byhydraulically fracturing the rocks. Both technologies e horizontaldrilling and hydraulic fracturing e have been applied for more thantwo decades to allow commercial gas production from coal seamsand tight reservoirs, but only in the recent years a significantlearning curve has been experienced in drilling and completingshale gas wells: in the Barnett shales (USA, Texas), during the last5e10 years, drilling speed has more than doubled and D&C costshave been halved.

These improvements, however, are not sufficient to explain themagnitude of the shale gas phenomenon: its underpinningopportunities along with its peculiar challenges have to be foundthroughout the value chain, including the world of productionfacilities. The following review will provide some technical andcontextual highlights from the point of view of an oil & gas oper-ator, starting from a number of key subsurface aspects that influ-ence surface facilities.

1.2. Subsurface challenges

When explorationists look for shale gas outside of alreadyproducing shale gas basins, e.g. outside of Northern America, theyoften face the difficulty that well data resolution is large or verylarge; for such reason the normal approach (quantification of welldata only) is not sufficient to describe properly the propertiesdistribution. The extrapolation of well data to the entire prospectextension can be successfully supported by a Petroleum SystemModelling (PSM), i.e. the numerical simulation of the naturalprocesses governing the properties distribution over vast areas(thousands of square miles). The outcome of a PSM typically is theidentification of a so-called “sweet spot” characterised by the mostfavourable shale properties: maps of depth, thickness, organiccontent, maturity and brittleness are compared against each otherand one or more optimum areas are selected for further studies orexploration.

Here we have the first example where an unconventional andmulti-disciplinary mindset is required. In many cases, indeed,geographically identifying the perspective “sweet spot” for

exploration/pilot wells based only on geological and reservoirparameters (as resulting from a PSM approach) may lead toundesirable situations: gas can be produced efficiently but thenthere may not be enough infrastructures in the area to economi-cally transport it to the customers, or there may be an unacceptableimpact by production sites on communities, flora and fauna.

When evaluating a new area, once the sweet spot has beenidentified, a key-step in the workflow of an oil & gas operator is, onone side, the evaluation of a preliminary drilling & completionprofile and, on the other side, the estimation of the most likelyproduction decline curves for a single well.

As already mentioned, horizontal drilling is a must tocommercially produce from low permeability shales; importantcost savings are obtained by increasing the horizontal length (up toabout 10 000 ft) and by deviating wellbore profiles allowing clus-tering of wellheads and D&C operations (“wellpad approach”).Moreover, fracturing has to be performed, which means to isolatesections of the well in the producing zone, then to pump fluids andproppant down into the wellbore through perforations in thecasing and out into the shale. In the deeper high-pressure shale, it iscommon to pump slickwater (a low-viscosity water-based fluid)with proppant. Ideally, a higher number of hydraulic fracturescorrespond to more gas produced. However, a balance between thenumber of fractures and the costs of these treatments must befound, in order to achieve the optimal number of frac jobs to beperformed by well.

Gas in shale formations can be either adsorbed on organicmatter and mineral surfaces or occur as free gas in pores andnatural fractures. Adsorbed gas is released only at a later stagewhen formation pressure declines; its quantities vary significantlyfrom one shale to another, contributing to the statistical variabilityobserved in the proven basins. The gas in pores and fractures,instead, is produced immediately (migrating by Darcy flow) andrepresents the dominatingmechanism at the initial phase of a shalegas well, but, due to the limited storage capacity of the fractures,the initial rate typically declines steeply. In general, gas shale wellshave a high initial production rates followed by a steep decline ofthe initial production (70%e90%) within few years (see Fig. 2).

Depletion rates are very important to identify because they willdetermine how long each well will produce in order to pay off thecost of thewell and the associated surface facilities. A variety of wellproduction decline curve models for the various shale plays havebeen published in the literature that contemporaneously take intoaccount the presence of both free and desorbed gas. Shale gasoperators use combinations of the decline curves determined byArps in 1945, to fit the single-well production data, but there isa high degree of uncertainty and unknown in predicting both InitialProduction (IP) and Estimated Ultimate Recovery (EUR) for a shalegas well, with risk of over-estimating production performances(Baihly et al., 2010).

M. Guarnone et al. / Journal of Natural Gas Science and Engineering 6 (2012) 14e2316

2. From shale gas wellheads to customers

2.1. Clustered wellheads and production equipment

Typically, a wellpad can accommodate from 4 up to 10 wells.Recently, the tendency is to increase the number of wells perwellpad, in order to reduce the impact on the environment byreducing the number of wellpads. As reference, a minimum of 8wells is considered for a typical design of a wellpad.

In addition to the wellheads, the wellpad accommodates thegas-liquids separators, one for each well, and the produced watertanks, as shown in Fig. 3. In case of presence of condensates in thegas stream, these are separated from the gas and the water streamsin the separators and stored in dedicated tanks.

Produced water is then loaded on trucks and moved to centraltreatment facilities for re-injection or re-use (see Section 2.3). Allthe utilities required by thewellpad facilities must be present in thewellpad design if not already available in the vicinity.

A typical wellpad layout is characterised by a large unusedspace, with the wellheads in the middle and the production facil-ities located on a side. This because the space required by thedrilling rig and by the fracturing operations is much larger than thatrequired by the equipments and these operations are leading theexecution schedule, therefore are usually carried out with theproduction facilities already installed. In addition, free space mustbe foreseen around the wellheads for possible wells workoveroperations.

In addition to the above process and utility facilities, a wellpadcould be provided with lift gas facilities. As water production couldbe very high especially in the first months of production, lift gas isrequired in order to increase the gas production or, in some cases, torestart it after a well has been stopped and then flooded withliquids.

Lift gas system is essentially composed by a multi-stage inter-refrigerated reciprocating gas compressor installed directly withinthe wellpad fence. As it is required for the first months ofproduction, it is usually a rented machine which is removed once itis no longer required.

In a well-designed full-field development configuration, lift gasproduction can be centralised. Lift gas compression facilities arepermanently installed into the hub and properly designed to

Fig. 3. Wellpad production separators and water tanks.

accommodate the lift gas profile required by the whole field.Typically, a modular and expandable design should be foreseen.

Similarly, produced water, after a minimal treatment for solidsand sand removal, can be pumped to a central water treatment hubby means of pipelines, in order to minimise trucks operations,which are far more expensive and less environmentally friendlythan using water pipelines.

Sand management is another important issue: sand is used asproppant for hydraulic fractures, but some of it inevitably returnsback during gas production. Gas separators should be equippedupstream with sand-removal devices and internally with sand-cleaning tools, in order to prevent and avoid possible obstruc-tions due to deposits of sand.

2.2. Gathering networks and treatment plants

The very high number of wells and wellpads characterisingshale gas developments is directly inducing a multi-phasedproduction profile with very long ramp-up period. This is due tothe fact that all the wells and wellpads cannot be put intoproduction all together, as drilling operations continue for thewhole field life and they are required to maintain the productionplateau.

The resulting production profile could look like as in Fig. 4, witha very gradual ramp-up (lasting typically many years) and a plateaumaintained only if new wells are continuously drilled and put inproduction.

The gas produced by all the wellpads has to be collected andbrought to a central treatment plant, or hub. In the central hub gasis treated up to export/marketing grid specifications. When it is dryand sweet the treatment process is limited to a conventionaldehydration preceded and/or followed by gas compression;different quality of feedgas may require gas sweetening and/orNatural Gas Liquids (NGL) extraction. In addition, produced waterhas to be routed to a treatment plant for re-injection or re-use.Furthermore, lift gas must be compressed and sent back from thehub to each wellpad as required by the producing phase.

As the typical pressure profile of a well sees a rapid decreasesoon after the first months of production, the gas gatheringnetwork has to be designed for low operating pressures, namelyabout 5 bar. This parameter is strongly influencing the overallproduction of the field, especially after the first years of production,as an increase of the gathering network operating pressure (e.g.determined by newwells being tied-in) causes a certain number ofolder wells, producing at low pressure, to be abandoned. On thecontrary, keeping a low operating pressure in the gatheringnetwork allows having a higher production rate for a longer period.As a drawback, this requires more compression power in the huband larger pipelines diameters.

Fig. 4. From single well to field production forecast (Guarnone et al., 2010).


The presence and the development level of the midstreamgathering & transport network is one of the necessary conditionsfor a successful development of a shale gas asset. As amatter of fact,the construction of a long pipeline to connect the hubwith a distantgas network has a strong impact on the economic sustainability ofthe initiative, as a high CAPEX would be required in the very firstyears when the production is quite low, as discussed above.

In the US, this condition was one of the most important enablerof the “shale gas revolution”, being the national gas network verywell developed, as can be observed in Fig. 5.

This leads to important consequences for the central treat-ment hub.

Primarily, the plant has to be designed taking into account thecapability to be expanded in a modular way in order to “follow” thelong ramp-up period.

Secondly, even once the plateau is reached, this is characterisedby feedgas flowrate fluctuations due to the continuous drillingoperations required to sustain the plateau. This drilling activitiesrequires the shut-down of the entire wellpads in which theimpacted well is located and sometimes also the nearby wellpadsare stopped to avoid interferences between the fracking and theproduction of the wells in the vicinity.

For this reason the central treatment hub should be designed asmade up of several trains, especially for those equipments moreimpacted by variations in gas flowrates.

A strong interaction between surface facilities engineering anddrilling & completion activities is mandatory in order to minimiseproduction fluctuations.

2.3. Flowback and produced water treatment

Water management issues are associated to every stage ofshale gas development and can impact operator’s costs, environ-mental sustainability and public acceptance. Covering the wholewater cycle, the first crucial step is fresh water supply from publicor private sources, which may be subject to restriction in certainareas. Then, water is typically stored in above ground ponds witha capacity that varies from 100 000 to 1 000 000 bbls or more and

Fig. 5. Extensive gas treatment and transp

depth from 10 to 25 ft. Water usage in shale gas industry is rep-resented by drilling and fracturing activities (respectively 10% and90% of total demand). During a fracking job, about 10 000 bbls perstage are required, so a typical well of 6000 ft of horizontal lengthwith 15 stages implies a water volume close to 150 000 bbls.Considering that a fracking crew is able to perform 3 stages perday, the water demand is close to 30 000 bbls per day, obtained byquickly draining the above mentioned water pond(s). This is thereason why, in many cases, a network to link different ponds is setup in order to create a significant water buffer; this ensures thatthe required amount of water supply does not exceed maximumwater wells withdrawal capacity. In the last phase of water cycle,once a wellpad has been drilled and completed, wells are put inproduction by means of dedicated temporary facilities with robustwater and sand separation systems: this operation, often con-ducted by service companies, is called “flowback phase” andusually lasts approximately 2e4 weeks after start-up for a typicalwellpad; in the mean time permanent production equipment isinstalled and put into service as a second separation stage,allowing commercial export of gas. Water rate from each well,during flowback phase, is considerable, since it can be as high as3 000 bbls per day in case of a 6 000 ft horizontal drain, but itdrops dramatically and after few weeks reaches values in theorder of 1000O1500 bbls per day that can be handled by the solepermanent production equipment. From that moment, water isstored inwater tanks and exported fromwellpads either by trucksor by export pipelines.

Before addressing unconventional aspects of water treatmentfacilities in shale gas business, some non-exhaustive but indicativehighlights are provided on flowback/produced water composition.

Fracturing water typically consists of about 98O 99% water andsand, and 1 O 2% chemical additives, blended on-site just beforepumping fluids into wells in order to enhance and optimize thefluid dynamics while preserving well and reservoir formationintegrity. The resulting flowback and produced water still containsmany chemical substances in addition to the dissolved salts andchlorides (TDS e Total Dissolved Solids) and to the entrained sand/proppant particles (TSS e total suspended solids).

ort network in the USA (US EIA DoE).


The characterisation of such water is crucial to define the propertreatment/handling solutions, but it is difficult to be conducted forseveral reasons. Firstly, a big statistical variance is associated towater quality when looking at different wells even in close prox-imity, reflecting complex interactions between fracturing fluids andshale rocks. Secondly, service companies only recently haveincreased the transparency on fracturing water chemical additivesand intellectual properties on their receipts still hinder the fulldisclosure of the exact composition of the various substancesblended in the fracturing fluids.

Governments and regulatory bodies also outside USA are look-ing at this complex topic and they are increasingly worried aboutthe consequences of extensive use of fracturing fluids projected forpromising shale gas basins. The European Commission, forinstance, identified a list of 260 substances provided by the NewYork State, out of which 58 have one or more properties that maygive rise to concern: in particular, substances such as Acrylamide,Benzene, Ethylbenzene, Isopropylbenzene, Naphthalene, Tetraso-dium Ethylenediaminetetraacetate, Hydroxylamine hydrochlorideare classified as priority potential hazards, some of them beingtoxic, carcinogens, bioaccumulative (European Parliament, 2011).

It is important to note that such components are present at verylow concentration in the flowback/produced water and that mostare already well known in other industrial sectors, being used forinstance in the cosmetics, in the food or in the household/deter-gents industry (US Department of Energy and National EnergyTechnology Laboratory, 2009). This is positive, on one side, but, atthe same time, represents a challenge for the upstream oil & gasindustry, typically not used to handling such components.

Shale gas produced water in the U.S. is generally disposedthrough under-ground injection and/or treatment for release or re-use. Under-ground injection through disposal wells is the preferreddisposal method: in this way, only a basic filtration and suspendedsolids settlement is foreseen in order to protect injection equip-ment, wellbore and formation from solids erosion/entrappement.Public concerns about the amount of water used for shale gasoperations, coupled with the lack of adequate large scale disposalcapacity, have caused some operators to explore treating and/or re-using the produced water.

Depending on the final use, produced water may be treated fordischarge to surface waters or it may be treated and re-used insubsequent fracture operations. Looking at the overall watertreatment process, it could be easily divided into two mainsections.

The first can be called “pre-treatment” and comprises all theprocesses necessary in order to reduce TSS and heavy metals. This

Fig. 6. Possible scheme of a repeatable “complex

goal can be achieved by means of different technologies such ashydrocyclone separation, electrocoagulation, flocculation, resinsadsorption and softening that properly combined together allowreaching the desired output in terms of water specifications.

The next step, the “core-treatment”, is to reduce TDS andchlorides, which can be performed by following two different waysdepending on the specific water features. For inlet TDS value closeor lower than 30 000e40 000 ppm, physical separation seems to bethe most technically and economically feasible option, with proventechnologies such as ultra-filtration, nano-filtration and reverseosmosis: these ensure the achievement of treatment targets withrelatively low costs, CAPEX and OPEX typically being in the range1.5e3 US$/bbl in Northern America contexts. For higher inletTDS value, instead, thermal technologies (namely mechanicalevaporators and crystallizers) are candidate to provide higherefficiencies and recovery factors (more than double compared toa physical process, e.g. reverse osmosis) but they imply final costsinternally estimated to be as high as 3e6 US$/bbl for the fullwater treatment cycle in Northern America contexts.

3. An unconventional mindset to unlock shale value

3.1. Modelling multi-asset facilities

When planning a shale gas development with several tens tohundreds of wells, a modular facilities approach is recommended,meaning that a few “building blocks” can be designed and usedrepeatedly. This well-used US philosophy demonstrated severalbenefits, including:

B avoiding continuous rework to design new customised instal-lations for new productions;

B simplifying procurement of goods and services, enablingsignificant cost savings;

B speeding the permitting process, since stakeholders becomefamiliar with the facilities.

Modularisation can be applied at both plant and field level. Plantlevel design approaches have been already mentioned in Section2.1 and 2.2. At the field level, the “building blocks” are essentiallythe well cluster facilities (or wellpads), the connecting pipelinesand the treatment plants. Starting from the experience gained incollaboration with Quicksilver in the Barnett shale, typical fieldlevel modularisations are being studied, such as the exampleshown on the left in Fig. 6, which is hereafter referred to asa “complex”.

” (left) and “multi-complex” scenario (right).

Fig. 7. Aerial view of irregular wellpads distribution in Louisiana (eni source).


A “complex” is composed of a number of wellpads (20 in thiscase, each collecting production from 8 wells, represented in black)that send effluents to a treatment hub by means of pipelines (heretwo types, in blue and violet colour depending on the expectedmaximum flowrates). If a reasonable spacing of about 4 horizontalwells per square mile is assumed, the described “complex” wouldtheoretically drain an area of about 40 mi2 (w100 km2) with 160wells. Broader developments can be based on a sequential real-isation of multiple “complexes”, as depicted on the right side of leftin Fig. 6; in such situation it is likely that only one of the treatmenthub performs the complete gas treatment up to commercial gridspecification, the other hubs being simpler satellites for gasboosting and water handling.

An example of the unconventional challenges related to suchschemes can be summarised within a simple question: what is theoptimum number of wellpads that can be connected to a singletreatment hub? Two extremes have to be avoided:

B too few wellpads per “complex” would not justify a dedicatedcentral plant, since lack of economies of scale generate higherspecific gas costs;

B too many wellpads per “complex”would mean longer paths ofgas from the wellheads to the plant, up to a point where gasboosting and/or higher diameter pipelines become mandatoryfor the most peripheral wellpads, again generating higherspecific costs.

When modelling multi-asset systems such as shale gas ones, anunconventional mindset should be applied especially on theupstream installations and on the gathering network, with criteriathat could be in contrast with those usually applied in conventionaloil & gas plants.

For instance, as the whole full-field gas production is theresulting production of hundreds of wellpads, it is extremelyimportant that a wellpad is designed with the objective to reduceits costs to the minimum, as a non-optimized design would berepeated hundreds of times. On the other hand, from an overall-production point of view, it could be acceptable to temporarilyloose the production of onewellpad, as this couldminimally impactthe field production. For this reasons, wellpad critical equipmentsare never spared nor overdesigned in order to reduce the costs,leading to an extremely simplified and “low-cost” design.

Another example of unconventional aspect is the fact that gas,water and utilities lines should be properly designed since earlystages and they should be able to be expanded during the projectlife in order to accommodate a gradually increasing production ofthe field and at the same time to assure a full availability of gassupply to the plant. For these pipelines, operating at low pressure,as well as for water pipelines, which contain a non-hazardous fluid,the use of special plastic materials should be investigated, with theaim to reduce the costs and to ease the installation, with a savingfor the schedule.

As a final consideration on surface developments, it is stressedthat passing from conceptual design phase to real application oftenimplies significant deviations from the theoretical and geometricalmodels initially conceived. Deviations from early plans often occurin normal oil and gas initiatives, but they are inherently morefrequent in shale gas developments, since:

B heterogeneity among wells and productive areas can be quitehigh,

B drilling campaigns and continuous infilling projects covera much longer period than for conventional developments,therefore long term planning is necessarily quite generic andflexible, leaving room for year-by-year adjustments

It happens, as an example, that wellpads have to be distributedquite irregularly over a certain territory in order to respect urban-istic or geographic constraints, as depicted in Fig. 7.

3.2. Life-cycle costs and uncertainty management

Shale gas production is an attractive business for oil & gasoperators as soon as there is confidence that gas can be producedcommercially and in a sustainable way in a certain region; this,however, may pass through a first period with initially low profits/margins, reflecting an early effort to establish a gathering andtreatment system, a local operating structure (affiliate or similar)and an effective relationship with all stakeholders.

It is therefore evident that cost estimation plays a key role sinceearly evaluations of new shale gas opportunities, because itsupports the economic evaluation and approval process foracquiring or not an exploration permit or a stake in a promisingbasin.

At the same time, however, the costs structure of a shale gasdevelopment is substantially different from conventional produc-tion, which makes quite difficult the task of cost estimation.

Firstly, drilling & completion activities, along with surfacefacilities installations, are spread over many years, in order tocontinue increasing (initially) and maintaining (at later stage) theannual production target. As a consequence the CAPEX, that wouldbe typically concentrated in few years after FID of a conventionaldevelopment, are in this case more similar to OPEX (Cingolani,2010). But estimating significant OPEX-like investments requiresa sufficiently accurate prediction of the time when they will berequired, which in turns depends on:

B the prediction of Decline Analysis Curves to model single wellsand overall field performance;

B the external variables affecting investment decisions, such asprice scenarios, costs framework, competing business oppor-tunities, again uncertain to forecast on a long time-frame.

Secondly, as already mentioned above, shale gas production isessentially a repetitive business, therefore it presents huge poten-tial for continuous improvements onmany fronts, including surfacefacilities. Such effect can be taken into account in the cost estimateexercises by applying learning curves that progressively reducespecific costs (e.g. of a wellhead separator) with a predefined rule.Learning curves for surface facilities are difficult to estimate, butneglecting them at all would imply an excessively conservative

FIRST 3-YEARS COSTS

Drilling

Frac &

Compl

Gas

Transport

to Market

Upstream

Gathering &

Treatment

Wellpad

Facilities

FULL LIFE COSTS

Drilling

Frac &

Compl

Wellpad

Facilities

Upstream

Gathering &

Treatment

Gas

Transport to

Market

Fig. 8. Indicative costs breakdown of a shale gas initiative (eni source).

Table 1Example of uncertainty in cost estimate (eni source).

Annual absolute expenses for water management (MMUS$)

1.5 US$/bbl 3.0 US$/bbl 6.0 US$/bbl

5000 bbld 3 5 1115 000 bbld 8 16 3325 000 bbld 14 27 55

1 Design-to-Cost is an approach where design goals are constrained by availablefunds; in other words, investments become an independent variable used as inputdata rather than being a dependent outcome of a design phase.

2 Business tool to evaluate the Strengths, Weaknesses, Opportunities and Threatsof a series of alternatives.


approach. Aspects to be taken into account as drivers for learningeffects include the following:

B contingency reduction on investments, due to increasinglyhigher confidence in repeatable facilities and geographicalproximity of subsequent installations;

B procurement costs savings due to increasingly more optimizedcontracting strategies and due to the increasingly higherprocurement volume;

B costs reduction due to lessons learned, minimization of over-design and removal of bottlenecks.

The above considerations imply the need of flexible cost esti-mating tools that enable a quick evaluation of threats and oppor-tunities for fast-response of decision makers. It is also important tohave an immediate picture of the most impacting cost items, andthis can be communicated in differentways depending on the time-frame object of the analysis.

Fig. 8 shows an indicative example of costs analyzed for a shalegas initiative by allocating common infrastructures costs propor-tionally to single wells. It appears that subsurface costs arepredominant when looking at a short time-frame, until the 3rd yearafter start-up, while investment and operating costs for wellpadfacilities and for treatment/transport systems become moreimportant when looking at the full life of each single well.

It is a common believe that shale gas business has little explo-ration risk compared to conventional gas accumulation. It is morecorrect to say, however, that the risk moves to the commercialproducibility of gas that depends on the costs versus prices posi-tioning. Costs, in turn, depend on many technical uncertainties,inducing project teams to make assumptions, e.g. on predictingflowing pressures, presence of contaminants in gas, associatedwater flowrate/composition, etc. As an example, Table 1 shows theannual expense of water treatment that would be generated byvarious indicative field water rate values and by applying differentspecific water treatment costs reflecting the spectrum of technol-ogies depicted in Section 2.3. From a cost prediction point of view, itis evident that the combination of uncertainty both on waterquantities and on the effective treatment strategy could result inannual water costs varying by more than an order of magnitudefrom the cheapest to the most expensive situation.

The final remark on this matter is therefore the need for a costanalysis throughout the project life, that has to be quickly set up atearly stages of business opportunities and that has to be tunedaccording to actual costs once reaching the commercial productionstages. Such analysis should incorporate the management ofuncertainties typically encountered in shale gas projects.

3.3. Fast and cost-effective supply chain

The exploitation of unconventional reserves needs specifictechniques to be implemented and this affects the whole processfrom exploration to final gas customers, including supply chainmanagement & procurement as well.

Economic performances of a Shale Gas development Project canbe positive only if Design-to-Cost methodology1 is extensivelyapplied to the integrated cycle of activities, without compromisingon safety or on business sustainability, and this principle has a highimpact on the planning and performance of the procurementactivities.

Such strategic target can be achieved both by a large standard-ization (Mancini et al., 2011), simplification and achievement ofsynergy for each sub-portion of scope and by project activity withinthe integrated cycle including procurement/supply chainmanagement.

It is important that Procurement is involved from the beginningin the definition of the development strategy, in order to start assoon as possible the scouting of the market of suppliers of goodsand services, with an extensive use of market intelligence tools: inthis way, especially when entering an area with not yet establishedoil & gas industry, it is possible to know the alternatives proposedby the market, in terms of contract strategy (EPC, Service or mixedstrategy) and compensation mechanism (purchase, rental or lease)to assess project’s economics. The alternatives will be assessed inan SWOT analysis2 to select the most suitable for the specificdevelopment scenario.

The process should be implemented in an earlier stage comparedto the “traditional” field development strategy. The procurementapproach to pilot project aims at the full-development scenario as


a target, so early stages scouted alternatives should be assessed toachieve the full scale development scenario in the most effectiveand efficient way.

The process is phased in different steps to gradually go intomore detailed assessment of the market and vendors available tofulfil project development strategy, as shown in Fig. 9.

Strong integration with the project team and local branches willhelp to have a smooth process during execution phase. Further-more the knowledge of the suppliers’ market acquired in an earlystage of the project will help the development phase to have a fastreply from vendors.

Contractual tools to be implemented shall also be tuned andaddressed to achieve the unconventional aspects of a shale gasdevelopment, in particular decisional and operational flexibility,financial exposure minimization and fast reply from Vendors.From this point of view, shale gas business is more similar tomanufacturing business.

A key example is the wellhead gas-liquids production separator,which has to be ordered and fabricated hundreds of times fora multitude of wells, and then installed regularly, following thestringent wellpad start-up schedule. But the same concept isapplicable for example to the wellheads, their control panels, etc.The production of such equipment would be too long and tooexpensive if based on a dedicated job order every time there isa new well to be tied-in. On the contrary, the best condition wouldbe the establishment of a continuous production at amanufacturingworkshop, possibly not far from installation sites, in order tominimise the time-to-market and catch the opportunities ofa flexible business. In other words, the so-called lean productionconcepts should be applied to reduce production costs and time-to-market (Cassidy, 2010).

The focus should be on Open Book Contracts, Multi ServiceContracts with short tender activation process and, where appli-cable, Framework Agreements andMaster Service Agreements. Keytools to be included could be incentive mechanisms based on KPIand demand planning/forecast tools to improve performance andachieve cost saving.

Vendor pre-qualification requirements should also be alignedwith new requirements in order to allow standardization andcompetition among vendors. This will facilitate the implementa-tion of the contractual tools described above.

Shale gas can lead the market to develop new business model.Furthermore the development strategy is phased and modular,adjustable during the progress of the field. This means thatProcurement will have an active and continuous role to achievecost optimization, as shown in Fig. 10.

The market analysis process should be an active and liveprocess, in order to capture any major change and new opportunityarising from new business model that can be assessed to achievecosts optimization. This can be the result of changing the “mix” ofproviders/vendors, changing remuneration principle (rental/lease/purchase) and different level of integration of the supply chain.

Fig. 9. Procurement

3.4. Territorial analysis for facilities design

The exploitation of shale gas has a considerable surface impact,especially given the large number and frequency of wellpadsrequired for production. In populated areas, limitations stem notonly from the physical (such as land-use, hydrography, hydrology,morphology and climate) and environmental characteristics of thearea (such as the presence of protected, sensitive or valuable areas)but are also linked to the presence of human settlements andactivities.

The analysis of spatial data plays a key role in planning activitiesfor the exploitation of shale gas. A careful study of the elements thatcharacterise the area prevents unwanted complications and facili-tates the development of operational activities. To this end, as ofearly stages of project design, it is necessary to acquire spatial datawhich, when cross-referenced with the project, enable a timelyidentification of needs and criticalities.

Topographic maps, satellite images, thematic maps and vectordata feed into a Geographic Information System (GIS) whichsupports spatial analyses and the development of maps high-lighting needs and criticalities. In populated areas, indices ofurbanization, distinguishing among isolated dwellings, urbanconglomerations and densely urbanized areas, are carefullyassessed, creating a buffer indexed according to the differenttypologies found.

Shale-gas operations involve a massive use of water, thereforerendering important to investigate the presence and availability ofwater in mining areas. Limits imposed by local legislation, and bynational and international standards, as well as those internallyestablished by the company, are included into the analysis. Theposition of protected areas also significantly affects the finalevaluation.

The integrated analysis of these parameters allows for theidentification of those areas potentially suitable to host the projectinfrastructures.

A second phase of the analysis includes completing the locali-zation on the basis of engineering and logistics criteria such asinterfacewith the existing gas grid and distance to customers, road-traffic system and the electricity network.

The analysis is concluded with a possible on-site field surveythat confirms and elaborates the considerations arrived at throughthe GIS analysis. During the survey a team of engineers, geologists,agronomists, and cartographers evaluates the areas’ characteristicsbearing in mind project technical requirements regarding alloca-tion of wells and gas transmission infrastructure. Preliminaryinformation concerning the availability and cost of potentiallyinteresting portions of the territory are acquired during the survey.The use of local mediators with the support of technical expertscertainly facilitates the final land acquisition negotiations.

The result is a number/series, albeit limited, of configurationsthat meet the requirements of efficiency and sustainability, such asillustrated in an example of wellpad location in Fig. 11.

process outline.

Fig. 10. Procurement and costs optimization.


3.5. “Exploration Extended Engineering”

The above considerations bring to the conclusion that one of themost unconventional aspects of shale gas business, from an oil &gas operator point of view, is the need for a very different workflow,impacting on surface facilities design approach.

A new shale gas exploration initiative, in order to be progressed,needs early contributions of reservoir, drilling/completion anddevelopment/facilities people, so that a candidate “sweet spot” canbe identified for exploration pilot wells.

Once this is fixed, development engineers can start working onthe feasibility of a production pilot phase, to be realized as soon asexploration pilots provide good results; objectives of the pilotphase are multiple, including the following:

B understand the productive potential of the geological forma-tions (confidence on geological risk)

B acquire technical and operational know-how, in terms ofgeology, reservoir, drilling and facilities

B initiate the learning curve and lowering costs for thedevelopment

Fig. 11. Example of wellpad location identification (eni source).

B gain experience in all commercial aspects relative to theterritory

B study the territory and the reactions of stakeholders andinhabitants in the area

B set up a sound internal organizational structure

Operation would then take over the management of the firstproducing assets, but their role is also to provide important feed-back to exploration and development people, whose work, indeed,does not end with the first gas. On the contrary, all sectors of an oil& gas company, when dealing with a shale gas initiative, have tocontinueworking in parallel on the same play area for several years,as schematized in Fig. 12.

The workflow of a shale gas project can be summarised by theconcept of “Exploration Extended Engineering”, where all decisionsare taken by an integrated multi-disciplinary team of geologists,engineers and commercial experts, all aware of the challenges andopportunities not only of their own discipline but also of theothers’.

Surface facilities design, in terms of global transport and treat-ment sizing and scheduling, has to be aligned as early as possiblewith field production profiles, drilling campaign schedule and gasproduction/marketing profiles. Only in such way the overall projectefficiency can be guaranteed (Fig. 13).

ENG

EXPLO

OPERATION

EXPLO

ENGINEERING

OPERATION

Sweet spot Upside area 1

EXPLO

OP

Upside area 2

Pilot prod TIME

ENGINEERING

Fig. 12. “Exploration Extended Engineering”.

Fig. 13. Surface facilities: part of an integrated workflow.


4. Concluding remarks

Shale gas phenomenon has revealed its solid basis in NorthAmerica, being expected to account for the majority of the growthin natural gas supply in this region, namelymore than 50 percent ofthe supply portfolio by 2030 (Annual Energy Outlook, 2011).

The US experience in particular is suggesting that a shale gasdevelopment has to be approached with an unconventional mindsetleveraging on a series of key-concepts:

B multi-disciplinary integrationB gradual expansionB wells tie-in phasing optimizationB modularityB design-to-costB standardizationB supply chain efficiencyB operating experience

Nevertheless translating these concepts into a model to betransferred to rest of the world it is not so straightforward. Asa consequence of the current tight energy market scenarios,extraordinarily high project efficiency is everywhere required. Thisgoal is achieved by creating a network of skilled resources, workingwith an integrated multi-disciplinary approach dynamicallyoriented to the common target of maximising the overall projectprofitability, without compromising on personnel safety, environ-mental protection and stakeholder value assurance. Unconven-tional aspects are, in fact, not limited to the “subsurface” challengesbut dramatically impact on the “surface” developments. Facilitiesmodularity and phasing through appropriate design standardiza-tion, strong interaction between surface facilities engineering andD&C schedule, sharing of the existing local infrastructures andresources, like treatment & transport ones, are only few examplesof project efficiency.

When applying these concepts, a new unconventional mindsetis required which asks for an early involvement, since the explo-ration stage, of the project development and engineering.

This helps to catch since the beginning the right synergiesbetween subsurface with the surface facilities development fora profitable shale gas project. It may happen that the identification

of a sweet spot could be penalized in its development by territorialconstraints (physical, environmental, anthropological or by limitedaccess to the local infrastructures). Much of the engineering activitycould identify at early stage possible issues through the involve-ments of disciplines like system integration, procurement, territo-rial analysis as well as domestic & regional market analysis. The useof an integrated model capable to represent from a technical andeconomical standpoint the whole development phases (Pilot, Earlyand Full production) could be of outmost importance to identify thekey investment decision making metrics.

Leveraging on Northern America experience, when startinga new shale gas development, especially in a new play, an initialPilot Phase, starting from the sweet spot is very important to gaina better understanding not only on subsurface aspects (geology,reservoir, drilling & completion) but to gain operational and orga-nizational know-how as well as a sustainable relationship withstakeholders. Moreover the Pilot phasemay also provide solution toone of the main issue related to shale gas industry: the watermanagement. It could be of outmost importance to validate at pilotscale economic solutions to potentially recycle flowback water andreduce its environmental impact, even optimizing fracking job.

The concept of sustainable unconventional play development,aimed at reaping the maximum resources in a given acreage, can besummarised as a triple E or “Exploration Extended Engineering”process, where all decisions are taken by the integrated asset team,from project inception to abandonment, with the goal of max-imising project returns in a low margin environment.

Acronyms

CAPEX Capital ExpenditureD&C Drilling & CompletionEoI Expression of InterestEPC Engineering, Procurement & ConstructionFID Final Investment DecisionGIS Geographic Information SystemKPI Key Performance IndicatorsOPEX Operating ExpenditurePSM Petroleum System ModellingSWOT Strengths, Weaknesses, Opportunities & ThreatsTDS Total Dissolved SolidsTSS Total Suspended SolidsUSA United States of America

References

Annual Energy Outlook, 2011. US Energy Information Agency.Baihly, et al., Sept. 2010. Shale Gas Production Decline Trend Comparison over Time

and Basins. SPE 135555.Cassidy, D., et al., 2010. Unconventional Gas Projects: Big Gains from Lean Supply

Chains. Booz & Company Inc.Cingolani, E., eni e&p, Sept. 2010. Realizing Margins in European Shale Gas. Global

Shale Gas Forum, Berlin.CME Group, Energy Products Homepage. Available at: http://www.cmegroup.com.European Parliament, June 2011. Impacts of Shale Gas and Shale Oil Extraction on

the Environment and on Human Health, IP/A/ENVI/ST/2011-07 PE 464.425.Guarnone, M., Ciuca, A., Reymond, S., Zennaro, R., eni e&p, Oct. 2010. Shale Gas:

From Unconventional Subsurface to Cost-Effective and Sustainable SurfaceDevelopments. Oil & Gas Symposium, Nanjing.

Mancini, F., Zennaro, R., Buongiorno, N., Broccia, P., Chirico, M., eni e&p, Mar. 2011.Surface Facilities For Shale Gas: A Matter Of Modularity, Phasing And MinimalOperations. 10th Offshore Mediterranean Conference.

US Department of Energy and National Energy Technology Laboratory, 2009.Modern Shale Gas Development in US: A Primer.

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