Validation-of-lateral-fluid-flow-in-an-overpressured-sand-shale-sequence-during-development-of

Research paper

Validation of lateral?uid?ow in an overpressured sand-shale sequence during development of Azeri-Chirag-Gunashli oil?eld and Shah Deniz gas?eld:South Caspian Basin,Azerbaijan

Rashid J.Javanshir a,1,Gregory W.Riley b,Stephan J.Duppenbecker c,*,

Nazim Abdullayev d

a BP1St James's Square,London,SW1Y4PD,UK

b BP Building F,Chertsey Road,Sunbury on Thames,TW167LN,UK

c BP Building C,Chertsey Road,Sunbury-on-Thames,TW167LN,UK

d BP153Neftchilar Avenue,Baku,AZ1010,Azerbaijan

a r t i c l e i n f o

Article history:

Received24November2013 Received in revised form

10July2014

Accepted20July2014 Available online28July2014

Keywords:

Azerbaijan

South Caspian Basin

Shah Deniz

Azeri-Chirag-Gunashli Pliocene Productive Series Lateral?uid?ow

Tilted?uid contacts

3D basin modeling a b s t r a c t

Data collected over the past15years from exploration,appraisal and production in the offshore South Caspian Sea validates the previously developed model of lateral?uid?ow from the overpressured basin center to the basin margins within the sandstone aquifers of the Pliocene Productive Series.Speci?cally, new data con?rm the predictions that1)although both sandstones and shales are overpressured, sandstones are generally less overpressured than shales,2)there is a lateral,regional gradient in sandstone overpressure,decreasing from the basin center to the basin margin and3)the impact on the pressure?eld from local features such as mud volcanoes or local faults is limited.Additional pressure data,combined with regional seismic mapping,suggests variations in lateral?uid?ow in different stratigraphic intervals.These data show that the less continuous sandstones of the upper and lower Productive Series are closer to the surrounding shale pressures as they are less well connected to the basin margin outlet,whereas,continuous sandstones in the middle Productive Series show the highest amount of lateral pressure transfer from the basin center and are therefore at lower pressures than the surrounding shales.Pressure data from development wells at the Azer-Chirag-Gunashli oil?eld and the Shah Deniz gas-condensate?eld reveal local variations in sandstone and shale overpressure resulting from the lateral pressure transfer affect(Traugott and Heppard,1994;Traugott,1996;Swarbrick and Osborne,1998;Yardley and Swarbrick,2000).Across large,high relief structures,well-connected sandstones transmit?uid pressures from the adjacent,deep overpressured synclines into the shal-lower crest of the structure.Pressures in sandstones decrease updip along a hydrostatic gradient (0.433psi/ft).The pressure gradient in the shales however,will change according to the shale over-pressure gradient.In the South Caspian Basin the overpressure gradient in the shales varies between0.6 and0.9psi/ft.Therefore,the relative overpressure between the sandstones and shales varies along structural dip.There are a number of important implications to exploration,appraisal,and development because of large scale lateral?uid?81c6830c360cba1aa911da94teral?uid?ow has consequences for the sealing capacity of sandstone reservoirs and the variable position of hydrocarbon e to-water contacts around a structural accumulation.This requires each sandstone e shale couplet be considered separately for pore pressure prediction.Basin-scale3D models were constructed to better understand the implications of basin-scale ?uid?ow within and between individual reservoirs at each structure.

?2014Elsevier Ltd.All rights reserved.

1.Introduction

The South Caspian Basin(SCB)has regained a prominent posi-

tion in global oil and gas production.Developments at Azeri-

Chirag-Gunashli(ACG)and Shah Deniz(SD)in the offshore

Azerbaijan(Fig.1)have resulted in export of large quantities of oil

and gas.These developments produce from the Pliocene Productive

*Corresponding author.BP Exploration Ltd.,Chertsey Road,Sunbury-on-Thames, Middlesex,TW167LN,United Kingdom.Tel.:t447747745033.

E-mail addresses:duppensj@81c6830c360cba1aa911da94,duppensj@81c6830c360cba1aa911da94 (S.J.Duppenbecker).

1Previously Rashid D.

Djevanshir.

Contents lists available at ScienceDirect

Marine and Petroleum Geology journal h omepage:ww w.elsevi 81c6830c360cba1aa911da94/locate/marp

etgeo

81c6830c360cba1aa911da94/10.1016/j.marpetgeo.2014.07.019

0264-8172/?2014Elsevier Ltd.All rights reserved.

Marine and Petroleum Geology59(2015)593e610

Series (PS)reservoirs (Fig.2)further offshore and in deeper water

than had been penetrated previously (Wethington et al.,2002;

Reynolds et al.,1998).

Hydrocarbons have been produced from PS reservoirs for over

150years,both onshore and then in shallow water extensions of onshore ?elds.In Bredehoeft et al.(1988),Buryakovsky and Javanshir (1983),Javanshir (1985)the authors interpreted data collected from these onshore and near shore developments and concluded that sandstones in the SCB act as lateral conduits for ?uid ?ow from the overpressured basin centre to the margins of

the Figure 1.A.Map of Caspian region showing oil and gas export pipelines of the Baku-Tblisi-Ceyhan oil pipeline (BTC)and South Caucasus gas pipeline (SCP).B.Bathymetry of north-western South Caspian Basin showing location of recent oil and gas developments and exploration wells.Azeri-Chirag-Gunashli oil ?eld (ACG)and Shah Deniz gas ?eld (SD)represent major new offshore developments with over one hundred and ?fty new wells drilled.Also shown on map are Areas I,II,and III as de ?ned in Bredehoeft et al.(1988)and extent of original data set.C.Schematic stratigraphic model of Bredehoeft et al.(1988),summarizing lateral ?uid ?ow model of South Caspian Basin.Area I displays highest sandstone to shale ratio and the least amount of overpressure.Area III displays the lowest sandstone to shale ratio and the highest amount of overpressure.Area II is intermediate between the extremes.R.J.Javanshir et al./Marine and Petroleum Geology 59(2015)593e 610

594

basin (Fig.1).They furthermore concluded that vertical conduits

such as faults or mud volcanoes did not greatly in ?uence the regional lateral ?uid ?ow system.These conclusions were based on the following observations:

1.Although both sandstones and shales are overpressured,sand-stones are generally less overpressured than shales.

2.The presence of a regional sandstone overpressure gradient is recognized with highest overpressures toward the basin centre.

3.The lateral sandstone overpressure gradient exhibits no local effects that would result from local vertical ?uid ?ow through faults or mud volcanoes.These observations were used to develop a general model that subdivided the Azerbaijan sector of the SCB into three areas.Fluid and pressure ?ows from the more distal and more highly over-pressured Area III through Area II and Area I and out of the basin through either outcrops or shallow structures (Fig.3).

LITHOLOGY

Sabunchy

Fasila

Balakhany

S u r a k a h a n y

NKG NKP KS PK

a l a K Miocene

Pliocene

Pleistocene

Recent Paleocene

Eocene

Oligocene

Absheron

Cretaceous

0.1 1.8 23.3

35.4

56.5

Epoch

Suites Akchagyl

1.6 P r o d u c t i v e S e r i e s

MA

7.0

Akchagyl Shale deposited during marine reconnection.

6.0 Major structure formation post dates Akchagyl Shale deposition. Deposition in low gradient, shallow

lacustrine basin with laterally

extensive fluvio-delatic sandstones separated by lacustrine shales.

Isolation of basin in Late

Miocene resulting in deposition in shallow water lacustrine basin.

Deposition in deep water back arc

basin. Includes deposition of Oligocene Maykop source rock.

Lower PS sediments infill pre-existing topography.

Deposition in deepwater lacustrine system with large, growing anticlines.

Decrease in sandstone deposition

in basin. Deposition of evaporites in Surakhany.

2.4

L o w e r M i d d l e U p p e r

Figure 2.Stratigraphic column for South Caspian Basin.The Lower Productive Series contains the Kala Suite,Under-Kirmaky Suite Sandstone (PK),Kirmaky Suite (KS),Above-Kirmaky-Sandstone (NKP)and Above-Kirmaky Shale (NKG).The Middle Productive Series contains the Fasila (also known as Pereriv)and Balakhany Suites.The Upper Produc-tive Series contains the Sabunchy and Surakhany Suites.

R.J.Javanshir et al./Marine and Petroleum Geology 59(2015)593e 610595

2.Recent developments

Over the last 15years,a substantial amount of additional data

have been collected from the SCB during drilling of exploration

wells and development of two major offshore hydrocarbon ?elds

ACG and SD (Fig.3).Whereas the earlier data set was con ?ned to the onshore and shallow water shelf,these recent data extends into the deeper water Caspian Sea (Fig.1).These recent data includes a large number of direct measurements of sandstone pore pressure as well as sonic logs for interpretation of shale pore pressures.Furthermore,due to the complex pore pressure system and criti-cality of pore pressure prediction to exploration and

developments Figure 3.A.Map showing overpressure distribution in Fasila based on measured pressures in sandstones from offshore well data.Strong decrease in overpressure to northern basin margin is a consequence of pressure out ?ow through well-connected sandstones.The box outlines the basin model area as described further in the text.The contours in Area III are based on extremely limited data and small scale perturbations should not be interpreted.B.Schematic cross section showing pressure regime changes in a well-connected sandstone (e.g.Fasila)from basin centre to margin of basin.R.J.Javanshir et al./Marine and Petroleum Geology 59(2015)593e 610

596

(especially well planning),a signi?cant effort has been made to understand and model the pore pressure evolution at both a local and regional scale.These new data have allowed us to test previous conclusions(Bredehoeft et al.,1988;Buryakovsky and Javanshir, 1983;Javanshir,1985)against a much more regionally extensive and detailed dataset.

These new data strongly support the original conclusion of regional?uid?ow through well-connected sandstones in the SCB. Figure3shows the overpressure distribution for a single sandstone interval in the Fasila based on pressure measurements in sand-stones.This map clearly illustrates a strong lateral overpressure gradient in the Fasila sandstone at the basin scale,from extremely high,near lithostatic overpressures in the basin centre to approx-imately hydrostatic pressures on the basin margin.It should be noted that at the local structural scale there can be complications arising from local structural heterogeneities as documented by Adler et al.(2012),Chevallier et al.(2012)and Grosjean et al.(2009). This paper is an attempt at a more general regional model and does not purport to explain local structural perturbations.

3.Re?nements to model

These new data do however allow re?nements to the original model.These re?nements are:

1)A more precise understanding of the regional stratigraphic ar-

chitecture of individual sandstones and their control on basin-scale connectivity and the resultant overpressure of these sandstones and,

2)The impact of lateral pressure transfer on differential sandstone

and shale overpressures within a single anticline.These addi-tional observations also highlight important implications of the model to hydrocarbon exploration,appraisal and development.

3.1.Stratigraphic and depositional controls on regional variations

in overpressure

In the original interpretation of Bredehoeft et al.(1988)authors generalized the regional stratigraphic component of the model into a generic stratigraphic model(Fig.1).Substantial work conducted on the regional stratigraphic architecture of the PS(Fig.2)since that time(see Reynolds et al.,1998;Hinds et al.,2004;Abdullayev et al.,2012)has resulted in a more detailed regional stratigraphic architecture for the PS.Abdullayev et al.(2012)describe in some detail the depositional architecture of the PS in the SCB(Fig.4).The results of this work con?rmed that some sandstone horizons are regionally extensive into the SCB because of deposition on a very low-gradient ramp in a shallow water under?lled lacustrine setting.However,they also show that other stratigraphic intervals contain less regionally extensive and therefore less well-connected sandstones.

Speci?cally,they subdivide the PS into three intervals.The Lower PS,containing the Kala Suite(KaS),Under-Kirmaky Suite Sandstone(PK),Kirmaky Suite(KS),Above-Kirmaky-Sandstone (NKP)and Above-Kirmaky Shale(NKG)formed the initial de-posits in the basin after the major Messinian base level fall that resulted in isolation of the SCB(Reynolds et al.,1998;Hinds et al., 2004;Green et al.,2009;Abdullayev et al.,2012).Sandstones in the Lower PS are interpreted to have been deposited on the margins of a deeper lake and therefore are less extensive into the SCB (Fig.4).The Middle PS(Fasila and Balakhany Suites),in contrast, was deposited after in?ll of the pre-existing topography in a shallow water under?lled lake.Sandstones in the Middle PS, especially the Fasila D,Fasila B and the Balakhany VIII,are the most laterally extensive and form the predominant offshore reservoirs (Wethington et al.,2002;Reynolds et al.,1998).These Middle PS sandstones best?t the stratigraphic model described in Bredehoeft et al.(1988).Sandstones in the Upper PS(Sabunchy and Surakhany) are mostly limited to the margins of the basin and do not extend as continuous,connected sandstone sheets beyond Area I.

Therefore,a re?nement to the original model(Bredehoeft et al., 1988)based on a more detailed understanding of the stratigraphic architecture of the PS would predict that the less continuous sandstones of the Upper and Lower PS would have lower basin-scale connectivity due to more restricted?ow pathways.The resultant overpressure in the sandstones would be closer to the surrounding shale pressures.The more continuous sandstones in the Middle PS would have higher basin-scale connectivity and would best?t the model of lateral pressure transfer from the basin centre with large differences between sandstone and shale over-pressures(Bredehoeft et al.,1988).

Recent pressure data(Fig.5)clearly illustrate the stratigraphic control on overpressure in Area II.The pressure regression of up to 4500psi at approximately5e6km is associated with the well-connected Balakhany and Fasila aquifers.The high overpressures in the above interval are associated with poorly connected Upper PS.These strong vertical changes in sandstone overpressure con?rm the lateral out?ow of pressure through the better-connected sandstone of the Middle PS.The variability in over-pressure is a consequence of the regional basin-scale connectivity of individual sandstone units.

3.2.Local lateral pressure transfer impacts on sandstone versus shale pressures

The analysis of a detailed set of pressure data,primarily from the Shah Deniz structure,allowed for further re?nement to our original model.This data set shows variations in sandstone and shale overpressure with depth resulting from the lateral pressure trans-fer effect(Bowers,1995;Traugott and Heppard,1994;Traugott, 1996;Swarbrick and Osborne,1998;Yardley and Swarbrick, 2000).Across large,high relief structures,well-connected sand-stones transmit?uid pressures from the adjacent,deep,over-pressured synclines into the shallower crest of the structure. Pressures in sandstones decrease updip along a hydrostatic gradient(0.43e0.46psi/ft).The pressure gradient in the shales however,will change according to an overpressure gradient.In the SCB the overpressure gradient in the shales typically varies be-tween0.6and0.9psi/ft.Therefore,the relative overpressure be-tween the sandstones and shales varies with depth of the structure as shown schematically in Figure6.

For this scale of lateral pressure transfer,sandstone connectivity is required only at the scale of the structure and not at the basin scale.Our experience in the SCB has shown that almost all sand-stones exhibit this scale of connectivity over geologic time scales. Therefore,sandstone pressures tend to be higher relative to shale pressures near the crest of the structure and lower relative to the shale pressures down?ank.Absolute differences between the sandstone and shale pressures depend on the regional connectivity of the sandstone.

The SCB has numerous large anticlines with areas greater than 300km2and vertical relief of3000m(Fig.7).Structures began their main phase of growth at the end of the Pliocene with younger sediments focused into the adjacent synclines.This results in an addition of up to3000m of recent sediment in synclines(Fig.7).As a result,more overpressure is generated in the synclines and due to the dramatic relief there is signi?cant lateral pressure transfer in continuous sandstones from synclines into the structural crests.

R.J.Javanshir et al./Marine and Petroleum Geology59(2015)593e610597

Figure4.A.North e south stratigraphic cross section through the Caspian Basin.The section is datumed at the top of the Productive Series and is based upon2D seismic and well data.This section highlights the differing stratigraphic architecture of individual sandstones within the PS.The Lower PS in?lls the previously existing topography and the Middle PS sandstones form more continuous sheets above this in?ll.The Upper PS then gradually backsteps.The most extensive sandstones are found in the Balakhany VIII,Fasila and NKP.KaS

refers to the Kala Suite.Modi?ed from Green et al.(2009).B.Paleogeographic map of regionally extensive Fasila sandstone.Modi?ed from Abdullayev et al.(2012).

The transfer of high pressures in the sandstones to the structural

crests can result in sandstone pressures at or near to the over-

burden stress.In these instances,there is an extremely limited

ability for these sandstones to preserve a hydrocarbon column.In

addition,the low effective stresses create a situation where there is

little to no mud-weight window for drilling.Often these low

effective stress regions must be drilled through in order to reach

the deeper primary reservoirs.

3.3.Control on sandstone overpressure

From the above discussion therefore,the amount of over-

pressure in any one sandstone interval at any one location is a

consequence of both the original overpressure resulting from

compaction disequilibrium and subsequent redistribution of pres-

sure locally and regionally within the permeable sandstone layers.

4.Recent data

4.1.Methodology

The following section summarizes our methodology for pore

pressure prediction and correlation of pressure derived

parameters 0

1

3 5

7 0 5000 10000 15000

Sandstone Pressures, PSI

D e p t h (k m s ) Middle Productive Series Upper Productive Series

Figure 5.Recent pressure data from sandstones in Area II reveals

a strong

stratigraphic

control on overpressure.The Upper PS of the overburden is highly overpressured,

approaching lithostatic stress.The Middle PS (Balakhany and Fasila)below approxi-

mately 5km depth shows a dramatic reduction in overpressure.

Pressure PSI 5000

5500 6000 6500

7000

7500

8000

5000 10000 15000 20000 25000

D e p t h M e t e r s Sandstone

Shale

Lithostatic Hydrostatic Figure 6.Schematic example of the impact of lateral pressure transfer and its impact on the difference between sandstone and shale pressures.If we start with an assumption of 12,000psi pressure in sandstones and shales at a depth of 6000m (not an unreasonable assumption for the offshore South Caspian at reservoir level as

Shah Deniz ?eld shows a range from 4500to 7000m for the centroid),well-connected sandstones will change pressure updip and downdip at a hydrostatic (?uid)gradient whereas shales can change pressures at a gradient approaching the lithostatic gradient.Figure 7.A.Structural map of the Fasila in the SCB showing dramatic relief of SCB anticlines.Relief from syncline to crest of structure can exceed 3kms.B.Pleistocene to Recent sedimentation rate in meters per million years in the SCB.Dramatic differences in sedimentation rates between synclines and crest of structures.The highlighted box represents the area of the basin model described later in the text.

R.J.Javanshir et al./Marine and Petroleum Geology 59(2015)593e 610599

across the SCB.Well log measurements (such as sonic,density and resistivity),direct pressure measurements of sandstones,seismic interval velocities,and compaction models serve as an input for integrated estimation of the overburden,pore pressure and fracture pressure for purposes of and exploration assessment,well planning and ?eld development.

The “overburden ”stress is the pressure exerted by all overlying material,both solid and ?uid.The overburden stress is calculated by ?tting a generic density model to well density data or inte-grating well log density at each well location.Where the well density is not available interval velocity or compaction models are used to deduce the overburden stress.

Formation pore pressure measurements in sands do not always match shale pressures inferred from well logs or seismic velocities.This may simply mean the ‘model ’used to compute shale pressures requires better calibration,or that there is a genuine inequality between the sand and shale pressures that describes about pres-sure drive and ?uid movement over geological time.The shale pore pressures were computed from sonic logs using an industry stan-dard compaction trend based on the Eaton method (Eaton and Eaton,1997).In our methodology,the majority of pressure values matched the sand pressures when the Eaton exponent is set to 4(usually within the industry the Eaton exponent of 3is used).Translating shale pressures along structures is open to discussion however,as direct measurements of shale pore pressure are hard to achieve.In our approach shale pore pressure were translated along structures according to overpressure gradient trends developed for individual shale intervals.

Sand pore pressures were directly measured using various direct pressure measurement tools at well locations and mapped using appropriate ?uid gradients for gas condensate and water within reservoir

outlines.

Figure 8.Depth structure map of Shah Deniz at top Fasila B interval.Location of exploration,appraisal and development wells shown.Structural height is 3500m from syncline to crest over a distance of approximately 15km.

R.J.Javanshir et al./Marine and Petroleum Geology 59(2015)593e 610

600

An internal BP fracture pressure model was used that calculates fracture pressure based on pore pressure,overburden,Poisson's ratio and tectonic stress and was calibrated to local leak off test (LOT)data.

4.2.Area II d Shah Deniz gas development

There are no developments in Area III and therefore only a limited set of data are available.However,the limited data avail-able does indicate,that the best-connected sandstones of the Fasila and Balakhany Suite contain less overpressure than sand-stones in the lower net to gross section of the Sabunchy and Surakhany Suites.We will not discuss Area III in any more detail.

As Area II is in the transition zone from the less overpressured basin margin to the highly overpressured basin centre,it shows the impacts of lateral?uid?ow most dramatically and therefore will be discussed?rst.Area II contains the Shah Deniz gas-condensate?eld (Fig.8).The?eld has multiple,stacked reservoirs lying at depths between4600and6500m below Caspian Sea level.Thirteen exploration,appraisal and development wells have been drilled to date and more than a thousand pressure measurements have been obtained.The Shah Deniz Stage1project is currently producing approximately8billion cubic meters per annum

(BCMA,

Figure9.Well data from Area2(Shah Deniz).Gamma ray on left shows net to gross changes vertically through section.Pressure plot on right shows sandstone pressures from MDT data and shale pressure as interpreted from sonic log.For reference purposes hydrostatic and lithostatic trends are shown.The amount of overpressure is also shown.All sandstone pressures have been converted to water pressure(the effect of the hydrocarbon buoyancy has been removed).PP e Pore Pressure,OP e Overpressure,Hydro e Hydrostatic Pressure.

R.J.Javanshir et al./Marine and Petroleum Geology59(2015)593e610601

770mmcfd)from the Alpha Platform in the north-eastern part of

the structure and the Shah Deniz Stage 2project is in the devel-

opment phase with ultimate production at Shah Deniz planned for

24BCMA (2300mmcfd).

Figure 9shows data from a mid-?ank well drilled at Shah Deniz.

This well is located approximately 1000m beneath the structural

crest and like all wells in Shah Deniz displays a strong stratigraphic

control on the vertical overpressure distribution.The lower net to gross and less well-connected Surakhany and Sabunchy intervals contain substantially more overpressure than the sandstones of the higher net to gross and laterally continuous Fasila and Balakhany Suites.At this mid-?ank location,sandstones and shales in the Surakhany and Sabunchy are at similar overpressure.Sandstones in the higher net to gross Fasila and Balakhany not only are less overpressured than the lower net to gross intervals but also contain substantially less overpressure than surrounding shales.

The Figure 10.A.Cross section at Shah Deniz highlighting continuity of the main sandstone and shale intervals.B.Initial pressures in Shah Deniz sandstones.Pressure data from each sandstone has similar levels of overpressure.The exact trend is related to the ?uid type,column length and position of the well in the regional pressure trend.They are separated from adjacent sandstones by lacustrine shale.C.Pressure depletion as measured in SDX-4and SDX-5appraisal wells during production from the SD Alpha platform.This pressure depletion documents reservoir continuity at the scale of the Shah Deniz structure over production time scales (refer to Fig.8)for location of wells.Modi ?ed from Love et al.(2011).R.J.Javanshir et al./Marine and Petroleum Geology 59(2015)593e 610

602

Balakhany VIII interval contains the least overpressure in this extremely overpressured system and indeed even approaches hy-drostatic pressures.Shale pressure is shown as straight lines because it connects log-derived shale pressure measurements above and below the sandstones.It is likely that thin shales within these sandstones are dewatered and at sandstone pressures. However there are some?ooding surfaces above Balakhany VIII and between the Balakhany sandstones that retain high overpressure.

An identical stratigraphic control on pressure is shown in all wells at Shah Deniz(Fig.10).Figure10A shows individual sand-stone layers separated by continuous lacustrine shales.Figure10B is from the initial exploration and appraisal wells and shows that although each sandstone horizon contains different amounts of overpressure,each individual sandstone horizon is in pressure communication over the structure.This dramatic and consistent initial pressure stratigraphy,with reduced overpressure in the larger,higher net to gross intervals,is strong con?rmation of the importance of lateral?uid/pressure?ow within the system.

Pressure connectivity at the scale of the Shah Deniz structure is documented over both geological time scales,as described above, and production time scales.Pressure connectivity at production time scales is demonstrated by analysis of pressure data collected from pressure gauges installed in two appraisal wells.These two wells are approximately10e15km away from the producing wells and record the pressure depletion(Fig.10C)in the Fasila as a consequence of production at the Shah Deniz Alpha Platform.Both wells show a relatively consistent drop in pressure of approxi-mately200psi over a period of about one year.

Additional data to support the importance of regional-scale lateral?uid?ow through these well-connected sandstones is shown by the pressures in the aquifers around the Shah Deniz structure and the resultant hydrocarbon contacts.Aquifer pressures were obtained in the northern?ank of the structure in the SDX-3 well and in the southwestern part of the structure in the SDX-4 well(Fig.11).As predicted by the regional pressure data in Figure3A,the reservoirs in the SDX-4well contain more over-pressure than they do in the SDX-3well.This difference in aquifer pressure results in a tilted hydrocarbon contact with shallower contacts in the basin-?anking south west?ank and deeper contacts in the north?ank(Love et al.,2011,Fig.11).This is interpreted to result from the fact that the south and west?anks face the extremely overpressured central portion of SCB whereas the northeastern part of the structure faces the normally pressured basin margin.Pressure data from wells in the aquifer show over-pressure differences across the structure to vary between200and 1000psi over a distance of15kms.

To get a more holistic view of sandstone versus shale pressures for the Shah Deniz structure,sandstone and shale pressures are extrapolated updip to approximate a crestal location,and downdip towards the syncline(Fig.12).Sandstone pressures are translated along?uid gradients,and shale pressures are translated along trends developed at Shah Deniz for individual shale intervals.These data show that even at crestal locations sandstones in the Bala-khany and Fasila are at lower pressures than surrounding shale pressures,whereas sandstones in the lower net to gross intervals of the Sabunchy and Surakhany are at higher overpressure than sur-rounding shales.In fact,the pressure in the upper most Surakhany and the Sabunchy sandstones are projected to equal the fracture pressure at the absolute crest of the structure,reducing the effec-tive stress at these locations to zero.This implies that the crestal fracture pressure is in fact the local control on the pore pressure in Sabunchy and Surakhany sandstones and that?uid and pressure is likely to escape through the crest of the structure from these sands.

These extremely high overpressures on the crest of the structure result in greatly reduced sealing integrity for the Sabunchy and Surakhany sandstones,as any excess pressure as a result of hy-drocarbon buoyancy results in the pore pressure exceeding the crestal fracture pressure and therefore leaking through the crest. Furthermore,these crestal locations have greatly reduced mud-weight drilling windows between the sandstone pressure and the fracture pressure.

4.3.Area I d Azeri Chirag Gunashli

Area I contains the ACG oil?eld development where over150 wells have been drilled from the installed platforms and several thousand-pressure measurements obtained(Fig.13).Hydrocarbons are found in more than10stacked horizons ranging from oil to gas-condensate.Since1994,approximately2billion barrels of oil have been produced,primarily from the Fasila Suite.Structural closure along the anticlinal trend is greater than900m and the structural height from crest to the syncline is in excess of2500m.

Data from one of the initial appraisal wells on the ACG structure is shown in Figure14.The well is from a crestal location(called BO1ST1)on the Azeri structure and was chosen as it was drilled prior to substantial production and has a relatively complete

data

North-East

South-West

SDX-4

SDX-3

0 metres 2000

Approx horizontal scale Approx vertical scale 0

400 metres

Figure11.Schematic cross section from across Shah Deniz structure showing relative position of hydrocarbon contacts.All contacts are shallower with higher aquifer pressures in the basin-facing southwest part of the structure and deeper with lower aquifer pressures in the basin margin facing north?ank(Fig.3).Contact differences are about100e500m. Modi?ed from Love et al.(2011).

R.J.Javanshir et al./Marine and Petroleum Geology59(2015)593e610603

set.A pressure stratigraphy can be observed with regionally extensive lacustrine shales creating pressure barriers to vertical ?ow between sandstones.

Sandstones in the lower overall net to gross Surakhany and Sabunchy Suites contain relatively high overpressure compared to the surrounding shales.This suggests that the sandstones are poorly connected regionally such that they cannot lose substantial pressure to the equivalent outcropping strata at Absheron Penin-sula on the margin of the basin.The fact that the sandstones are at higher pressures than the surrounding shales suggests that they are however,connected to the adjacent syncline.

Sandstones in Balakhany and Fasila Suites show a reduction in overpressure relative to the Upper PS with the lowest over-pressures in the Fasila and Balakhany VIII.Even at this crestal location,the sandstone overpressure is at or below the overpressure in the surrounding shales.The lower net to gross in-tervals of the Balakhany IX and X are more similar to the Surakhany and Sabunchy strata with relatively high overpressure in the sandstones and thus poorly connected regionally.The lower over-pressure in the Balakhany VIII and Fasila Sandstones requires that they be connected laterally to a region of lower pressure.The most likely location for this pressure sink is the onshore/nearshore area and outcropping strata around the Absheron Peninsula.As shown in Figure 3,the strata are regionally correlated and connected to-wards the onshore.

Further con ?rmation for connectivity of the Fasila reservoirs is provided by production scale studies conducted since the ?eld was put on production.Reynolds (2006)and Tozer and Borthwick (2010)summarized production data and describe the ?eld-scale (~50tkm scale)connectivity of the reservoirs at ACG (Fig.15

).

Figure 12.Extrapolation of overpressures updip and downdip away from the original mid-?ank well at Shah Deniz.Sandstone pressures are extrapolated on a water gradient and shale pressures are extrapolated on an overpressure gradient develop for individual shale layers.Mid ?ank well is SDX-1as shown on Figure 8.

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604

Reynolds (2006)shows that because of oil production over the past 20years the Fasila reservoirs along the entire ACG megastructure are depleted.

Pressure is also transmitted from the deep,overpressured syn-cline south of the ACG structure through these well-connected sandstones.This is shown in a study of the aquifer pressures around the ACG megastructure (Tozer and Borthwick,2010).This study documents the presence of a hydrodynamic ?ux within the main reservoirs with the pressure front advancing from the highly overpressured SCB (Fig.3)resulting in a severe tilt of the oil-water contacts northward (Fig.15C).The northern ?ank of the ACG megastructure dips into the normally pressured North Absheron Basin.

Tozer and Borthwick (2010)show that in:1)lower net to gross intervals,pressures from the adjacent syncline are transmitted locally updip into the crest,but not laterally out of the basin and 2)high net to gross,well-connected intervals,pressures are trans-mitted from the adjacent syncline into the crest and also laterally out of the basin.

To highlight the full range of overpressures expected on the ACG structure,Figure 16shows a pressure model for two pseudo-well locations downdip from the crestal well shown in Figure 14.

Sandstone pressures are extrapolated along a water gradient and shale pressures are extrapolated along shale pressure trends developed at ACG.These data show similar results to Shah Deniz,where in the crestal and mid ?ank locations,sandstones in the lower net to gross intervals are at pressures above shale pressure due to their inability to transmit pressure out of the basin.Sand-stones in the higher net to gross main reservoir intervals are either at,or below,shale pressures,from the syncline to the crest,as pressure is transmitted through these sandstones out of the basin.4.4.Discussion

Data collected over the past 20years have shown that lateral ?uid ?ow is a critical mechanism in the burial and compaction history of the offshore SCB.Data from ACG and SD developments show that well-connected,regional reservoirs of the Balakhany and Fasila Suites contain less overpressure than both the surrounding shales and the less well-connected sandstones in the Sabunchy and Surakhany Suites.Furthermore,production data also show that at the scale of each individual ?eld the sandstone reservoirs are very well connected over production time scales.The occurrence of hydrocarbon contacts tilted towards the basin margin at both

SD

Figure 13.Structure map of Azeri-Chirag-Gunashli oil ?eld.Map shows location of production and drilling platforms and well paths.This structure map is located near the top of the main reservoir of the Fasila Suite.Structural contours are in meters.Cross section is shown in Figure 15.

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and ACG support the hypothesis of lateral ?ow away from the basin centre and towards the basin margin within regionally well con-nected sandstones.Deposition of such laterally extensive,perme-able,sheet sandstones,separated by laterally extensive mudstones,is interpreted to be a consequence of deposition in a large,under-?lled lacustrine basin with a resultant aggradational stacking pattern (Abdullayev et al.,2012).

In the original paper of Bredehoeft et al.,1988the term “regional permeability ”was used in order to examine the hypothesis that the interbedded sands are acting as drains at regional scale for ?uids being expelled from the compacting shales in SCB.It was assumed that regional permeability re ?ects a combination of permeability at pore scale,geometry of the basin,average sand-shale thickness at different depths,sand-shale ratio,and lateral and vertical connec-tivity at the basin scale.One may reasonably expect that regional permeabilities are indicative of an average amount of intercon-nection of the sands across the entire basin,and they would be one or two orders of magnitude smaller than permeability of the single sand body (Bredehoeft et al.,1988).

In Bredehoeft et al.(1988),a series of 1D and 2D mathematical solutions were constructed to determine if this mechanism was reasonable.Over the last decade,however,integrated 3D basin modeling techniques have been developed and increasingly applied to study and quantify the pressure and temperature dy-namics of young sedimentary systems on regional to local scale (Poelschau et al.,1997;Kroeger et al.,2008;Schneider et al.,2000).Based on our comprehensive regional lithology and chro-nostratigraphic description of the depositional history from the Cretaceous to present,a 3D ?uid ?ow model for the SCB has been developed.3D basin modeling technology was applied to recon-struct geological processes through time and to quantify the evolution of pressure and temperature in the subsurface.This approach enabled the reconstruction of the 3D pressure and temperature ?eld evolution through the geologic history of

the

Figure 14.Well data from Area 1(ACG).Gamma ray on left shows net to gross changes vertically through section.Average net to gross values for structure shown on far left.Pressure plot on right shows sandstone pressures from MDT data and shale pressure as interpreted from sonic log.Shale pressures in the very high net to gross intervals should be ignored as there is insuf ?cient shale for calculation.For reference purposes hydrostatic and lithostatic trends are shown.The amount of overpressure in sandstone and shales is also shown.All sandstone pressures have been converted to water pressure (the effect of hydrocarbon buoyancy has been removed).P ?Pressure;OP ?Overpressure;Hydro ?Hydrostatic pressure.

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SCB and provided key insights into the dynamics of regional ?uid ?ow.

The study area measures 190?220km and captures Areas I,II and III.The model quanti ?es in some detail the history of sediment deposition from the earliest Eocene to the present day.The cali-bration of the model to well observations in Areas I d III was critical to quantify the dynamics of the petroleum system,with emphasis on pressures,temperatures and the nature of ?uids.The modeling results match the main subsurface observations and provide a quantitative understanding of the transient nature of the young petroleum system in the SCB.

The 3D basin model simulates the observed data as shown in Figure 5and matches the differential aquifer pressures on the basin facing ?anks of SD and ACG.Figure 17shows the simulated over-pressure ?eld in the extensive aquifer of the Fasila Suite resulting from the 3D ?uid ?ow simulation model.The Fasila is used in this example;however,each sandstone reservoir has its own unique pressure distribution arising as a consequence of the interaction of the sandstone geometry and the basin structural history.The ?ow rates simulated for the Fasila B aquifer are up to 10cm/year and the

hydrocarbon accumulations in the crest of the large structures of Shah Deniz and ACG act as ?ow barriers which perturb the aquifer ?ow ?eld locally.The observed tilt of the hydrocarbon e water contact is caused by the pressure differential which has developed in the aquifer due to the ‘blockage ’of the crestal area for aquifer ?ow.The result can be seen in Figure 17in the offset of the isobars around the hydrocarbon columns of ACG and Shah Deniz which ‘drive ’the tilt of the hydrocarbon contacts.The occurrence of hydrodynamic-controlled ?uid contacts in extensive aquifers is not uncommon and has been described in large number of reservoirs worldwide as in the Britannia Sandstone Formation in the North Sea (O'Connor and Swarbrick,2008;Dennis et al.,2005),Peciko and Tuba ?elds in Mahakam Delta (Grosjean et al.,2009)and the Cretaceous Shuaiba Formation in the Al Shahin ?eld,Qatar Arch (He and Berkman,2003).

4.5.A note on the role of mud volcanoes

More than 30%of the world's known mud volcanoes are concentrated in the South Caspian Basin (Milkov,2000;Yusifov

and

Figure 15.Data highlighting pressure connectivity in reservoirs at ACG.A.Well log and seismic showing lateral connectivity of main reservoir sandstones at ACG (modi ?ed from Reynolds,2006).B.Pressure depletion over time in main Fasila reservoirs at ACG ?eld.From Tozer and Borthwick (2010).C.Cross section through ACG oil ?eld showing dramatic tilt in oil-water contact with shallower contacts on south ?ank and deeper contacts on north ?ank.Tilt is interpreted to result from strong hydrodynamic ?ux through well-connected reservoirs coming from highly overpressured SCB (Tozer and Borthwick,2010).Line of section is shown on Figure 13.

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Rabinowitz,2004).Some of the most spectacular mud volcanoes are concentrated in the South Caspian,their activity resulting in the expulsion of large volumes of mud,water and gas from the deeply buried source rock to the surface.Onshore mud volcanoes have been studied in some detail for a many decades,and their sub-marine equivalents have been described from modern seismic data (Fowler et al.,2000;Yusifov and Rabinowitz,2004;Stewart and Davies,2006).

A large number of authors assert that mud volcanoes act as perturbations in regional pressure ?eld and conduits to migrating hydrocarbons (Katz et al.,2000;Isaksen et al.,2007).However,Bredehoeft et al.(1988)commented that since a large lateral gradient exists across the basin,vertical conduits for ?ow,such as mud volcanoes,are not a signi ?cant outlet for the ?uid ?ow.In all of the subsequent data that we have collected since that time,we do not observe any impact on the local or regional pressure ?eld that can be attributed to proximity to a mud volcano.Both ACG and Shah Deniz contain a number of large mud volcanoes,with several of them showing activity in the last few hundred thousand years (Fowler et al.,2000;Stewart and Davies,2006).In neither of these ?elds is there any indication of perturbation of the local pressure ?eld due to proximity to a mud volcano.Furthermore,the dramatic pressure stratigraphy observed in a Shah Deniz well (Fig.8)does not suggest reservoir pressure communication with the mud vol-cano.The well is located approximately 3km away from a large mud volcano and if the reservoirs were in fact connected to the mud volcano it is likely that they would all be of similar over-pressure.Recently acquired seismic data suggests a possible reason for their limited impact (Fig.18).Figure 18A shows the seismic expression of a buried mud volcano in the SCB.Because the mud volcano has been buried and the shallow sediments are compacted the image beneath the volcano cone is relatively good.This image shows that the pipe connecting the volcanic cone to the feeder zone (deep Maykop source rock)is very narrow (approximately a few hundred meters).In addition,the collapse of the adjacent horizons near the pipe likely severely disrupts the reservoir and reduces the reservoir quality in the immediate vicinity of the pipe,which will greatly retard ?uid ?ow in these intervals.Figure 18

B is a

three-

Figure 16.Extrapolation of overpressure downdip from a crestal well BO1ST1at the ACG structure (wells shown as 1on Fig.13).Sandstones are extrapolated along a hydrostatic gradient and shales along pressure trends developed from shales at ACG to create two pseudo well locations for the midlfank and downdip.

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dimensional high-resolution interval velocity display of a mud volcano pipe in the shallow overburden at ACG.The high-resolution interval velocity can image the pipe down to about 2km beneath the seabed,though the pipe itself does extend deeper into the Maykop source interval.This image also highlights the very restricted and con ?ned nature of the mud volcano pipe.5.Implications for exploration,appraisal and developments in overpressured lacustrine basins

There are a number of very important implications to explora-tion,appraisal and development because of large-scale lateral ?uid ?ow.

5.1.Exploration

As demonstrated by our observations the amount of over-pressure in each sandstone layer is a consequence of its regional distribution and connectivity.In overpressured settings,where sealing integrity is a critical risk,it is important to evaluate the sealing capability of each potential reservoir separately.More extensive,well-connected sandstones on the basin margin are likely to have more sealing capacity than poorly connected distal sand-stones.For example,in the Sabunchy and Surakhany intervals at Shah Deniz the pressures are at approximately lithostatic pressure at the crest.Any additional pressure because of hydrocarbon buoyancy would result in hydrocarbon leakage into the

overburden.

Shah Deniz

ACG

1450 2900 4350 5800 7250

0 Figure 17.Overpressure in Fasila Suite as generated in 3D ?uid ?ow model.Model shows ?uid ?ow from basin centre to margins of basin within well-connected sandstone of the Fasila Suite.The model outputs are very similar to the data-based map shown in

Figure 3.

Figure 18.A.Buried mud volcano in the SCB.Burial has compacted the mud volcano ?ows and allowed for a quality seismic image beneath the volcano.This image shows a very narrow pipe which can be traced from the buried volcano down into the Maykop interval,which is the source for all of the described mud volcanoes in the SCB.B.A mud volcano pipe in the overburden at ACG,highlighted using high resolution interval velocities,rendered to show only the low velocity zones which are typical of mud volcanoes.The velocity data resolves the pipe in about the ?rst 1.5e 2kms.

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5.2.Appraisal

The presence of a dynamic aquifer with a regional?uid?ux can result in tilted hydrocarbon contacts.Therefore,it is critical to consider hydrodynamic effect,when planning appraisal programs. Contacts found on the basinal?ank of the structure might lead to a conservative view of the accumulation,whereas those on the?anks close to the basin margin can give a more optimistic view of the potential degree of hydrocarbon?ll(Tozer and Borthwick,2010). This can help to increase the accuracy of in-place hydrocarbon volumes estimation.

5.3.Development and production

The high-degree of lateral reservoir connectivity found in these under?lled lacustrine systems can be a great advantage in the development and production stage by allowing for more predict-able reservoir behavior.Both Shah Deniz and ACG show production scale pressure continuity over many tens of kilometers(Reynolds, 2006;Love et al.,2011).

5.4.Pore pressure prediction and well planning

The transfer of pressure around the basin through well-connected sandstones presents a challenge to predict sandstone overpressure at wells.The overlying mudstone and sandstone pressures are not necessarily a guide to the deeper pressures. Generally,the better-connected sandstones will be at lower pres-sures as they are more likely to bleed pressure to the basin margin. However,in some cases,sandstones can be well-connected basin-ward but onlap in the landward direction.Even though at a regional scale disconnected sandstones do show a“similar”overpressure trend,at the local scale they do not.The reason they do not is that some sandstones pinch out or terminate at faults prior to reaching the crest and are therefore constrained by a higher fracture pres-sure than sandstones that reach the crest.Also some sandstones do not fully connect to the deepest part of the syncline and therefore do not feel the full pressure of the adjacent syncline.This is more detail than we have shown in this paper but it is an important concept in well planning.Fundamentally we believe that one should think of each of the sandstone/seal couplets in these basins as individual reservoirs and consider where are the pressure supply points and where are the pressure release points.This can be at both a basinal as well as local scale.Therefore,each sandstone e shale couplet must be treated as its own unique pressure cell.In addition,sandstones can easily transfer pressures from the deep synclines into the crest of structures.In the most extreme cases of pressure transfer,sandstone pressures effectively equal the over-burden stress on the crest.Therefore,special care must be taken in drilling wells in near crestal locations.

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