Imbibition only relative permeability is commonly used to model water influx in water-drive gas reservoirs, however an aquifer is rarely strong enough to maintain constant pressure support. Continued pressure depletion in the part of the reservoir swept with watercauses expansion and remobilisation of trapped gas behind the waterfront. This paper presents a reservoir simulation study on modelling the expansion and remobilisation of trapped gas due to pressure depletion as secondary drainage flow using relative permeability hysteresis.
Previous studies in literature on relative permeability show the secondary drainage curve during blowdown is below the primary imbibition curve. This is based on field cases and core experimental studies, which establish the existence of a gas remobilisation threshold above residual saturation to reconnect the gas phase. Commonly used hysteresis models by
The conclusion of this study is that the standard formalisms used to model relative permeability hysteresis (Killough, Carlson) should not be used to model trapped gas remobilisation due to blowdown as they do not incorporate a gas remobilisation threshold and a secondary drainage curve underlying the primary imbibition curve. By assuming no mobility threshold above residual gas saturation, the total recovery of residual gas will be overestimated. Instead, by adopting the ODD3P hysteresis model, gas production will be lower and water production higher due to the correct use of secondary-drainage relative permeability curves in a gas reservoir invaded by water. This will lead to a significant improvement in results from reservoir simulation and the subsequentevaluation of trapped gas recovery.
The expansion and remobilisation of residual or trapped gas saturations has a major impact on the prediction and/or matching of production and pressure response from a reservoir. This study intends to understand these impacts and serve as a preliminary guideline in modelling trapped gas expansion and remobilisation as secondary drainage flow, which is applicable to many water-drive gas reservoirs.
Studies of modern desert dune fields allow geologists to draw conclusions about the controls that govern the development of spatial patterns of arrangement of desert landforms. This knowledge can be applied to predict the likely arrangement of architectural elements in preserved ancient desert successions. This serves as the basis for the development of more sophisticated facies, architectural-element and sequence stratigraphic models that can be applied in reservoir geology.
This study presents a series of ten bespoke facies models that demonstrate different types of aeolian-fluvial interaction documented from dune-field margin settings. These ten semi-quantitative models have been developed based on analysis of modern and ancient systems, and via comparison of literature-derived case-study examples of ancient successions using a meta-analysis approach. The presented facies models account for the nature and origin of stratigraphic complexity present in aeolian dune-field margin successions that arose in response to the combined interplay of a series of autogenic and allogenic controls.
From an applied perspective, mixed aeolian and fluvial successions are known to form several major reservoirs for hydrocarbons, including the Permian Unayzah Formation of Saudi Arabia. However, quantitative stratigraphic prediction of the three-dimensional form of heterogeneities arising from aeolian and fluvial interaction is notoriously difficult: (i) interactions observed in one-dimensional core and well-log data typically do not yield information regarding the likely lateral extent of sand-bodies; (ii) stratigraphic heterogeneities of these types typically occur on a scale below seismic resolution and cannot be imaged using such techniques.
Understanding the nature and surface expression of various types of aeolian and fluvial interaction, and considering their resultant sedimentological expression, is important for prediction and interpretation of preserved deposits of such interactions that might be recognized in the ancient stratigraphic record. Assessment can be made of the spatial scale over which such interactions are likely to occur and this has applied significance; the developed facies models facilitate the prediction of net reservoir sandbody dimensions from subsurface successions by constraining the geometry and lateral and vertical connectivity of sand bodies for specific desert system types. Assuming layer-cake correlations between neighbouring wells within stratigraphically complex reservoirs composed of mixed aeolian and fluvial facies is inappropriate; instead, a range of bespoke facies models should be utilized, each of which considers possible stratigraphic configurations and each of which has implications for likely reservoir performance.
Autonomous systems offer expanding capabilities to provide maritime services in a time where saving costs, creating efficiencies and improved safety are vital. Autonomous vehicles are complex systems and therefore their design and development requires careful and detailed planning. Autonomous Surface Vehicles (ASV) is a rapidly growing company based in the UK with offices in the United States and is a leading manufacturer of Unmanned and Autonomous Marine Systems. Utilising specialist expertise and experience in the design, build and operation of Marine Autonomous Systems, the C-Worker 6 Autonomous Surface Vehicle (ASV) was developed for marine operations support in the Oil & Gas industry.
This paper explores the design and build process from a naval architecture, mechanical, electrical and software engineering point of view, from initial concepts to field operations. The authors also assess the presented method in a meta-design manner. With the initial concept and technology capabilities established, ASV collaborated with Oil and Gas service company Technip to establish industry requirements and define the final configurations accordingly through a dedicated technology qualification process. Technological advancements introduced in this 6 meter long vehicle known as the C-Worker 6, include the integration of multiple offshore payload combinations including USBL, ADCP (current meter), CTD, Multibeam Sonar, Acoustic Telemetry, and Passive Acoustic Sonar (PAM) for marine mammal detection. The robust design incorporating an aluminium, self-righting hull makes the vehicle suitable for harsh ocean environments. C-Worker 6 has a 30 day endurance at an average speed of 4 knots and houses fully redundant power propulsion and communication systems.
As a result of the methodology applied, the product development timeline is presented. The paper also presents data evaluated from real missions. Early qualification of the vehicle has shown its ability to perform in the high sea states of the Gulf of Mexico successfully carrying out subsea positioning in 1300m deep waters with 2.5m waves, as well as having performed Touch Down Point (TDP) monitoring support for S-Lay pipe installation during the technology qualification. The vehicle has since undertaken different mission witch includes a 5 day deployment in the Irish Sea where it held station and extracted data from a subsea platform via an integrated acoustic modem payload, a multibeam survey on a future wind farm installation and Pacific Acoustic Monitoring (PAM) in the Gulf of Mexico.
The interest for using unmanned and autonomous systems to support marine operations in Oil and Gas industry is anticipated to grow with the industry needs and requirements for more efficient, cost effective and safer solutions.
Centrica Energy operates the South and North Morecambe Fields, which are among the largest in the UK Continental Shelf in terms of original reserves. Current production is approximately 200 million cubic feet of gas per day, which is 5% of the indigenous UK production or 3.5% of the UK gas demand. Monitoring real-time production surveillance rates from each well in the field provides critical information for Centrica Energy’s reservoir management and workover planning. Centrica Energy explored the range of potential replacement technologies for the existing venturi meters, including installing new in-line differential pressure meters of several types, as well as traditional ultrasonic type meters. Parameters considered include the cost of acquisition, installation and the total cost of ownership, measurement quality and repeatability. Turndown ratio, or the instrument’s measurement range, was also an important consideration as this instrument was expected to measure well production throughout the declining life of the field.
In 2010, Centrica Energy trialed a SONAR meter on one well to assess its applicability to the well conditions in the Morecambe fields. The SONAR meters, applied at that time, were a new class of SONAR meter technology that had been developed specifically for Type I and Type II wet gas wellhead measurement. After evaluating the performance of the SONAR meter for one year, Centrica Energy installed SONAR flow meters on all 44 producing wells across 6 platforms. SONAR meters clamp onto the existing pipework allowing installation without shutting in the well and incurring the associated lost production, reducing management of change and HSE exposure. This paper describes the importance of real-time production surveillance for reservoir management and for making informed decisions concerning workover strategy and prioritization. In addition, this paper presents the production data collected over an extended time period and the challenges presented by the field wide implementation of a new class of flow meter technology.
SOUTH AND NORTH MORECAMBE FIELDS:
The South Morecambe Gas Field is located in the East Irish Sea Basin in Blocks 110/2a, 110/3a and 110/8a, some 26 miles due west of Blackpool. It was discovered by well 110/2-1 in 1974 and commenced production in 1985. The reservoir is in the Triassic Sherwood Sandstone Group, laid down in a rapidly subsiding basin under continental semi-arid conditions.
The South Morecambe reservoir is produced from five platforms and a total of 34 wells via volumetric depletion. Slant-drilling techniques were used in the initial development because the reservoir is shallow. Each of the five platforms has a single sub-vertical well and several slant wells. All five production platforms are connected to the Central Processing Platform (CPC) via a 24” line, and the entire production is then piped to Barrow via a 36” sea-line. The 34 active production wells consist of 5 vertical wells, 2 long reach wells and 27 slant wells. The wells are gathered to 5 drilling platforms which are a Normally Unmanned Installations. The gas is then piped to the Central Processing Platform before being compressed and sent to shore for further processing.
PEDL 164 is located to the north of Liverpool and contains the site of the abandoned shallow Formby oilfield. The licence lies within the West Lancashire sub-basin, the onshore extension of the NNW-SSE trending Permo-Triassic East Irish Sea Basin which itself overlies the earlier NE-SW trending, predominantly Lower Carboniferous-age Bowland-Craven Basin. Whilst Aurora Petroleum's initial interest in the area centered on the potential to redevelop the Formby oilfield (Roche and Openshaw 2010), the emergence of a new shale gas play in the basin, within PEDL 165 to the north, led to a review of historical well data, and the subsequent commissioning of new palynological and geochemical analyses which have resulted in the identification of a previously unrecognized shale oil play in the southern Bowland-Craven Basin. Figure 1 Location Map SPE 150933 3 Basin evolution Lower Carboniferous-age basins in northern England such as the Bowland-Craven Basin, Northumberland Trough-Solway Basin and the Stainmore Trough, were formed as a result of back-arc extension within the Avalonian microplate resulting from northward-directed subduction of the Theic Ocean beneath Iberia/Armorica (Waters and Davies 2006). These rift basins were separated by stable platform areas, a number of which are cored by late Caledonian granites (Figure 2). Figure 2 Lower Carboniferous Structural Elements after Waters et al (2009) BT Bowland Trough In the vicinity of the Bowland-Craven Basin, late Tournasian-early Chadian marine transgression coupled with the equatorial position of the area resulted in the highs being dominated by platform carbonates and the intervening gulfs by hemipelagic shale deposits, interbedded with calci-turbites. This pattern of sedimentation persisted throughout the Visean with the progressive deposition of the Hodder Mudstone Formation, Pendleside Limestone Formation and Lower Bowland Shale Formation (all Craven Group).
The unprecedented success of North American shale gas has lead to a proliferation of international shale gas exploration plays, particularly in Europe. Whilst differing basin geometries and structural geology provide significant local constraints on development strategies, global sea level changes provide a framework by which different stratigraphic intervals can be evaluated at a "continental" level. Using the Hallam Curve we have identified a number of global sea level maxima which correspond to significant periods of prospective gas shale deposition. These typically correspond to periods of relatively high sea level, frequently post-glacial, during which continental shelves were inundated and clastic sediment supply was limited because of the high base level. Under-filled marginal sedimentary basins appear particularly attractive exploration targets. Shales deposited under these conditions typically have geochemical and petrophysical characteristics comparable to North American shales which are currently in production.
Several orogenic events severely influence European shales in terms of organic maturity, hydrocarbon generation and fracture generation, key prospective horizons(in ascending stratigraphical sequence) include the Middle Cambrian Alum Shale, Lower Silurian (Llandovery), the Devonian (Fammenian/Frasnian), Lower Carboniferous (Serpukhovian), Lower Jurassic (Toarcian), the Upper Jurassic (Kimmeridge Clay) and the Tertiary Eocene and Oligocene shales common to central Europe.
This paper will outline the authors initial exploration strategy focusing on three main intervals: Lower Palaeozoic of Central Europe, the Namurian of NW England and the Jurassic Posidonia Formation of the Roer Valley Graben in Holland.
Diagenesis is defined as any chemical, physical or biological change undergone by a sediment (rock) after its initial deposition and during and after its lithification, exclusive of surface alteration (weathering) and metamorphism. The diagenetic changes that occur in the rock result in the alteration of some of the original petrophysical properties of the rock. Porosity and permeability, amongst others, have been established to be altered by diagenesis.
It is common knowledge in the industry that the amount of hydrocarbon recovered from a reservoir is dependent, amongst other factors, on the hydrocarbon initially-in-place in the reservoir and the intra reservoir rock pore space connectivity. The hydrocarbon initially-in-place is a function of the reservoir rock porosity and the pore space connectivity is a measure of the permeability of the reservoir rock. Thus the recovery from a reservoir rock affected by diagenesis, based on the aforementioned effects of diagenesis on reservoir rock porosity and permeability, is largely dependent on the extent of diagenesis that took place in the reservoir rock.
While reservoir performance behaviour is well established in sandstone reservoirs with diagenetic clays occurring throughout the reservoir, though may be scattered here and there in the reservoir rock, the case of a reservoir rock with a clay-affected layer directly below a clay-free layer, but is one sand pack, is unique.
This paper discusses the recurring increases in gas recovery in a partly illitized sandstone reservoir using the North Morecambe field in the East Irish Sea Basin as case study. Illite, a diagenetic clay mineral, has the characteristic of lining the pores of the reservoir rock. Its main effect is reservoir permeability alteration.
The North Morecambe field is a sandstone reservoir with two flow zones: an illite-affected zone overlain by an illite-free zone. More than half of the gas-in-place in the field is located in the illite-free zone. Reservoir dynamic simulation and historical production data analysis carried out on the field indicates
The study carried out and presented in this paper highlights best practise approach in completion strategy for efficient draining of the illitized part of a partly illitized sandstone reservoir. It further establishes a cubic, not a linear, behaviour as the reservoir performance behaviour to be expected from a partly illitized sandstone reservoir.
The Douglas and West Douglas fields are part of the Liverpool Bay development in the East Irish Sea. The reservoir is a high net-to-gross, largely good quality (100-1000mD) Triassic sandstone lying in a series of fault terraces. The fields have been on production for over 10 years and whereas some wells have shown a watercut development typical for a waterflood, other wells recorded anomalous behaviour. This work addressed these anomalies as these directly influence the value of a late-life infill programme.
The subsurface team reviewed outcrops of the reservoir in NW England, addressing the possibility of vertical flow up and along damage zones of faults which may be otherwise sealing (‘fault-related fractures') - a feature not previously identified in the field. The presence of fault-related fractures, observed in the outcrops, was tested in simulation models and provided a solution to the anomalous behaviour.
A novel technique was employed to pragmatically characterise the fault-related fractures in the simulator. The technique involved installing wells as ‘pipes' in cells around the faults, allowing flow up and along the fault damage zones without necessarily affecting fault transmissibility across the major zones. The size and location of the pipes representing the fractures was then used as a history matching parameter in the model and resulted in the improved history match of the anomalous wells
and the match in general.
Douglas Field Setting
The Douglas and Douglas West Fields are situated in the Liverpool Bay area of the Irish Sea, 30km off the west coast of the UK, with oil trapped in fault and dip-closed structures (Figure 1). The reservoir is a fluvio-aeolian Triassic clastic reservoir, locally known as the Ormskirk member of the Sherwood Sandstone formation. Core data indicate a high net-to-gross fluvial system, drying upwards into a succession of aeolian reworked fluvial sands with small dunesets and more extensive sandsheets. The sandsheets are a heterogeneous mixture of aeolian sandflats and ephemeral fluvial sandsheets. The reservoir is described more fully in Meddows (2006) and Yaliz & McKim (2003). A typical log profile for the reservoir is shown in Figure 2.
The field is highly faulted, with ca.150 faults mappable from 3D seismic, spread around four main fault terraces. The smaller faults are at least partially open to cross-flow, as pressure continuity is observed in the field at least along the fault terraces. The major terrace-bounding faults have traditionally been assumed to be sealing, an interpretation encouraged by the mudstone content of the reservoir, the scope for juxtaposition with the overlying mudstone seal and, crucially, the interpretation from log data of differences in fluid contacts between some of the terraces.
A logging while drilling (LWD) Azimuthal LithoDensity (ALD) imaging tool was run in horizontal dual lateral wells 110/15-L13 and 110/15-L13z with the aim of identifying fault and fracture intersections. The wells are located in the BHPBilliton operated Lennox Field, in the Liverpool Bay area of the East Irish Sea Basin, United Kingdom Continental Shelf (UKCS). Image quality is good and numerous geological features have been identified. Fractures have been classified as either high density or low density, relative to host formation. A total of 184 fractures have been identified in L13 while 121 fractures were identified in L13z. When corrected for borehole bias, 529 fractures are calculated to intersect L13 while 241 fractures are calculated to intersect L13z. Fracture orientations are consistent with the strike of regional scale faults. Fractures in L13 and L13z strike north-south, with minor north-northwest to south-southeast components. Significant drilling mud losses in the vicinity of fractures suggest that some fractures were open and therefore acted as fluid escape conduits. Drilling mud seepages within intervals that contain no apparent fractures may be related to fracture cuts that are below the resolution of the ALD sensor. It is also possible that some fractures became dilated after passage of the LWD tool assembly. Real time utilization of the LWD and ALD data enabled the operator to plan and locate External Casing Packers (ECPs) and the completion string quickly and accurately, thus removing conventional logging delays (and costs) while the drilling rig was on location.
INTRODUCTION AND GEOLOGICAL CONTEXT
The Lennox Field is located in UK blocks 110/14a and 110/15a, in the Liverpool Bay area of the East Irish Sea Basin (Figure 1). The structure comprises a faulted roll over anticline which is located along the hanging wall of the Formby Point Fault. The reservoir consists of Triassic Ormskirk Sandstone Formation, part of the Sherwood Sandstone Group (Jackson and Mulholland 1993; Jackson and Johnson 1996; Warrington et al., 1999). This comprises a series of aeolian and fluvial dominated sandstones (Meadows and Beach 1993; Meadows, 2005, 2006; Thompson and Meadows, 1995, Macchi, 2000). These are fractured and faulted on the eastern side of the field. Porosity ranges from 11-21% with air permeabilities of between 50 md and 10 darcies. The Ormskirk reservoir is subdivided into four vertically stacked reservoir zones which have contrasting petrophysical properties, a reflection of their contrasting depositional textures and compositions (Yaliz et al., 2002; Yaliz and Chapman, 2003). Zones I, II and III intersect the oil rim and gas cap, whilst Zone IV is in the aquifer. Zones I and III consist predominantly of excellent quality aeolian dune and sandsheet lithofacies. Zones II and IV consists of moderate reservoir quality fluvial sandstones.
Figure 1: Top structure map of the Lennox Field showing the L13 and L13z well paths. The wells were drilled in the eastern part of the field as a side track to the poorly performing L3 well. Yellow line segment indicates shared L13 and L13z well path trajectory. Inset map shows location of Liverpool Bay Development (red dot). (available in full paper)