Poor Seismic Imaging Research Articles

Merganser Field: managing subsurface uncertainty during the development of a salt diapir field in the UK Central North Sea

Abstract The Merganser Field is located in the East Central Graben of the UK Central North Sea, and consists of a gas/condensate column trapped in a structural attic on the flanks of a fully penetrating salt diapir. A large salt overhang obscures the field and structural definition is challenging owing to poor seismic imaging. Exploration drilling established a column of 1327 ft in Paleocene-aged deep-marine deposits of the Forties, Andrew and Maureen Sandstone members, and revealed significant geological complexity. Depositional styles record the relationship between salt tectonics and sedimentation, with variable reservoir distribution influenced by halo-kinetically induced palaeorelief and accommodation space. Re-mobilization of sediments is observed at multiple scales, and includes centimetre-scale de-watering structures, decimetre-scale sand injectites and kilometre-scale olistoliths. Whilst the hydrocarbon properties are consistent, contact depths are variable. Pressure data indicate compartmentalization across the field, which is likely to be caused by either radial faulting or hydrodynamic effects. Owing to the magnitude of subsurface uncertainty, the Merganser discovery could not sustain the investment required for standalone facilities. The development of the neighbouring Scoter Field provided the requisite local infrastructure to progress Merganser into production. The Field Development Plan (FDP) estimated recovery of 100 bscf gas and 3 mmstb condensate, and focused on delivering a low-cost development solution consisting of two horizontal wells and a subsea tie-back that would be robust against the downside, yet maintain flexibility to optimize in an upside outcome. Pilot holes were drilled to establish top reservoir with the subsequent horizontal well trajectories being re-designed to reflect structural geometry. The reservoir sections would maximize connectivity between fault compartments and stratigraphic units, and positioning was optimized with well-site biostratigraphy. Each reservoir section exceeds 4000 ft and maintains at least 1000 ft vertical stand-off from the gas/water contact. The facilities include a 5 km subsea tie back to the Scoter production manifold, with metering at the Merganser manifold for allocation purposes. Gas and condensate are commingled with Scoter, and transported 11 km to Shearwater for processing. The gas is transported onshore through the Shearwater Elgin Area Line and condensate through the Forties Pipeline System to Kinneil. Field performance to date has exceeded the FDP P50 both in terms of daily rate and cumulative production. Early production rates peaked at 100 mmscf/day of gas and 6000 stb/day of condensate and, to end-2014, Merganser has produced 161 bcf of gas and 10 mmstb condensate. This performance is due to a combination of better than expected connectivity, high reservoir k h , lower draw-down afforded by long horizontal wells and compression at the Shearwater platform. Subsurface uncertainties prior to development were considerable and the ‘appraisal through development’ strategy has demonstrated that success is achievable through meticulous planning and scenario analysis.

Successful sidetracking of a well onshore Germany by integration of 3D vertical seismic profiling technology – a case study

ABSTRACTThe exploration for and exploitation of deep Lower Rotliegend gasfields onshore in North Germany often suffers from poor surface seismic imaging. This is owing to the depth of the reservoirs and a thick and complex Zechstein salt overburden. RWE Dea conducted a 3D vertical seismic profile (VSP) survey in a low‐performing production well after the borehole was plugged near total depth. Our main objective was to improve the seismic image of the reservoir zone in the vicinity of the well to determine a new landing point for a planned sidetrack. Because acquisition was in a densely populated and also partially environmentally protected area, there were surface restrictions concerning source deployment. Additionally, due to the complex geological setting, we conducted two 2D VSP field tests and thorough pre‐survey modelling to achieve the best results in terms of seismic imaging, environmental impact and reasonable cost. Deformation bands in the drill core suggest that the initial well was drilled close to a major fault, which was regarded as the main reason for the disappointing production rate. Therefore, we put special emphasis on fault detection in our processing and interpretation. Our interpretation approach used an enhanced structural mapping workflow that helped to design a sidetrack. When the sidetrack was drilled two years later, it ended up being one of the most productive wells in the field.

The Vesta oil and gas field, Vulcan Sub-basin, Timor Sea, Australia

The Vesta oil and gas field is located in the Swan Graben of the Vulcan Sub-basin. The structure consists of a number of separate tilted fault blocks located on a northwest-trending accommodation zone that forms a high, separating the southeast-dipping half-graben of the Swan Graben North from the northwest-dipping half-graben of the Swan Graben South. Drilled in 2005, Vesta–1 intersected a 17 m thick oil-bearing slope-fan sandstone of the Late Jurassic Elm Sandstone in the Lower Vulcan Formation. Drill-stem testing flowed oil and gas and indicated that the reservoir is normally pressured surrounded above and below by over-pressured claystone. In 2007, Vesta–2 intersected gas-bearing sandstone in a separate fault compartment. Understanding the geometry of the hydrocarbon-bearing Elm Sandstone reservoir has proved a challenge due to the very poor 3D seismic imaging, the variable sandstone thickness and quality, and abundant evidence of thin steeply-dipping injected sandstones above and below the main reservoir sandstone. The Lower Vulcan and Upper Vulcan Formation claystone provides the vertical and lateral seal for the Elm Sandstone. This thick seal has protected the Vesta oil and gas accumulations from the effects of the Late Tertiary tectonism, which had a significant effect on the integrity of the palaeo-oil filled closures on the adjacent Eclipse Trend. Three phases of hydrocarbon charge of the Vesta structure have been identified with oil-source correlation indicating a Lower Vulcan Formation marine source. The source interval intersected in Vesta–1 is presently post-mature, with oil and gas generation associated with high heat flow in the Late Jurassic. Expulsion of hydrocarbons from the source was most likely compaction-driven, with gas expulsion in the Early Cretaceous, and oil expulsion much later with increasing hydrocarbon saturation.

High-resolution reservoir characterization by seismic inversion with geological constraints

Fluvio-deltaic sedimentary systems are of great interest for explorationists because they can form prolific hydrocarbon plays. However, they are also among the most complex and heterogeneous ones encountered in the subsurface. Reservoirs in clinoform systems are difficult to characterize because they show two main types of complexity: complex sedimentology and poor seismic imaging. The former is due to complex internal architecture with many small sedimentary elements often at a sub-seismic scale. Poor seismic imaging occurs because the internal layers of the clinoform often do not differ much in their acoustic properties, in addition, they have thicknesses that are below the vertical resolution of seismic data, and therefore such features do not show up very well on seismic images. Obviously, the most unfavorable situation occurs when both conditions interact. The static model of a fluvio-deltaic (clinoform) reservoir is extremely important because it plays a critical role in the field development planning. There are many ways to build a static model but the most effective way is by integrating seismic and well data through the construction of an acoustic impedance model by inversion of seismic data within a sequence stratigraphic framework. There are several reasons to integrate well-log data into the inverse process in the reservoir characterization workflow, such as the integration of different sources of information in a common earth model, the estimation of the seismic distortion (also known as the wavelet filter), etc. In addition, the low vertical resolution of seismic data is an important motivation to integrate well-log information into the inverse process and thereby complement the relatively dense horizontal coverage of seismic data with high-resolution borehole data (Van Riel and Mesdag, 1988; Van Riel and Pendrel, 2000; Van Riel, 2000; Bosch et al., 2009). Another potential benefit of seismic inversion is the ability to incorporate structural and stratigraphic information of the reservoir in order to differentiate between similar mathematical solutions on the basis of their geological viability. We present two different inversion approaches for poststack, time migrated seismic data and apply them to a clinoform sequence in the North Sea. Both inversion methods are not fully 2D, but more than a series of independently processed 1D inversions. To stress the enforced continuity along the geological structure, we use the name pseudo 2D inversion. The methods use well data as a priori constraints but differ in the way they incorporate structural information. One method uses a discrete layer model from the well that is then propagated laterally along the clinoform layers, which are modeled as sigmoids. The second method uses a constant sampling rate from the well data and employs horizontal and vertical regularization parameters for lateral propagation. Both methods obtain an acoustic impedance image with a high level of detail. The first method has a low level of parameterization embedded in a geological framework and is computationally fast. The second method has a much higher degree of parameterization but is flexible enough to detect deviations in the geological settings of the reservoir, however there is no explicit geological significance and it is computationally much less efficient. Forward seismic modeling of the two inversion results indicates a good match of both methods with the actual seismic data. The methods are especially considered to be useful when seismic data alone do not reveal the actual detailed reservoir architecture, which can be the case either because of their low vertical resolution or exceedingly thin layering.

Accommodation zones and tectono-stratigraphy of the Gulf of Suez, Egypt: A contribution from aeromagnetic analysis

ABSTRACT This paper starts with an up-to-date literature review of the pre-rift, syn-rift and post-rift stratigraphy of the Gulf of Suez. The geometry and depth of the Proterozoic basement is not generally known due to poor seismic images below the Upper Miocene evaporites (including massive rock salt) and clastics. The pre-rift Paleozoic to Early Oligocene succession shows that several local basins (c. 10s of km in extent) occur in the Gulf, with thick sedimentary sections (e.g. c. 3,000 m for Paleozoic and 1,000 m for Jurassic and Lower Cretaceous). The origin and distribution of these basins is not well understood and the presence of similar pre-rift basins in the southern Gulf is not known to occur. The syn-rift Late Oligocene to Middle Miocene and post-rift Late Miocene – Pliocene successions are widely distributed within the rift basin and reach a thickness in excess of 5,000 m. In order to visualize the grain and relative relief of the Proterozoic basement, a series of aeromagnetic images are shown in this paper. The images include Total Magnetic Intensity (TMI), Reduced-to-Pole (RTP), filtered regional and structural RTP, and Second Vertical Derivative (SVD). The paper also shows a three-dimensional visualization image of the magnetic basement that highlights the distribution of the basins in the Gulf. The magnetic lows do not generally trend along the Suez (NNW-trending Clysmic) Fault, but instead show highly variable orientations attributed to a complex pattern of criss-crossing faults. In particular, two areas were selected to interpret the geometry and depth of the basement. The first area covered the northern Zaafarana Accommodation Zone and involved modeling five aeromagnetic profiles. The Zone was interpreted as an EW-trending basement plateau bounded by basins that are c. 8,000 m deep. The second modeled area (four profiles) covered the southern Morgan Accommodation Zone. This zone was interpreted as an ENE-trending plateau of similar relief to the Zaafarana Zone. The Morgan Zone is terminated in the eastern Gulf by the 8,000-m-deep Morgan Basin. The very deep basins surrounding the two plateaus may contain both pre-rift and syn-rift source rocks, from which the numerous surrounding petroleum fields were sourced.

Model-Based Identification of the Base of the Gas Hydrate Stability Zone in Multichannel Reflection Seismic Data, Offshore Costa Rica

Along the pacific margin offshore Costa Rica the Bottom Simulating Reflector (BSR) shows a patchy occurrence in 2-D seismic reflection profiles. The reason for this can be either lack of free gas beneath parts of the gas hydrate stability zone (GHSZ) or poor seismic imaging. We compare far to near offset stacked common midpoint sections to reduce imaging ambiguity utilizing the amplitude variation with offset effect and thus successfully distinguish BSRs from regular sediment reflections. In combination with 1-D modeling of the base of the GHSZ we disqualify or qualify reflections in the predicted depth range as BSR. Additionally we calculate the heat flow and compare it with an analytical solution to detect thermal anomalies, for example, at the frontal prism. The higher confidence in BSR depths based on the far offset stacks and heat flow calculations allows further analyses on gas hydrate concentration estimates and tectonic evolution of the margin.

Downdip-Oil Potential for an Onshore Abu Dhabi Petroleum System

Summary A combination of fluid-inclusion and geochemical analyses was conducted on rocks and reservoir fluids to develop an improved understanding of downdip-oil potential in a mature exploration play, onshore Abu Dhabi, UAE. Exploration for oil in the region is complicated by low-permeability carbonate reservoirs, poor seismic imaging, and complex hydrocarbon-maturation and -migration histories. In addition, a broad range of fluid properties, including gas, condensate, and high-°API oil, makes evaluation of the reservoir fluid phase difficult. In this challenging environment, geochemical and fluid-inclusion techniques are effective tools for identifying downdip oil potential from gas-cap fluids and reservoir-rock samples. Fluid-inclusion data are used to develop a hydrocarbon-emplacement history, which constrains the distribution of fluids throughout the exploration area. In some areas, undersaturated gas inclusions trapped at present-day temperatures suggest a low chance for downdip oil. Conversely, other structures contain oil inclusions that have been displaced recently by saturated gas, suggesting good potential for downdip oil. Geochemical analyses of recovered fluids were used independently to predict the likelihood of down-dip oil. These combined techniques were placed in a geologic framework to regionally risk the potential for downdip oil throughout the exploration area. This framework enables improved resource evaluation and prioritization of exploration efforts in areas of the play where a high probability of downdip oil exists.

Seeing below the basalt – offshore Faroes

ABSTRACTExploration in the basalt covered areas of the Faroes offshore has always suffered from poor seismic imaging below the basalt. Long offset 2D and 3D seismic data were acquired and a significant improvement in the seismic image below top basalt has been achieved. Deep towing of the source and receiver cables helped by extending the seismic bandwidth towards lower frequencies. Bubble‐tuned rather than conventional peak‐tuned source arrays gave little, if any, incremental benefit. The improvement in the imaging comes primarily from the approach to processing the data. High frequencies (dominantly noise) are filtered out of the data early in the processing to concentrate on the low frequency data. Careful multiple removal is important with several passes of demultiple being applied to the data using both Surface‐Related Multiple Elimination (SRME) and Radon techniques. Velocity analysis is performed as an iterative process taking into account the geological model. Reprocessing legacy 2D surveys, acquired with wide‐ranging parameters, using these processing techniques improved these datasets significantly, indicating that sub‐basalt imaging seems to be more sensitive to processing than to the choice of acquisition parameters.

DEMETER HIGH RESOLUTION 3D SEISMIC SURVEY—REVITALISED DEVELOPMENT AND EXPLORATION ON THE NORTH WEST SHELF, AUSTRALIA

The newly acquired 3,590 km2 Demeter 3D high resolution seismic survey covers most of the North West Shelf Venture (NWSV) area; a prolific hydrocarbon province with ultimate recoverable reserves of greater than 30 Tcf gas and 1.5 billion bbls of oil and natural gas liquids. The exploration and development of this area has evolved in parallel with the advent of new technologies, maturing into the present phase of revitalised development and exploration based on the Demeter 3D.The NWSV is entering a period of growing gas market demand and infrastructure expansion, combined with a more diverse and mature supply portfolio of offshore fields. A sequence of satellite fields will require optimised development over the next 5–10 years, with a large number of wells to be drilled.The NWSV area is acknowledged to be a complex seismic environment that, until recently, was imaged by a patchwork of eight vintage (1981–98) 3D seismic surveys, each acquired with different parameters. With most of the clearly defined structural highs drilled, exploration success in recent years has been modest. This is due primarily to severe seismic multiple contamination masking the more subtle and deeper exploration prospects. The poor quality and low resolution of vintage seismic data has also impeded reservoir characterisation and sub-surface modelling. These sub-surface uncertainties, together with the large planned expenditure associated with forthcoming development, justified the need for the Demeter leading edge 3D seismic acquisition and processing techniques to underpin field development planning and reserves evaluations.The objective of the Demeter 3D survey was to re-image the NWSV area with a single acquisition and processing sequence to reduce multiple contamination and improve imaging of intra-reservoir architecture. Single source (133 nominal fold), shallow solid streamer acquisition combined with five stages of demultiple and detailed velocity analysis are considered key components of Demeter.The final Demeter volumes were delivered early 2005 and already some benefits of the higher resolution data have been realised, exemplified in the following:Successful drilling of development wells on the Wanaea, Lambert and Hermes oil fields and identification of further opportunities on Wanaea-Cossack and Lambert- Hermes;Dramatic improvements in seismic data quality observed at the giant Perseus gas field helping define seven development well locations;Considerably improved definition of fluvial channel architecture in the south of the Goodwyn gas field allowing for improved well placement and understanding of reservoir distribution;Identification of new exploration prospects and reevaluation of the existing prospect portfolio. Although the Demeter data set has given significant bandwidth needed for this revitalised phase of exploration and development, there remain areas that still suffer from poor seismic imaging, providing challenges for the future application of new technologies.

Seismic prediction of prolific oil zones in carbonate reservoirs with extremely low porosity and permeability under salt

The Carboniferous reservoir in KJ oilfield is a carbonate reservoir with extremely low porosity and permeability and high-pressure. The reservoir has severe heterogeneity, is deeply buried, has complex master control factors, is covered with thick salt, all of which result in the serious distortion of reflection time and amplitudes under the salt, the poor seismic imaging, and the low S/N ratio and resolution. The key to developing this kind of reservoir is to correctly predict the distribution of highly profitable oil zones. In this paper we start by analyzing the master control factors, perform seismic-log calibration, optimize the seismic attributes indicating the lithofacies, karst, petrophysical properties, and fractures, and combine these results with the seismic, geology, log, oil reservoir engineering, and well data. We decompose the seismic prediction into six key areas: structural interpretation, prediction of lithofacies, karst, petrophysical properties, fractures, and then perform an integrated assessment. First, based on building the models of faults and fractures, sedimentary facies, and karst, we predict the distribution of the most favorable reservoir zones qualitatively. Then, using multi-parameter inversion and integrated multi-attribute analysis, we predict the favorable reservoir distribution quantitatively and setni-quantitatively to clarify the distribution of high-yield zones. We finally have a reliable basis for optimal selection of exploration and development targets.

Pre-stack depth migration and velocity model building for imaging in the North Sea

One of NAM’s Rotliegend prospects is situated at c . 2800 m below a major wrench-fault zone. Large lateral impedance contrasts across the faults are believed to be one of the main causes for the poor seismic imaging at the Rotliegend objective. Three-dimensional pre-stack depth migration (PSDM) seismic processing using hard-layer model updating was applied to the data in 2000. The results showed a significant improvement compared to previous post-stack depth migration (post-SDM) results and the original post-time migration processing. Despite these improvements in data quality, ambiguity still remained over the exact seismic pick of the top Rotliegend objective at the prospect. There was a clear case to optimize further the data quality at the prospect because only the high case interpretation proved to be economically viable. A review of the 2000 PSDM processing concluded that there was still considerable scope for further improvement of the data by fine-tuning the velocity model near the complex re-activated fault systemas well as by detailed pre-stack data analysis. It was decided to embark on another 3D PSDM iteration to improve the structural definition of the prospect by using the latest available velocity modelling tools within Shell. The selected technique is based on non-layer constrained RMO measurements, followed by a velocity model inversion. This approach allows full and flexible interaction with the pre-stack data, a pre-requisite for proper velocity modelling in complicated wrench-fault systems.

Near-salt deformation in La Popa basin, Mexico, and the northern Gulf of Mexico: A general model for passive diapirism

Strata adjacent to exposed diapirs in La Popa basin, northeastern Mexico, comprise stacked halokinetic sequences consisting of unconformity-bounded packages of thinned and rotated strata cut by radial faults. Deformation results from shallow drape folding over the flanks of the rising diapirs and not from deep drag folding in diapir-peripheral shear zones. Subsurface analogs from the Gulf of Mexico have diapir-flanking geometries ranging from similar, wide zones of upturned and thinned strata to undeformed, constant-thickness strata. Subhorizontal salt tongues display little subsalt deformation and thinning.We propose a general model for passive diapirism and flank deformation that includes (1) gradually varying salt-flow rates, (2) superposed episodic sedimentation that results in changing bathymetric relief, (3) rotation of near-surface strata as salt inflates relative to the adjacent basin, (4) failure and erosion of strata in the steepening bathymetric halo, and (5) bedding-parallel slip surfaces that converge on unconformities and onlap surfaces. A primary factor influencing flank geometries is the width of the bathymetric high extending beyond the diapir edge. This is largely dependent on the thickness of the halokinetic sequence onlapping the diapir, which in turn is controlled mostly by the interplay between salt inflation/deflation rates and sedimentation rates. Other factors include the amount of concurrent shortening, which produces a wider but less intense zone of deformation, and the position on the scarp of salt breakout and extrusion.Our model is important for exploration and production in diapir-flank and subsalt settings because of its implications for trap size and geometry, reservoir distribution, trap compartmentalization and pressure seals, and hydrocarbon charge. It can help in explaining complex and enigmatic well data and in better assessing risk in areas of poor seismic imaging.

Velocity/interface model building in a thrust belt by tomographic inversion of global offset seismic data

Between September and November 1999, two test seismic lines were recorded in the southern Apennine region of southern Italy using the global offset technique, which involves the acquisition of a wide offset range using two simultaneously active seismic spreads. One consisted of a symmetrical spread moving along the line, with geophone arrays every 30 m and a maximum offset of 3.6 km. The other one consisted of fixed geophone arrays every 90 m with a maximum offset of 18 km. This experimental acquisition project was carried out as part of the enhanced seismic in thrust belt (ESIT) research project, funded by the European Union, Enterprise Oil and Eni‐Agip. An iterative and interactive tomographic inversion of refraction/reflection arrivals was carried out on the data from line ESIT700 to produce a velocity/interface model in depth, which used all the available offsets. The tomographic models allowed the reconstruction of layer interface geometries and interval velocities for the target carbonate platform (Apula) and the overburden sequence. The value of this technique is highlighted by the fact that the standard approach, based on near‐vertical reflection seismic and a conventional processing flow, produced poor seismic images in both stack and migrated sections.

A Novel Approach to the Exploration of the Southern Apennines, Italy: Geological Models and Oil Discoveries: ABSTRACT

The last, successful, exploration phase in the Southern Apennines started in the early eighties after small but encouraging discoveries of oil in the carbonates of the Apulian Platform foreland, in the Basilicata region. The poor seismic definition of the top of this unit and the extremely poor seismic imaging of the overlying {open_quotes}allochthonous{close_quotes}, forced the oil companies active in the area to build geological models in order to constrain the seismic interpretation. The main units within the proposed simplified depositional and structural framework are represented by two carbonate platforms separated by a seaway: the Apenninic Platform to the West, the Apulian Platform to the East and the Lagonegro Basin in between. Due to the Tirrenian Sea spreading and/or subduction of the Adria Plate, the Apenninic Platform, Lagonegro basin-fill and related syntectonic sediments were thrusted over the Apulian Platform and its overlying Pliocene foredeep. According to the proposed model, the Apulian Platform has been differentiated into three main structural domains. These are interpreted as resulting from the decreasing horizontal compressive stress from west to east. All these domains are proved oil producer. The geological modelling of a formerly unknownly structural trend developed during the compressive phases represented the key for majormore » oil discoveries performed at the end of the eighties. The reservoir in this area, homogeneous in first approximation, is characterised by high fracturing, related to the several tectonic regimes that affected the Apulian Platform, moderate matrix and vuggy porosity and several hundreds of meters of oil column.« less