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Abstract The Thunder Horse Field targets Middle Miocene deepwater turbiditic reservoirs. Despite of being prolific, the mapping of the ~180 m thick, partly amalgamated reservoir sandstones is challenging. Seismic quality is reduced by the presence of salt structures. The salt overburden and high formation pressure requires the use of heavy mud weights and oil-based drilling fluids, which limit the resolution and interpretation potential of borehole image logs (BHI). Halokinetic movements caused significant post-depositional deformation of the already complex gravity- driven sediment stack and the reservoir beds drape against an E-W oriented salt wall. Consequently, the assessment and removal of the structural dip component is not trivial and the evaluation of paleo-transport directions is considerably more complicated compared to undisturbed deepwater reservoirs. The intention of this paper is to bring the main results from Henry et al. (2018) into context with the eigenvector methodology from Ruehlicke et al. (2019) and to emphasize its value for reservoir characterization.
Summary The ability of geochemistry techniques in reservoir-continuity studies has already been proved. Most of the traditional methods mainly involve analyzing nonpolar components of crude oil and overlooking polar components. Despite valuable information obtained from nonpolar components, these compounds are sometimes affected by various alterations or likely provide only a piece of the reservoir-compartmentalization puzzle. In this paper, an integrated geochemical approach that uses nonpolar (i.e., saturates and aromatics) and polar (i.e., asphaltenes) components of crude oil was performed to evaluate reservoir continuity efficiently. The Shadegan Oil Field in the Dezful Embayment in southwest Iran was investigated for reservoir-continuity studies to show the efficiency of this proposed technique. The selected interparaffin peak ratios and light hydrocarbons [the C7 oil correlation star diagram (C7CSD)] from whole-oil gas chromatography (GC) (WOGC) chromatograms were used to obtain oil fingerprints from the nonpolar fraction of crude oils. The Fourier-transform infrared (FTIR) spectroscopy of asphaltenes was applied to obtain oil fingerprints from the polar fraction of crude oils. The pairwise comparison of studied wells by each technique was summarized in a similarity matrix with green, yellow, and red colors to show connectivity, limited connectivity, and disconnectivity according to oil fingerprints. Finally, a compartmentalization model was prepared from the integrated results of different techniques considering the worst-case scenarios regarding the occurrence or absence of reservoir continuity when relying on individual methods for the studied field. Results show that the Shadegan Oil Field comprises three zones in the Asmari Reservoir and two zones in the Bangestan Reservoir. Reservoir-engineering data, including pressure data and pressure/volume/temperature (PVT), completely corroborated the obtained results from the geochemical approach. The consistency of results suggested FTIR oil fingerprinting of asphaltene as a novel and straightforward technique, which is a complementary or even alternative method with respect to previous geochemical methods.
Summary Wells are sometimes deformed due to geomechanical shear slip, which occurs on a localized slip surface, such as a bedding plane, fault, or natural fracture. This can occur in the overburden above a conventional reservoir (during production) or within an unconventional reservoir (during completion operations). Shear slip will usually deform the casing into a recognizable shape, with lateral offset and two opposite-trending bends, and ovalized cross sections. Multifinger casing caliper tools have a recognizable response to this shape and are especially useful for diagnosing well shear. Certain other tools can also provide evidence for shear deformation. Shear deformations above a depleting, compacting reservoir are usually due to slip on bedding planes. They usually occur at multiple depths and are driven by overburden bending in response to reservoir differential compaction. Shear deformations in unconventional reservoirs, for the examples studied, have been found to be caused by slip on bedding planes and natural fractures. In both cases, models, field data, and physical reasoning suggest that slip occurs primarily due to fluid pressurization of the interface. In the case of bedding plane slip, fracturing pressure greater than the vertical stress (in regions where the vertical stress is the intermediate stress) could lead to propagation of a horizontal fracture, which then slips in shear. Introduction Well shear is defined as deformation of the well (usually observed as casing deformation) due to localized geomechanical shear slip that intersects the well. Typical slipping surfaces are bedding planes, faults, and natural fractures. Shear deformations in the overburden above compacting (or inflating) conventional reservoirs, and also at the reservoir/caprock interface, have been recognized for decades. Excellent overviews of these issues can be found in Dusseault et al. (2001) and Bruno (2002). Well shear associated with conventional reservoirs typically occurs only after production operations begin, and in the case of a depleting reservoir, it is often not until many years later. Unconventional reservoirs also experience casing deformations. These deformations can occur anywhere along the lateral, although many are observed near the heel. Importantly, they occur while completion operations are underway. While there are nongeomechanical causes for some of these observed deformations, there is a growing awareness that many of these deformations are due to geomechanical shear slip (Casero and Rylance 2020).
If pore volume contraction contributes prominently to overall expansion while the reservoir is saturated, then the reservoir is classified as a compaction drive. Compaction drive oil reservoirs are supplemented by solution gas drive if the reservoir falls below the bubblepoint; they may or may not be supplemented by a water or gas cap drive. Compaction drives characteristically exhibit elevated rock compressibilities, often 10 to 50 times greater than normal. Rock compressibility is called pore volume (PV), or pore, compressibility and is expressed in units of PV change per unit PV per unit pressure change. Rock compressibility is a function of pressure.
Rachapudi, R. V. (ADNOC Onshore) | Al-Jaberi, S. S. (ADNOC) | Al Hashemi, M. (ADNOC) | Punnapala, S. (ADNOC Onshore) | Alshehhi, S. S. (ADNOC Onshore) | Talib, N. (ADNOC Onshore) | Loayza, A. F. Jimenez (ADNOC Onshore) | Al Nuimi, S. (ADNOC Onshore) | Elbekshi, A. (ADNOC Onshore) | Quintero, F. (ADNOC Onshore) | Yuliyanto, T. (ADNOC Onshore) | Abd Rashid, A. Bin (ADNOC Onshore) | Alkatheeri, F. Omar (ADNOC Onshore) | Gutierrez, Daniel (ADNOC Onshore) | Chehabi, W. (Fishbone A/S) | Hussain, Ali Ba (ADNOC Onshore)
Productivity enhancement of tight carbonate reservoirs (permeability 1-3 md) is critical to deliver the mandated production and to achieve the overall recovery. However, productivity improvement with conventional acid stimulation is very limited and short-lived. Tight reservoirs development with down spacing and higher number of infill wells can increase the oil recovery. Nevertheless, poor vertical communication (Kv/Kh < 0.5) within the layered reservoir is still a challenge for productivity enhancement and needs to be improved.
First time successful installation of fishbone stimulation technology at ADNOC Onshore targeted establishing vertical communication between layers, in addition to maximizing the reservoir contact. Furthermore this advanced stimulation technology connects the natural fractures within the reservoir, bypasses near well bore damage and allows the thin sub layers to produce. This technology requires running standard lower completion tubing with Fishbone subs preloaded with 40ft needles, and stimulation with rig on site. This paper presents the case study of the fishbone stimulation technology implemented at one of the tight-layered carbonate reservoir.
A new development well from ADNOC Onshore South East field was selected for implementation of this technology. The well completion consisting of 4 ½ liner with 40 fishbone subs was installed, each sub containing four needles at 90 degrees phasing capable of penetrating the reservoir up to 40 ft. While rig on site, acid job was conducted for creating jetting effect to penetrate the needles into the formation. Upon completion of jetting operation, fishbone basket run cleaned the unpenetrated needles present in the liner to establish the accessibility up to the total depth. Overall, application of this technology improved the well production rate to 1600 BOPD compared to 400 BOPD of production from nearby wells in the same PAD and reservoir. In addition the productivity of the candidate well improved by 2.5 times with respect to near-by wells in the same PAD. Currently, long-term sustainability testing preparation is in progress. This paper provides the details of candidate selection, completion design, technology limitations, operational challenges, post job testing and lessons learned during pilot implementation. In summary, successful application of this technology is a game changer for tight carbonate productivity enhancement that improves the overall recovery along with optimizing the drilling requirements. Currently, preparation for implementation of 10 pilots in one of the asset at ADNOC Onshore fields is in progress.
Soni, Kishan (Petroleum Affairs Division, Department of Communications, Climate Action and Environment, Ireland/ iCRAG, School of Earth Sciences, University College Dublin) | Manzocchi, Tom (iCRAG, School of Earth Sciences, University College Dublin) | Haughton, Peter (iCRAG, School of Earth Sciences, University College Dublin) | Carneiro, Marcus (iCRAG, School of Earth Sciences, University College Dublin)
Oil reservoirs hosted in deep-water slope channel deposits are a challenge to manage and model. A six-level hierarchical arrangement of depositional elements within slope channel deposits has been widely recognized, and dimensional (width and thickness) and stacking (amalgamation ratio and volume fraction) data have been acquired from published studies to establish parameters for a representative slope channel system. A new static modelling workflow has been developed for building models of channel complexes based on a simplified hierarchical scheme using industry-standard object-based modelling methods and a new plugin applying the compression algorithm. Object-based modelling using the compression algorithm allows for independent input of volume fractions and amalgamation ratios for channel and sheet objects within a hierarchical modelling workflow. A base-case channel complex model is built at the resolution of individual sandstone beds, conditioned to representative dimensional and stacking characteristics of natural systems. Inclusion of explicit channel axis and margin regions within the channels governs bed placement and controls inter-channel connectivity where channels are amalgamated. The distribution of porosity and permeability within these beds mimics grain-size trends of fining in the vertical and lateral directions. The influence of various geological parameters and modelling choices on reservoir performance have been assessed through water-flood flow simulation modelling. Omission of the compression method in the modelling workflow results in a three-fold increase in oil recovery at water-breakthrough, because the resultant unnaturally high amalgamation ratios result in overly-connected flow units at all hierarchical levels. Omission in the modelling of either the bed-scale hierarchical level, or of the axial and marginal constraints on the bed placement in models that do include this level, results in a two-fold increase in oil recovery at water-breakthrough relative to the base-case, because in these cases the channel-channel connections are too permissive.
Shoup, Robert Charles (Subsurface Consultants & Associates, LLC) | Jong, John (JX Nippon Oil & Gas Exploration Malaysia Ltd) | Barker, Steven M. (JX Nippon Oil & Gas Exploration Malaysia Ltd) | Khamis, Mohd Asraf (JX Nippon Oil & Gas Exploration Malaysia Ltd)
The high cost of deepwater developments and the limited reach from offshore platforms requires operators to have a good understanding of the expected reservoir compartmentalization in the field before the first well is drilled. Deepwater reservoirs can be compartmentalized both structurally and stratigraphically. This paper will briefly address the structural compartmentalization and discuss the stratigraphic baffling that occurs in deepwater depositional settings.
The distribution of reservoir facies within deepwater depositional settings is well-understood from outcrop studies, seismic facies mapping, and exploration and development drilling. This understanding can be used to predict where stratigraphic compartmentalization is likely to occur.
Channel levee complexes and crevasse splays are deposited principally on the slope. Deposits are typically characteristic of a meandering river. Fluid flow in channel levee complexes occurs principally along the channel thalweg. Small-scale slumps within the channel levee complex may baffle flow from the levee into the channel thalweg. Crevasse splays are deposited when there has been a breach in the levee. The reservoir distribution in a crevasse splay deposit is characteristic of a river-dominated delta. Fluid flow in a crevasse splay will be generally toward the channel breach.
Submarine fans are deposited in structurally restricted basins on the slope or on the basin floor. Interbedded shales baffle vertical fluid flow, with lower or distal lobe deposits more vertically baffled than upper lobe deposits. Lateral baffling of fluid flow in lower fan deposits is generally caused by small faults. In the middle to upper fan lateral erosional channels as well as small faults can baffle lateral fluid flow.
Gorges or canyons are incisional events. They can occur anywhere on the system but are more common and more deeply incised in the upper fan and slope. The reservoir facies that fill the gorge are typically sand-prone, with sand more prevalent in the lower gorge-fill.
Debris flows and slumps can occur anywhere in the system. Since reservoir connectivity within the debris flow is minimal, these should not be targeted for development.
Kiyashchenko, Denis (Shell International Exploration and Production Inc.) | Wong, Wai-Fan (Shell Exploration and Production Company) | Cherief, Dalila (Sarawak Shell Berhad) | Clarke, Dan (Shell UK Exploration and Production Limited) | Duan, Yuting (Shell International Exploration and Production Inc.) | Hatchell, Paul (Shell International Exploration and Production Inc.)
Time-lapse seismic monitoring is a proven technology for increasing ultimate recovery. However, small 4D changes in stiff reservoir rocks masked by noise poses limits to its use. We share our experience with tracking fluid injection signals in a Brazilian pre-salt carbonate reservoir with time-lapse OBN. The development of novel methods to characterize water velocity variations and application of advanced time-lapse matching has helped to maximize the repeatability. This new workflow reveals meaningful 4D amplitude and time-shift signals, which further consolidates 4D monitoring as a viable surveillance technique in pre-salt carbonates and similar challenging settings. Presentation Date: Wednesday, October 14, 2020 Session Start Time: 9:20 AM Presentation Time: 9:20 AM Location: Poster Station 2 Presentation Type: Poster
Time-lapse (4D) seismic is an essential tool for monitoring the subsurface in and around producing hydrocarbon or CO2 storage reservoirs. The seismic time-shifts, in the reservoir as well as in the overburden, depend on the stress changes and strains induced by the subsurface depletion or the inflation. In this study, geomechanical modeling is used to quantify the stress changes and strains in a synthetic model for the formations in and around a depleting reservoir. The estimated strains are coupled to experimentally determined strain sensitivities for P-wave velocities of shales, to predict time-shifts in the surroundings of the reservoir. The modeling shows that the stiffness contrast between the reservoir and its surroundings plays an important role in controlling the stress and strain changes in the subsurface. The strain sensitivity of the vertical P-wave velocity in the surroundings is significant and is rapidly increasing in magnitude with the proximity to the reservoir. Correspondingly, the time-shifts are increasing with depth in the overburden and decreasing with depth in the underburden. In this study, the time-shifts of the surroundings are changing most between the depths corresponding to one and two reservoir radii above and below the reservoir. Presentation Date: Wednesday, October 14, 2020 Session Start Time: 8:30 AM Presentation Time: 11:00 AM Location: 360A Presentation Type: Oral