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Exploring the major controlling factors on resistivity depth trends in sedimentary basins is an interesting subject from both scientific and commercial perspectives. Our study aims to develop rock-physics based resistivity modeling methods and workflows that can be applied in any given sedimentary basin, through xS-integration of quantitative geological knowledge linking lithology with in-situ subsurface conditions such as temperature and salinity. In this work, we present a workflow that utilizes the Waxman-Smits model and existing wells in the target basin to perform a prediction of the horizontal resistivity depth trends at any appointed location in the basin. The workflow will be demonstrated using well data from the Norwegian Barents Sea; the predictability of our method will be presented through comparison against a real horizontal resistivity log measurement.
The methodology and workflow are general, in principle they can be applied to sedimentary basins around the world. So far, we have tested the workflow and compared the predicted horizontal resistivity depth trends against log resistivity responses acquired in wellbores across the Norwegian Continental Shelf (NCS) — the North Sea, the Norwegian Sea and the Barents Sea. Our predictions capture the overall resistivity depth trends successfully in all selected wells within each individual basin across the shelf. The predicted resistivity depth profiles can be used as a priori models in controlled source electromagnetic (CSEM) data inversion schemes, or to provide ‘what if’ scenarios as part of the reservoir property analysis and risk assessment in an exploration phase.
Presentation Date: Tuesday, October 16, 2018
Start Time: 1:50:00 PM
Location: Poster Station 22
Presentation Type: Poster
Both ordinary Gassmann model, modifications to it and This paper describes a new and patented workflow for other rock physics models that allows for variations in fluid performing fluid substitution in porous rocks. The method properties, can be included in the ROFS workflow to is called rock physics fluid substitution (ROFS), and can be predict elastic properties and density for a rock with applied in all kind of rocks that can be described by rock changes in pore fluid.
Keogh, William (University of Leeds, Leeds) | Charpentier, Thibaut (University of Leeds, Leeds) | Eroini, Violette (Statoil ASA) | Olsen, John Helge (Statoil ASA) | Nielsen, Frank Møller (Statoil ASA) | Baraka-Lokmane, Salima (TOTAL) | Ellingsen, Jon Arne (Conoco Phillips) | Bache, Oeystein (Conoco Phillips) | Neville, Anne (University of Leeds, Leeds)
Deposition of inorganic scale on downhole completion equipment contributes to significant downtime and loss of production within the oil and gas industry. High temperature/high pressure (HT/HP) fields have reported build-up of lead sulfide (PbS) scale as a consequence of reservoir souring. This paper reports on the design of an experimental rig allowing diffusion of H2S into a scaling brine under dynamic environments. Multiphase conditions induced by introduction of a light distillate within the system were used to create an emulsion in order to reflect more accurately the scaling process occurring within sour systems. The results showed that the presence of an oil phase within the system caused the lead sulfide nano crystals to reside at the oil- water (o/w) interface; increasing surface build-up propensity through an adhesion process. Performance of a range of coatings for potential application in oilfield environments was determined through gravimetric measurements and microscopy techniques and the wettability of surfaces was shown to have a significant influence on the degree of lead sulfide deposition in a multiphase system.
Stipanicev, Marko (Schlumberger) | Birketveit, Øystein (Schlumberger) | Kvalheim, Vibeke Hatloe (Schlumberger) | Hoshowski, Jody (Schlumberger) | Lioliou, Maria G. (Statoil ASA) | Rindalsholt, Tore (Statoil ASA)
Production of mature oil and gas fields often requires managing the related risks and limitations imposed by reservoir souring upon assets and production integrity. The corrosive effect of H2S in combination with export gas H2S specifications, escalates operational expenditure (OPEX). The treatment of produced fluids can, in a worst-case scenario, reduce production output if the appropriate toolbox for managing elevated H2S levels are not in place. Herein presented is a case where production from a subsea field was restricted by the amount of H2S produced due to constrains in the topside gas processing system. The objective of the work was to remove significant amounts of H2S from produced fluids during transit via subsea production pipelines; scavenging H2S during multiphase flow, whilst maintaining corrosion and scale inhibition.
A novel multiphase H2S scavenger was incorporated into the incumbent subsea corrosion inhibitor. The work included identification of suitable multiphase H2S scavenging chemistry, tailoring of the multipurpose chemical to retain corrosion inhibition properties, and confirmation that this new chemistry did not deleteriously impact performance of other production chemicals used nor the production process itself. The experimental development work depicted ethylenedioxy(dimethanol) (EDDM) as capable of delivering suitable H2S scavenging capacity while maintaining corrosion inhibitor component performance. The qualification work supported a full-scale field test that demonstrated suitability of the new multipurpose chemical.
The new environmentally acceptable combined formulation of corrosion inhibitor and H2S scavenger enables higher production rates from the subsea field without modification of the chemical injection system or topside process system.
Flexible pipes used in oil and gas production are composed of densely packed steel wires enclosed in an annulus confined by inner and outer thermoplastic sheaths (pressure barriers). Hydrocarbons, water, CO2 and H2S from the bore diffuse through the inner sheath and form a corrosive environment in the confined space between the sheaths. A large steel surface to water volume ratio leads to rapid accumulation of dissolved corrosion products and precipitation of protective iron carbonate (FeCO3) films. Low corrosion rates (<0.01 mm/y) are usually experienced in the field and have been reported in a number of experiments where fresh abraded steel surfaces are exposed in environments with high concentration of dissolved corrosion products.
This paper presents results from experiments where the protective properties of iron carbonate films were studied when the armour steel was exposed to oxygenated water for some time, i.e. simulation of accidental ingress of aerated seawater into the annulus. The protective iron carbonate film broke down during the O2 exposure and was converted to a porous film of iron oxides and iron carbide. The porous film gave poor protection and the corrosion rate increased from less than 0.01 mm/y to more than 1 mm/y during the O2 exposure. The presence of the porous film disturbed the reformation of protective iron carbonate films when outer sheath repair was simulated by removing the O2 source. It was shown that reformation of protective films was strongly dependent on the duration of the O2 exposure and on the corrosion history of the steel surface prior to the O2 exposure. The experiments were performed at atmospheric pressure, at 25 and 60 °C and with a CO2 partial pressure of 0.2 bar. The paper discusses the experimental results, the experimental approach and the challenges of simulating the annulus conditions in small scale lab experiments.
Sedimentary methane hydrates contain a vast amount of untapped natural gas that can be produced through pressure depletion. Several field pilots have proven the concept with days to weeks of operation, but the longer-term response remains uncertain. This paper investigates parameters affecting the rate of gas recovery from methane hydrate-bearing sediments. The recovery of methane gas from hydrate dissociation through pressure depletion at constant pressure was studied at different initial hydrate saturations in cylindrical sandstone cores. Core-scale dissociation patterns were mapped with magnetic resonance imaging (MRI) and pore-scale dissociation events were visualized in a high-pressure micromodel. Key findings from the gas production rate analysis are: 1) The maximum rate of recovery is only to a small extent affected by the magnitude of the pressure reduction below the dissociation pressure. 2) The hydrate saturation directly impacts the rate of recovery, where intermediate hydrate saturations (0.30 – 0.50) give the highest initial recovery rate. These results are of interest to anyone who evaluates the production performance of sedimentary hydrate accumulations and demonstrate how important accurate saturation estimates are to predict both the initial rate of gas recovery and the ultimate recovery efficiency.
Controlled buckles in subsea pipelines exposed to expansion forces can be triggered by various methods such as snake-lay, installing sleepers/berms, or the residual curvature method (Statoil patent, 2002). The latter (RCM) is relatively new but is gaining popularity and has now been successfully applied to four pipeline projects. During installation, short sections of residual curvature in the vertical direction are introduced to the pipeline, and these introduce a rotationally destabilising effect. Different as-installed configurations may result: the residual curvature section may rotate over into the horizontal plane on the seabed; or it may remain vertical. If it remains vertical, self-weight can cause the pipe to slump down onto the seabed and become straightened.
When applying the RCM, it is preferable for the pipeline to rotate approximately 90° during installation, for the purposes of reducing the critical buckling force and avoiding the introduction of artificial free-spans at the residual curvature sections. Therefore it is important to analyse the rotation behaviour at the design stage. Rotational fixedness at the lay-vessel and resistance from soil friction act to restrain the pipe, but experience from, for example Statoil’s Skuld Pipeline Project, indicates that the residual curvature sections tend to rotate. Recent analysis work on rotation during installation of the Johan Sverdrup in-field pipelines is presented. The shallower depth reduced the tendency to rotation compared to reference projects, and the analysis results were used to guide installation settings to assure a robust rotation response during lay.
Subsea pipelines may twist during installation from a lay vessel due to mechanisms that generate torque. This leads to rotation of the pipe cross section. The torque can be generated by, for example route curves, or the weight of inline structures. The rotation phenomenon may be characterised as an instability, as in the case of top-heavy structures which only generate a torque when their centre of gravity becomes laterally displaced from the axis of the pipe. Another type of rotational instability is that caused by plastic hogging bending in the pipeline. This can originate in, for example, a mild constant plastic straining on an S-lay barge’s stinger, or a purposeful manipulation of the straightener settings during reel-lay. Since the suspended pipe between the lay vessel and the touchdown point (TDP) is dominated by sagging, there can be a net decrease in potential energy if the plastic bending becomes rotated to better match the imposed sagging bending (see Bynum & Havik, 1981).
Vik, Bartek (Uni Research, CIPR) | Kedir, Abduljelil (Uni Research, CIPR) | Kippe, Vegard (Statoil ASA) | Sandengen, Kristian (Statoil ASA) | Skauge, Tormod (Uni Research, CIPR) | Solbakken, Jonas (Uni Research, CIPR) | Zhu, Dingwei (Uni Research, CIPR)
Polymer injection for viscous oil displacement has proven effective and gained interest in the recent years. The two general types of EOR polymers available for field applications, synthetic and biological, display different rheological properties during flow in porous media. In this paper, the impact of rheology on viscous oil displacement efficiency and front stability is investigated in laboratory flow experiments monitored by X-ray.
Displacement experiments of crude oil (~500cP) were performed on large Bentheimer rock slab samples (30×30cm) by secondary injection of viscous solutions with different rheological properties.
Specifically, stabilization of the aqueous front by Newtonian (glycerol and shear degraded HPAM) relative to shear thinning (Xanthan) and shear thickening (HPAM) fluids was investigated.
An X-ray scanner monitored the displacement processes, providing 2D information about fluid saturations and distributions. The experiments followed near identical procedures and conditions in terms of rock properties, fluxes, pressure gradients, oil viscosity and wettability.
Secondary mode injections of HPAM, shear-degraded HPAM, xanthan and glycerol solutions showed significant differences in displacement stability and recovery efficiency. It should be noted that concentrations of the chemicals were adjusted to yield comparable viscosity at a typical average flood velocity and shear rate.
The viscoelastic HPAM injection provided the most stable and efficient displacement of the viscous crude oil. However, when the viscoelastic shear-thickening properties were reduced by pre-shearing the polymer, the displacement was more unstable and comparable to the behavior of the Newtonian glycerol solution.
Contrary to the synthetic HPAM, xanthan exhibits shear thinning behavior in porous media. Displacement by xanthan solution showed pronounced viscous fingering with a correspondingly early water breakthrough.
These findings show that at adverse mobility ratio, rheological properties in terms of flux dependent viscosity lead to significant differences in stabilization of displacement fronts. Different effective viscosities should arise from the flux contrasts in an unstable front.
The observed favorable "viscoelastic effect", i.e. highest efficiency for the viscoelastic HPAM solution, is not linked to reduction in the local Sor. We rather propose that it stems from increased effective fluid viscosity, i.e. shear thickening, in the high flux paths.
This study demonstrates that rheological properties, i.e. shear thinning, shear thickening and Newtonian behavior largely impact front stability at adverse mobility ratio in laboratory scale experiments. Shear thickening fluids were shown to stabilize fronts more effectively than the other fluids. X-ray visualization provides an understanding of oil recovery at these conditions revealing information not obtained by pressure or production data.
A single well biopolymer injection test has been performed to investigate the stability of the biopolymer Schizophyllan under reservoir conditions. Laboratory tests of the Schizophyllan biopolymer prior to field test did show microbial degradation, and an environmentally qualified biocide was selected to be injected together with the biopolymer. The objective of this paper is to focus on the microbial aspects of using biopolymers for EOR (Enhanced Oil Recovery) by performing an extensive microbial analysis program of injected and produced water samples both prior to and after injection of the biopolymer into the reservoir. Multiple samples at different stages during the field test were collected using sterile and anaerobic methods to investigate any change in microbial community and evaluate any microbial degradation of the biopolymer. Analyses show that the biopolymer was not biodegraded during the shut-in period due to presence of biocide. However, microbes able to degrade the biopolymer Schizophyllan were present and could have biodegraded the biopolymer in the absence of active biocide. The microbial community changed in the area affected by biopolymer injection during the field test.
Permeability estimation from log data in formations with complex pore structure remains one of the “holy grails” in petrophysics. This paper presents a novel method using dielectric dispersion logs to accurately predict permeability in carbonates and other complex lithologies.
A core analysis study has established the feasibility of permeability predictions from dielectric core plug measurements using an empirical model based on phase shift and amplitude dispersion in the kHz range (Norbisrath et al., 2017, 2018). The technique has now been adapted to dielectric wireline logs using dispersion phenomena in the MHz range. We show the application of the technique in a North Sea well with dielectric log data and 301 core plug measured permeability samples.
The core plugs have a poro-perm relationship with a low correlation coefficient of R2 = 0.15. Training an empirical dielectric dispersion model on a subset of the core plug data using unconstrained non-linear optimization achieves a correlation coefficient of R2 = 0.82 and R2 = 0.66 with the entire plug data population. A second approach using an artificial Neural Network achieves a correlation of R2 = 0.88, but may suffer from over-tuning and must be further evaluated using additional datasets. The result of the applied technique is a continuous and independent permeability log curve for the entire length of the dielectric log, with an excellent match to subsequently available core plug data, as well as dynamic well test data in un-cored intervals. The high predictability of the method suggests that dielectric dispersion in the low MHz range is related to the pore structure of the rocks, which in turn controls the permeability.
Permeability and mobility are critical uncertainties related to reservoir productivity in lithologies with complex pore structures such as carbonates and other diagenetically altered rocks. The complexity of the pore structure is difficult to discern with standard logging tools, and even advanced tools such as sonicmultipole array or NMR fail to see the connectivity. This results in high uncertainties in estimates of producibility as it is the pore structure and the pore throats that determine the flow (Knackstedt et al., 2008; Weger et al., 2009).