ALBERT

Description: Summary Successful reservoir surveillance and production monitoring is a key component for effectively managing any field production strategy. For production logging in openhole horizontal extended reach wells (ERWs), the challenges are formidable and extensive; logging these extreme lengths in a cased hole would be difficult enough but is considerably exaggerated in the openhole condition. A coiled-tubing (CT) logging run in open hole must also contend with increased frictional forces, high dogleg severity, a quicker onset of helical buckling, and early lockup. The challenge of effectively logging these ERWs is further complicated by constraints in the completion where electrical submersible pumps (ESPs) are installed, including a 2.4-in. bypass section. Although hydraulically powered CT tractors already existed, a slim CT tractor with real-time logging capabilities was not available in the market. In partnership with a specialist CT tractor manufacturer, a slim logging CT tractor was designed and built to meet the exceptional demands of pulling the CT to target depth (TD). The tractor is 100% hydraulically powered, with no electrical power, allowing for uninterrupted logging during tractoring. The tractor is powered by the differential pressure from the bore of the CT to the wellbore and is operated by a preset pump rate from surface. Developed to improve the low coverage in openhole ERW logging jobs, the tractor underwent extensive factory testing before being deployed to the field. The tractor was rigged up on location with the production logging tool and run in hole (RIH). Once the CT locked up, the tractor was activated and pulled the coil to cover more than 90% of the openhole section, delivering a pulling force of up to 3,200 lbf. Real-time production logging was conducted simultaneously with the tractor activation; flowing and shut-in passes were completed to successfully capture the zonal inflow profile. Real-time logging with the tractor is logistically efficient and allows instantaneous decision making to repeat passes for improved data quality. The new slim logging tractor (SLT) is the world’s slimmest and most compact and is the first CT tractor of its kind to enable production logging operations in openhole horizontal ERWs. The importance of the ability to successfully log these ERWs cannot be overstated; reservoir simulations and management decisions are only as good as the quality of data available. Some of the advantages of drilling ERWs, such as increased reservoir contact, reduced footprint, and fewer wells drilled, will be lost if sufficient reservoir surveillance cannot be achieved. To maximize the benefits of ERWs, creative solutions and innovative designs must be developed continually to push the boundaries further.

Description: Summary A class of monotone cell-centered nonlinear finite-volume methods has been proposed in the past decade to solve the anisotropic diffusion equation. The nonlinear two-point flux approximation (TPFA) (NTPFA) method preserves the nonnegativity of the solution values but can violate the discrete maximum/minimum principle (DMP). To enforce DMP, the nonlinear multipoint flux approximation (NMPFA) method ought to be used. In this work, we propose a novel NTPFA method that can reduce the severity of DMP violations significantly compared with the standard NTPFA method. The new formulation uses conormal decomposition for the construction of the one-sided fluxes. To define the unique flux through a connection between two cells, we choose a convex combination of the two one-sided fluxes such that the absolute differences of the magnitudes of the two transmissibility terms associated with the two neighboring cells are minimized, thus bringing the discrete coefficient matrix closer to having the zero row-sum property. Numerical experiments are conducted to test the performance of the new NTPFA method. The results demonstrate that the new scheme has comparable convergence order for both the solution and the flux compared with the standard NTPFA method or the classical multi-point flux approximation (MPFA-O) method. Moreover, the new NTPFA formulation shows marked improvements over the standard NTPFA in terms of reducing DMP violations. However, depending on the specific problem configuration, our new NTPFA formulation can lead to a system of nonlinear equations that is more difficult to solve.

Description: Summary In this paper, I present numerical results of gas/liquid flows in pipelines obtained from a new simulation code. One difference, with respect to other 1D fluid dynamic commercial simulation products, is the use of a compositional approach to the problem: This is rarely found in published articles about gas/liquid flow in the oil and gas industry. It is shown that the algorithm can calculate both pressure and material fast waves generated during the transportation of gas and liquid in pipes. The solution algorithm is based on the application of a two-fluid model to the mass, momentum, and energy conservation equations, which are solved using a mixed implicit-explicit integration schema. Closure equations for the calculation of interface stress are taken from literature articles. A dam-break simulation (i.e., a Riemann initial value problem) is presented as a severe test case for validation of the two-phase flow algorithm. Because the code is able to capture sharp and fast changes in the liquid holdup connected to the formation of pressure waves, it is applied to the simulation of slug flow without the use of steady-state “unit cell” models and slug tracking functions. In this context, the experimental results on pseudoslug formation in inclined pipes at high pressures, published by the Tulsa University Fluid Flow Project (TUFFP), are used to compare simulated results with experimental data. The last part is dedicated to the simulation of some cases taken from a classical flow-map of a fundamental article by Taitel and Dukler (1976). At constant liquid superficial velocity, the formation of liquid slugs and their subsequent termination with the increase of gas flow rate is simulated with details never previously presented.

Description: Summary The initial water saturation in a reservoir is important for both hydrocarbon volume estimation and distribution of multiphase flow properties such as relative permeability. Often, a practical reservoir engineering approach is to relate relative permeability to flow property regions by binning of the initial water saturation. The rationale behind this approach is that initial water saturation is related to both the pore-throat radius distribution and the wettability of the rock, both of which affect relative permeability. However, pore-throat radius and wettability are usually not explicitly included in geomodel property modeling. Therefore, the saturation height model should not only capture an average hydrocarbon pore volume but also reflect the underlying mechanisms from hydrocarbon migration history and its impact on initial water saturation distribution. This work introduces and describes a new term, excess water, for more precise classification of saturation height model scenarios in reservoirs in which multiple mechanisms have interacted and caused a complex water saturation distribution. An example of the presence of transition zones related to drained local perched aquifers (excess water) in oil-down-to (ODT) wells is shown using a limited data set from a North Sea reservoir. The physical basis for drainage and imbibition transition zones connected to both regional and perched aquifers is given. The distribution of initial water saturation in reservoirs containing excess water is demonstrated through numerical modeling of oil migration over millions of years. Highly permeable reservoirs are more likely to have locally trapped water because of lower capillary forces. A static situation occurs in areas where the capillary forces cannot maintain a high enough water saturation for further water drainage. On the other hand, both high- and low-permeability reservoirs may have significant excess water because of ongoing dynamic effects. In both cases, long distances for water to drain laterally to a regional aquifer enhance the possibility for a dynamic excess water situation.

Description: Summary Nanoparticles have great potential to mobilize trapped oil in reservoirs because of their chemical, thermal, and interfacial properties. However, the direct application of magnetic forces on superparamagnetic nanoparticles in reservoir engineering applications has not been extensively investigated. We demonstrate the enhanced oil recovery (EOR) potential of hydrophilic superparamagnetic nanoparticles in oil production by direct observation using microfluidics. We studied the mobilization of oil blobs by a ferrofluid (a suspension of hydrophilic superparamagnetic nanoparticles in water) both in a converging/diverging micromodel channel and in a foot-long pore network micromodel, both with varying depth (so-called 2.5D micromodels). The water-based ferrofluid in all cases was the wetting fluid. Initial ferrofluid flooding experiments in single channels were performed without and then with a static magnetic field. This magnetic field caused oil droplet deformation, dynamic breakup into smaller droplets, and subsequent residual oil saturation reduction. During the flooding, after the magnetic field was applied, significant oil displacement was observed within 2 hours [6 pore volumes injected (PVI)], and 86.2% of the oil that was not mobilized without a magnetic field was mobilized within 64 hours (192 PVI). Then, in experiments in the micromodel and in a Hele-Shaw cell without flooding, we observed self-assembly of oil droplets, indicating the formation of the hydrophilic magnetic nanoparticle microstructures (chains under the magnetic field) and their interaction with the oil blobs. Further ferrofluid flooding experiments were performed in a foot-long micromodel under a rotating magnetic field. The oil saturation was reduced from 44.6 to 33.3% after 17 hours (8.5 PVI) of ferrofluid flooding after the rotating magnetic field was applied. Finally, a discussion of field application of ferrofluid flooding is presented.

Description: Summary In this paper, we incorporated a kinematic proppant transport model for spherical suspensions in hydraulic fractures developed by Dontsov and Peirce (2014) in a pseudo-3D hydraulic-fracture simulator for multilayered rocks to capture a different proppant transport speed than fluid flow and abridged fracture channel by highly concentrated suspensions. For pressure-driven proppant transport, the bridges made of compact proppant particles can lead to both proppant distribution discontinuity and increased fracture aperture and height because of the higher pressure. The model is applied to growth of a fracture from a vertical well, which can contain thin-bedded intervals and more than one opened hydraulic-fracture interval, because the fracture plane extends in height through layers with contrasts in stress and material properties. Three numerical examples demonstrate that a loss of vertical connectivity can occur among multiple fracture sections, and proppant particles are transported along the more compliant layers. The proppant migration within a narrow fracture in a thin soft rock layer can result in bridging and formation of a proppant plug that strongly limits fluid speed. This generates an increase of injection pressure associated with fracture screenout, and these screenout events can emerge at different places along the fracture. Next, because of the lack of pretreatment geomechanical data, the values of layer stress and leakoff coefficient are adjusted for a field case so that the varying bottomhole pressure and fracture length are in line with the field measurements. This paper provides a useful illustration for hydraulic-fracturing treatments with proppant transport affected by and interacting with reservoir lithological complexities.

Description: Summary An industry-accepted standard for minifrac analysis for evaluating and improving design of hydraulic fracturing treatments originated from the original Nolte analysis (Nolte 1979) of pressure decline, followed by the introduction of Castillo G-function in a Cartesian plot (Castillo 1987). The latter provides a graphical method for the identification of fracture closure pressures and stresses with subsequent derivation of other parameters such as fluid efficiency and fracture geometry. With the introduction of a more advanced consideration of the G-function interpretation for various reservoir conditions (Barree et al. 2007), subdividing the interpretation into calculations based on flow regimes and leakoff modes, this approach has become even more sophisticated. Particularly, interesting flow regimes and leakoff modes during fracture closure include the fracture height recession mode. This mode tends to result in rapid screenout and difficulty in placing high proppant concentrations. Regarding interpretation, the G-function derivative curve for this mode can have more than one plateau, an outcome that is possibly indicative of features that have not been widely considered to date or on which little to no data have been published. This paper presents a case study as an example of such height recession mode, along with a subsequent G-function interpretation and analysis and with consideration of the vertical facies distribution along the wellbore. Considerable attention is paid to the G-function derivative plateau analysis. Three distinctive wells, namely X-1,X-2, and X-3, are discussed. Using this technique can lead to an improved fracture calibration, optimized fracture design, and adoption of a successful completion strategy; additionally, the confirmation of 1D facies distribution can provide new insights into the fracture closure period.

Description: Summary The permeability characteristics of hydrate-bearing reservoirs are critical factors governing gas and water flow during gas hydrate exploitation. Herein, X-ray microcomputed tomography (CT) and the pore network model (PNM) are applied to study the dynamic gas and water relative permeabilities (krg and krw) of hydrate-bearing porous media during the shear process. As such, the dynamic region extraction method of hydrate-bearing porous media under continuous shear is adopted by considering deformation in the vertical direction. The results show that krw and krg of hydrate-bearing porous media are influenced by the effect of disordered sand particle movement under axial strain. Declines in the critical pore structure factors (pore space connectivity, pore size, and throat size) contribute to the reduction in krw and the increase in krg. However, krg decreases during the shear process at a high water saturation (Sw) because of the high threshold pressure and flow channel blockage. In addition, the connate water saturation (Swc) continuously increases during the shear process. Swc is influenced by pore size, throat size, and flow channel blockage. Moreover, the preferential flow direction of krg and krw changes during the continuous shear process. The results of dynamic permeability evolution during the continuous shear process under triaxial stress provide a reference for pore-scale gas and water flow regulation analysis.

Description: Summary Torque and drag models have been used for several decades to calculate tension and torque profiles along drillstrings, casing strings, and liner strings. Buoyancy forces contribute to the loads acting on the pipe and affect its interaction with the borehole wall. Torque and drag calculations account for these localized effects, as well as the material internal forces, torques, and moments on each side of the contact. When the analysis is applied to a discrete length of pipe, the cross sections at each end do not contribute to the buoyancy forces because they are not in contact with the fluid, except where there is a change in diameter or at the end of the string of pipe. We argue that it is important to check that the models used for solid pipe torque and drag calculations remain valid for sand screens, in particular, the extent to which the buoyancy forces acting on a perforated tube might differ from those on a solid pipe. Because the buoyancy force is the result of the pressure gradient acting on the surface of the pipe, the presence of holes may also influence the buoyancy force. We propose that there are theoretical differences between local buoyancy forces acting on plain or perforated tubes. This paper describes how to calculate the local buoyancy force on a portion of a drillstem by the application of Gauss’ theorem and accounting for the necessary corrections arising from the cross sections not being exposed to the fluid. We built an experimental setup to verify that the tension inside a pipe subject to buoyancy behaves in accordance with the derived mathematical analysis. With complex well construction operations, for instance during extended-reach drilling or when drilling very shallow wells with high buildup rates, the slightest error in torques and drag calculations may end up jeopardizing the chances of success of the drilling operation. It is therefore important to check that the basis of design calculations remain valid in those contexts and that, for instance, sand screens or slotted liners may be run in hole safely after a successful drilling operation.

Description: Summary The stimulation of unconventional reservoirs to improve oil productivity in tight formations of shale basins is a key objective in hydraulic fracturing treatments. Such stimulation can be made by reliable fracture fluids that have a high viscosity and elasticity to suspend the proppant in the fracture networks. Recently, due to several operational and economic reasons, the oil industry began using high-viscosity friction reducers (HVFRs) as direct replacements for linear and crosslinked gels. However, some issues can limit the capability of HVFRs to provide effective sand transport, including the high fluid temperature during fracture treatment inside the formations. This may lead to unstable fracture fluids caused by a decrease in the interconnective strength between the fluid chains, which results in reduced viscosity and elasticity. This study comprehensively investigated HVFRs in comparison with guar at various temperatures. An HVFR at 4 gallons per thousand gallons of water (gpt) and guar at 25 pounds per thousand gallons of water (ppt) were selected based on fluid rheology tests and hydraulic fracture execution field results. The rheological measurements of both fracture fluids were conducted at different temperature values (i.e., 25, 50, 75, and 100°C). Static and dynamic proppant settling tests were also conducted at the same temperatures. The results showed that the HVFR provided better proppant transport capability than the guar. The HVFR had better thermal stability than guar, but its viscosity and elasticity decreased significantly when the temperature exceeded 75°C. An HVFR can carry and hold the proppant more deeply inside the fracture than liner gel, but that ability decreases as the temperature increases. Therefore, using conditions that mimic field conditions to measure the fracture fluid rheology, proppant static settling velocity, and proppant dune development under a high temperature is crucial for enhancing the fracture treatment results.