Zwartjes, Paul (Shell Global Solutions International B.V) | Mateeva, Albena (Shell International Exploration and Production Inc.) | Tatanova, Maria (Shell International Exploration and Production Inc.) | Chalenski, David (Shell International Exploration and Production Inc.) | Yang, Zhaohui (Shell International Exploration and Production Inc.) | Lopez, Jorge (Shell International Exploration and Production Inc.) | de Vos, Koos (Shell Global Solutions International B.V.) | Potters, Hans (Shell Global Solutions International B.V.)
We show that time-lapse 3D VSP acquired with Distributed Acoustic Sensing (DAS) is capable of detecting 4D signals associated with 3 years of production in the Deepwater Gulf of Mexico. Very good repeatability (NRMS~7%) was achieved, helped in part by a new DAS depth calibration method. Repeatability can be further improved in future surveys by better execution. We outline the next steps toward enhancing 4D DAS VSP value and affordability in order to establish it as a tool for frequent monitoring.
Presentation Date: Tuesday, September 26, 2017
Start Time: 3:30 PM
Presentation Type: ORAL
A dynamic multilevel compositional solver (C-ADM) is introduced for fully(and sequentially-) implicit systems arising from compositional displacements in natural porous media. The fully (or sequential) implicit system is first described at a fine-scale resolution, where phases are allowed to consist of different components (based on thermodynamics equilibrium). In addition, heterogeneous capillary functions (defined based on Leverett's J-function) and gravitational effects are both considered, adding significantly to the nonlinear complexity of the processes. Given this complex fine-scale system for a heterogeneous reservoir, C-ADM defines a dynamic multilevel system, based on an error criterion, where the grid resolution is defined based on the physics of the process as well as geological complexities and location of wells. Once this multilevel grid is defined, sequences of prolongation and restriction operators are employed to obtain an accurate and efficient multilevel system. CADM allows for a general set of prolongation operators, e.g., constant, bilinear (or polynomial), and multiscale basis functions. The restriction operators, however, are constructed based on a mass-conservative finite-volume formulation at all levels. For several challenging test cases it is shown that C-ADM employs only a small fraction of the fine-scale grids to provide an accurate description of the process. C-ADM casts a promising approach in the application of dynamic grid refinement methods for real-field applications.
Continuous Foam Injection is a proven deliquification technique in gas wells, but the technology typically struggles to perform in wells with high fractions of liquid hydrocarbons. For gas lifted oil wells operating at high water cuts however, continuous downhole foam injection may prove feasible to enhance production. A field trial to test this theory was successfully executed within an oil producing facility in The Netherlands. The objective of this trial was twofold: First, to observe the changes in production owing to downhole injection of a foaming agent while keeping the lift gas rate constant. Second, to perform a lift gas utilization test to identify potential lift gas savings with the assistance of foam. Furthermore, strict specifications on the export crude and produced water had to be achieved. The trial showed successful results. The well had a fast response to the addition of foam whereby initial sluggish production stabilized. This has overcome the flow instability related production deferment, which was significant. Further increases in the foam injection rate to reach the optimum foam concentration helped the well to produce up to 20% more gross liquid than the measured and calculated stable rates. The trial has revealed that with the application of foam, lift gas savings of 35% were feasible and more could be achieved depending on the desired gross liquid production. No process facility upsets were experienced during the trial.
This paper describes the detailed aspects of the trial, including the preparation, execution, and modelling techniques which will benefit and add to the current body of knowledge of foam lift to the petroleum industry.
Al Shoaibi, S. (Petroleum Development) | Kechichian, J. (Petroleum Development) | Mjeni, R. (Petroleum Development) | Al Rajhi, S. (Petroleum Development) | Bakker, G. G. (Petroleum Development) | Hemink, G. (Shell Global Solutions International B.V) | Freeman, F. (Shell Global Solutions International B.V)
Fiber Optics Distributed sensing technologies are evolving in the petroleum industry with its potential applicability in many areas of surveillance. Petroleum Development Oman (PDO) is embarking upon the implementation of this technology in various assets including both Gas and Oil fields. The vision of the company is to have the Fiber Optics distributed sensing technology as a surveillance tool in the Well and Reservoir Management (WRFM) toolbox and to become, where appropriate, a key element of its cycle. In comparison to conventional surveillance, fiber optic distributed sensing requires no well intervention and thereby reducing HSSE exposure and production deferment. In addition, the installed fibers can be used for multiple applications, e.g. hydraulic fracture performance monitoring and inflow performance monitoring. Recently, PDO trialed Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) technologies utilizing both, dip-in surveys and permanent installation of fiber optics in the wells.
Fiber optic implementation in PDO included a polymer flooding trial in heavy oil, high permeability clastic reservoir with a strong bottom water aquifer drive. The objective was to monitor well conformance as the polymer injection progressed. The horizontal injectors were completed with pre-drilled liner and divided into four zones, each with an independent Inflow Control Valve (ICV). The well was completed with a multi-mode (MM) fiber pumped into control lines three injectors. Real time DTS data was acquired continuously in all three wells while DAS was acquired as per the injection program in one injector. DAS and DTS data were analyzed to quantify the changes in injection profile and rate in each ICV zone. This provided timely information needed for decisions related to manipulation of the ICV valves to ensure best utilization of the polymer.
Another example of fiber optics was a dip-in survey in a deep gas well with commingled production which covered stacked reservoirs. This was run in order to prove the concept of flow response on DAS/DTS signals in terms of gas flowing and liquid lifting detection. The acoustic signature observed was mainly due to gas entering the well through perforations. This was detected by DAS and DTS and allowed a qualitative inflow profile to be generated. The dip in survey proved the concept and allowed justification for the permanent installation of fiber optics behind casing. The objective of the permanent setup is to improve the sensitivity of the measurement and allow for better quantification of inflow per zone. In this paper, the approach of implementing fiber optic technologies in PDO is discussed with emphasis on value generation in the various assets. Additionally, the examples mentioned in this abstract are discussed in more details and based on the results, the way forward is described.
Klinkenbijl, Jeanine (Shell Global Solutions International B.V) | Brok, Theo (Shell Global Solutions International B.V) | Critchfield, Jim (Shell International Exploration and Production Inc) | Valenzuela, Diego (Shell International Exploration and Production Inc) | Lee, Danmi (Shell Global Solutions International)
The development of more complex energy sources is increasing to meet the growing demand for more energy. Such gas resources may be more contaminated, more complex, more costly, and contain more CO2 and H2S. At the same time, tighter environmental and product specifications necessitate smarter gas processing. This needs to be achieved by stretching current processes and developing reliable new technologies to effectively address the challenges of managing complex gases.
One area of gas processing that is well established is Acid Aided Regeneration (AAR) technology: the use of acids to reduce the regeneration steam of amine treating units has been applied since the 1960s, and is nowadays often referred to as a Formulated amine. Or, achieve a lower specification in the treated gas, due to a lower leanness in the solvent when the regeneration heat is kept constant, and thereby reduce environmental (CO2 and/or SO2) emissions.
Shell has carried out an extensive study on the use and misuse of AAR, focusing on the actual effects in operation and comparing unit performance with results of process simulation in the presence of acids in an amine solvent.
The operational effects observed are explained and general guidelines for application discussed. Although the focus of the application is on low pressure selective design (Tail Gas Treating Units), the main effects for high pressure application are also addressed in the study. In the paper the basis for the Shells AAR technology is described: Detailed analysis of process performance (both analytical solvent analysis and actual plant performance data) in aqueous amine treating units in a wide variety of applications. This gives good and consistent insight in the qualitative and quantitative results of acid addition to amine solvents and measured contaminant removal. A theoretical discussion on the acid effects in an amine solution, focusing on the energy for regeneration of the amine, as well as the option to meet a lower contaminant specification with a constant regeneration energy requirement by the addition of an acid to the amine solution.
Detailed analysis of process performance (both analytical solvent analysis and actual plant performance data) in aqueous amine treating units in a wide variety of applications. This gives good and consistent insight in the qualitative and quantitative results of acid addition to amine solvents and measured contaminant removal.
A theoretical discussion on the acid effects in an amine solution, focusing on the energy for regeneration of the amine, as well as the option to meet a lower contaminant specification with a constant regeneration energy requirement by the addition of an acid to the amine solution.
Sorop, Tibi G. (Shell Global Solutions International B.V) | Masalmeh, Shehadeh K. (Shell Abu-Dhabi) | Suijkerbuijk, Bart M. J. M. (Shell Global Solutions International B.V.) | van der Linde, Hilbert A. (Shell Global Solutions International B.V.) | Mahani, Hassan (Shell Global Solutions International B.V.) | Brussee, Niels J. (Shell Global Solutions International B.V.) | Marcelis, Fons A. H. M. (Shell Global Solutions International B.V.) | Coorn, Ab (Shell Global Solutions International B.V.)
In the last few years it has become widely accepted in the industry that Low Salinity Flooding (LSF) works by changing reservoir wettability towards a more water-wet state. Most of the published experimental data to quantify the LSF effect focus on comparing ultimate recovery of low salinity (LS) and high salinity (HS) waterflooding experiments either in secondary and/or tertiary mode. A wide range in incremental oil recovery is reported in the literature, from 0 to more than 20% of OIIP. To assess the potential of LSF and to enable upscaling of the LSF benefit to reservoir scale, the relative permeability curves for HS and LS brine should be determined. In only a few published cases, the experimental data was interpreted using numerical simulations to derive relative permeability curves for both low and high salinity water.
So far all of the LSF corefloods reported in the literature have been done using the unsteady state (USS) coreflooding method. Unsteady state corefloods are appropriate in evaluating the LSF potential qualitatively and to de-risk for potential formation damage due to clay swelling. However, USS corefloods can only measure the relative permeability curves after water breakthrough and they are sensitive to heterogeneities in the core samples. The steady state (SS) coreflood method, on the other hand, is less sensitive to sample heterogeneity and can measure the relative permeability curves over a wide saturation range.
In this paper we will present the experimental procedures and data measured during SS LSF core floods using less homogeneous core samples from a sandstone reservoir. Details of the experimental procedures to quantify the LSF effect were published earlier (
Li, Y. (Shell Exploration and Production Company) | Wu, H. (Shell Exploration and Production Company) | Wong, W. (Shell Exploration and Production Company) | Hewett, B. (Shell Exploration and Production Company) | Liu, Z. (Shell Exploration and Production Company) | Mateeva, A. (Shell Global Solutions International B.V) | Lopez, J. (Shell International Exploration and Production Inc.)
Shell conducted its first dual-well 3D DAS-VSP survey concurrently with an OBS survey in a deep water environment in the Gulf of Mexico in 2012. This survey produced about 40M picks of the first arrival times (FAT) which were used to diagnose and update velocity models for improvement of both borehole and surface seismic images of subsurface structures. We developed a procedure to use the VSP-FAT to diagnose the velocity models derived from surface seismic surveys and monitor the velocity updating process. The method first was used for selecting a suitable initial velocity model. After the traveltime tomography inversion of FAT, this diagnosis approach was applied again to the updated VTI-inversion model to ensure the velocity updating effort is on the right track. We used the Absolute and Relative Misfits (AM & RM) and apparent velocities to quantify the velocity model uncertainties as functions of depth, azimuth, and offset. Both DAS-VSP data at two wells and OBS data were migrated with the initial VTI velocity model and the updated VTI-inversion model. It is found that both borehole and surface seismic images generated with the VTI-inversion model are improved from those obtained with the VTI-initial model, especially for the seismic amplitudes at a target event.
Distributed acoustic sensing (DAS) systems using the fiber optical cable have played important roles in the borehole seismic monitoring and imaging. In 2012, Shell simultaneously acquired its first 3D dual-well DAS-VSP (Vertical Seismic Profiling) with an OBS (Ocean Bottom Sensor) survey (Mateeva et al., 2013) in a deep water environment in the GOM (Figure 1). This DAS-VSP dataset, with over 40M traces, provides rich borehole seismic data to diagnose and update the surface seismic velocity models and examine the effects from model updating on improvements of both borehole and surface seismic images of subsurface structures. This study is a complementary to the earlier efforts of 3D OBS-VSP surveys in the GOM (Hornby and Burch, 2008; Wu et al, 2011) with the limited numbers of fiber sensors.
van Batenburg, D. W. (Shell Global Solutions International B.V) | Berg, S. (Shell Global Solutions International B.V) | Oedai, S. (Shell Global Solutions International B.V) | Elewaut, K. (Shell Global Solutions International B.V)
This paper describes a series of experiments that used X-ray computer tomography (CT) to visualize the mobilization of remaining oil by Alkaline Surfactant (AS) and Alkaline Surfactant Polymer (ASP) flooding after conventional waterflooding. The experiments were conducted in cores drilled from Gildehauser and Bentheimer sandstone outcrop material with diameters of approximately 7.55 cm and lengths of approximately 27 cm and one meter. Crude oil with in-situ viscosities of 1.3, 2.3 and 100 cP was used in the experiments. The changes in the fluid saturation distributions with time obtained with X-ray computer tomography are subsequently used to improve the conceptual understanding of the ASP process.
In addition to pressure and effluent data collected during conventional core flood experiments, phase and saturation distributions in space and time are needed to more completely interpret the results of core floods. This additional information reveals underlying mechanisms, and assists the development of models that capture the physics of ASP that can ultimately be used to provide field scale predictions for ASP performance.
One important observation from the experiments is that there exist a consistent fingering pattern in the zone upstream of the oil bank. Although fingering is often considered a bad sign for a displacement process the experiments also demonstrate that the fingering zone is contained in the area upstream of the oil bank and that the velocity of the front of the oil bank is significantly greater than that of the fingering zone. The production following the clean oil bank (tail) observed in many ASP core floods is a consequence of the formation of this fingering zone.
Effluent analyses conducted on the produced fluids from the long core experiments showed a sharp, rapid build up in polymer viscosity that coincides with the beginning of the tail production while the surfactant concentration only gradually increases to its injection value during the tail production.
Another important observation is that a characteristic self-similar cross-sectional averaged oil saturation profile develops during ASP injection after water flood in cores containing reactive crude oil with 100 cP viscosity and in non reactive light crude oil.
The implications of the self-similarity of the saturation profiles in combination with the observation that the surfactant propagation is retarded with respect to the polymer propagation results in a polymer flood ahead of the ASP-slug and a corresponding characteristic oil production profile. The characteristics of this process can be captured with an extended fractional flow approach that utilizes three fractional flow curves: one for the ASP-slug, one for polymer, and the original fractional flow curve for oil-water.
Przybysz-Jarnut, J. K. (Shell Global Solutions International B.V) | Didraga, C. (Shell Global Solutions International B.V) | Potters, J. H. H. M. (Shell Global Solutions International B.V) | Lopez, J. L. (Shell International Exploration & Production Inc.) | La Follett, J. R. (Shell International Exploration & Production Inc.) | Wills, P. B. (Shell International Exploration & Production Inc.) | Bakku, S. K. (Shell International Exploration & Production Inc.) | Xue, Y. (Shell International Exploration & Production Inc.) | Barker, T. B. (Shell International Exploration & Production Inc.) | Brouwer, D. R. (Shell Canada Limited)
Time-lapse seismic surveillance is a proven technology for areal conformance monitoring offshore, but not onshore due to its high cost and typically poor data quality in that environment. Yet a number of examples in the industry show that nonuniform reservoir sweep is common in IOR and EOR projects and, if not addressed, it can significantly reduce ultimate recovery. In such projects the efficacy of injectants such as water, steam, gas, and solvents needs to be maximized to reduce cost and environmental footprint. This requires that we know what happens in-between wells, and for this purpose we conducted a pilot of high fidelity frequent seismic monitoring of thermal EOR redevelopment in one of the production pads in the bitumen deposits in Peace River, Canada. We detected patterns that can be directly linked to dynamic reservoir changes on a weekly or more frequent basis, such as pressure increase during injection, fluid phase changes, and connection to previously stimulated zones. The data also highlight the imprint of previous operations on the reservoir state prior to the current redevelopment, stressing the challenges faced when managing steam conformance. Our observations indicate that frequent time-lapse seismic images significantly contribute to determining injection/production strategy adjustments aimed at improved areal steam conformance.
Pingo Almada, M. B. (Shell Global Solutions International B.V) | Pieterse, S. G. J. (Shell Global Solutions International B.V) | Marcelis, A H. M. (Shell Global Solutions International B.V) | van Haasterecht, M. J. T. (Shell Global Solutions International B.V) | Brussee, N. J. (Shell Global Solutions International B.V.) | van der Linde, H. A. (Shell Global Solutions International B.V.)
Low salinity flooding (LSF)- decreasing ionic strength to enhance oil production- is an Enhanced Oil Recovery (EOR) process currently being evaluated in industry and academia with first deployment beginning. A wettability modification is assumed to take place when decreasing the ionic strength. In this work we explore the effects of varying salinities from formation water down to very low salinity on brine permeability and on effluent composition. The following effects have been investigated: the presence and absence of oil in the core, the cation exchange capacity (CEC), mineral dissolution and cation stripping.
The experimental component of this investigation consisted of continuous permeability measurements during flooding at various salinity steps and simultaneous collection of the effluent. The effluent was analyzed using Inductively Coupled Plasma (ICP elemental analysis). The CEC's of the rock exposed to the different salinities have also been measured. Scanning Electron Microscope (SEM) visual investigations have also been carried out.
During the flooding with several different brines, permeability variations were observed. The variation of the ionic composition of the effluent has allowed for:
• identification and characterization of the temporary divalent cation stripping process
• the framing of hypotheses about other possible mechanisms taking place in the core during LSF, such as:
o ion exchange between injected brine and the clays as the salinity decreased
o The role that CEC plays in the re-equilibration with the new salinity
o the CEC variation throughout the experiment at Sor
o mineral dissolution and clay deflocculation.
The comprehensive suite of tools and techniques used here has given more insights into the mechanisms taking place when decreasing the ionic strength and their use can serve to improve the deployment of the technology, including the prevention of formation damage.
The role of the injection brine composition in oil recovery efficiency has been increasingly investigated in recent years. In several cases there is evidence of incremental oil after injection of a lower salinity brine in sandstones (Vledder et al, 2012, Seccombe et al, 2010), or when modified salinity brine is injected in carbonates (Yousef et al,2012; Romanuka et al , 2012); while in other cases no effect has been observed (i.e. Snorre Field, Skrettingland et al., 2011). The reason for the wide response is still to be elucidated but it is clear that it is related to the several factors underlying the microscopic mechanisms. It is clear that the low salinity brine needs to have a salinity low enough to yield extra recovery and at the same time high enough to prevent any formation damage (FD) by clay swelling. Typical low salinity concentrations are in the ranges of 1000 to 2000 mg/l TDS while the specific ranges are investigated individually per field.
This paper addresses salinity ranges below 6000 ppm TDS that are relatively low. Extensive work on the relationship between clay swelling/deflocculation and brine composition was carried out by Scheuerman et al. in the 1990's, which led to Injection-Water guidelines based on the compatibility of injection water and formation clays. A FD prevention criteria was outlined based on the fraction of total divalent cations needed in injection water to avoid clay deflocculation and hence permeability impairment.