Barker, Timothy (Shell International Exploration and Production Inc.) | Xue, Yang (Shell International Exploration and Production Inc.) | Przybysz-Jarnut, Justyna (Shell Global Solutions International B.V.)
Continuous seismic monitoring has been deployed at Peace River Pad 31 to provide temporal and areal insight to steam injection and production induced changes in the reservoir. To quantify the changes, a rock physics model has been defined that incorporates geologic variability and expected production effects. Interpretation of the complex seismic response requires a systematic approach to gain insight into and quantification of reservoir changes from thermal EOR (e.g. pressure, temperature, and steam thickness) to facilitate communication with surveillance engineers and influence operating decisions.
The Peace River bitumen deposits were discovered in 1951 in northwestern Alberta, Canada. They contain billions of barrels of heavy oil with 7-10 API and are under production employing steam injection.
The reservoir in the Peace River area is the Bluesky formation. It is lower Cretaceous in age and the siliciclastic sediments were deposited in a marginal marine setting. In the area of this study, the reservoir, a high porosity and unconsolidated sand, averages around 25 m in thickness and is at a depth of about 550 m below the surface. An unconformity separates the reservoir from the underlying Paleozoic carbonates. The top seal is formed by the marine Wilrich shale.
Operations at Pad 31 began in 2001 and there have been 7 cycles of steam stimulation. In 2014, the pad was instrumented with CGG’s SeisMovie® system to continuously monitor the injection and production once additional steam injection wells were drilled to increase oil recovery from the pad.
Rock physics model
In order to translate the reservoir changes into the seismic response to use in forward modeling (generating synthetic seismic) of reservoir models and scenarios, or in seismic inversion, it is first necessary to describe mathematically the relationship between reservoir properties (porosity, fluid types, saturations, pressure, and temperature) and elastic properties (Vp, Vs, and density). There has been a significant amount of work to describe the rock physics and we are building upon that foundation (Maron et al., 2005; Cabolova et al., 2014).
We have studied velocities and elastic properties of heavy-oil saturated sand (Alberta, Canada) as a function of temperature and pore pressure. In addition to ultrasonics we have applied a low-frequency technique for measuring the dynamic Young’s modulus at seismic frequencies in order to assess velocity dispersion. Our results indicate that the temperature dependence of ultrasonic velocities can be described by Gassmann theory for temperatures > 100C whereas velocity-dispersion effects have to be taken into account at lower temperatures. The pore-pressure dependence of the dry-rock bulk and shear moduli can be described by a power-law, however with a much smaller exponent as predicted by Hertz-Mindlin theory. Interestingly, over a large pore-pressure range, we observe a nearly linear dependence of axial velocities on axial strain, exhibiting much higher strain sensitivities than for other rocks. While the dynamic bulk modulus shows a non-linear pore-pressure dependence, the static bulk modulus measured during pore-pressure inflation exhibits a nearly linear dependence on pore pressure, with the bulk modulus dropping to near zero at zero effective stress. As a consequence, before the rock fails, it exhibits large, reversible dilation, which will have an impact on the steam-injection process.
For quantitative interpretation of seismic data and sonic logs of reservoirs undergoing thermal enhanced oil recovery (thermal EOR), in particular time-lapse seismic studies for reservoir surveillance, we need improved thermal rock physics models that describe the dependence of acoustic velocities on temperature, pore pressure, stresses, and fluid saturation. The goal of the present study was to develop – based on laboratory measurements with core plugs – a thermal rock physics model for heavy-oil saturated sand that is able to give a quantitative and consistent description of field data and allows for inversion of seismic data for temperature and pressure changes. In particular, we will assess the following assumptions: (i) Gassmann theory is applicable for heavy-oil saturated sand, and (ii) the pore-pressure dependence of the dry-rock bulk and shear moduli follow a Hertz-Mindlin power law. As techniques we applied triaxial compaction, ultrasonics, and a newly developed technique for measuring dynamic stiffnesses at seismic frequencies. We will show that for velocities at seismic frequencies, the Gassmann model provides for most applications an acceptable description, whereas at sonic and ultrasonic frequencies, velocity dispersion effects have to be taken into account for temperatures < 100°C. As for the second assumption, our laboratory measurements indicate that the pore-pressure dependence of the dry-rock bulk and shear moduli follow a power law, however, the exponent is much smaller than the one of the Hertz-Mindlin model, which is attributed to the large grain-contact areas of this Alberta oil sand. In addition to velocities, i.e. dynamic elastic properties, we have measured quasi-static elastic properties. The static bulk modulus, in contrast to the dynamic one, exhibits a linear dependence on pore pressure, dropping to near zero at zero effective stress. This rock-mechanical behavior might have some impact on high-pressure steam recovery. Finally, we find linear relationships between velocities and axial strains over large pressure ranges. However, the strain sensitivity (R factor) is much higher than previously suggested.
The acoustic wave detection system is considered a non-destructive monitoring system to estimate distances using measurement of the time-of-flight of an ultrasonic wave. In this paper, a comprehensive experimental study was conducted to investigate the feasibility of the acoustic wave detection system in monitoring the shape and position of the gas phase in the vapor extraction process. For this purpose, various stages of vapor chamber evolution in the Vapex process were experimentally simulated by changing the shape of air balloons buried in simulated porous media in a lab scale model. Then, an array of ultrasound transducers and receivers were used to measure time-of-flights at different stages of the vapor chamber growth. Finally, the collected data were fed into a signal processing program developed in this study to determine the shape of the vapor chamber. Conducted analysis in this study include: sound speed testing in different porous media, signal attenuation tests in different porous media, imaging of different simulated vapor chambers in different porous media, and the acquisition and analysis experiments. Results show that acoustic wave detection can be used for accurate mapping of the position and shape of the vapor chamber in the studied process. Monitoring the shape and growth of the vapor chamber provides valuable information for optimizing oil production in order to maximize oil recovery. This is the first attempt at using acoustic wave detection techniques in monitoring the phase movement in the Vapex process. Results of this study show that this technique can be potentially used for this purpose.
Thermal stimulation of bitumen in oil sands reservoirs is a critical requirement for the success of steam-based recovery processes. If the bitumen is not heated, it remains at its original viscosity, often in the millions of centipoise, and thus is not mobilized so that it can be moved to a production well. All oil sands reservoirs are heterogeneous; both with respect to geology and fluid composition, and thus steam conformance of steam in the reservoir is not uniform. At present, realtime monitoring of the steam conformance zone in the reservoir is not possible and thus the spatial distribution of heat delivery to the reservoir is uncertain. In this research, a new method for detecting heterogeneity and monitoring steam chambers has been developed and tested by detailed thermal-acoustic reservoir simulation. Here, a thermal fluid flow simulator was coupled to a wave propagation simulator to evaluate the potential of identifying rock and fluid discontinuities within a reservoir by using coded white noise reflection processes. Digital communication systems employ coded white noise processes to advantageously make use of unexpected reflections from environmental heterogeneities. The proposed theory and subsequent simulations reveal that it is possible to resolve features of an unconventional recovery process as well as imaging of heterogeneity within the reservoir as it evolves by using white noise reflection methods. The properties of the signals described provide an opportunity for property detection at lower power levels and higher frequencies than traditional sceismic methods. Furthermore the signals are such that the noise from recovery processes and the native reservoir environment do not interfere with the detection methods allowing for the monitoring method to be used concurrently with the recovery process. A SAGD model is tested and the results show that white noise reflections can be used to detect the edge of steam chambers.
We have modeled the warm-up phase of a SAGD project using a coupled reservoir simulator and stress model. We matched the injection pressure by adjusting the reservoir permeability. A fair match between data and model was obtained. Microseismic monitoring indicated localized injection at the toe, which was used in the model. Also, the seismic signature indicated strike slip and possibly overthrust fault slippage or casing failure as cause of the seismicity. This confirms the reservoir and stress model used in the interpretation. While most of the steam was injected at the toe, the uplift was largest at the heel of the well. This can be best explained by reservoir heterogeneity, which implies that surface heave measured with tiltmeters can best be interpreted using a geomechanical model. The matched coupled model can be used for optimizing the completion and injection process.
Bailey, Jeffrey R. (ExxonMobil Upstream Research Co.) | Smith, Richard James (Imperial Oil Resources Ltd.) | Keith, Colum M. (Imperial Oil Resources Ltd.) | Searles, Kevin Howard (ExxonMobil Upstream Research Co.) | Wang, Lei (ExxonMobil Upstream Research Co.)
Cyclic Steam Stimulation (CSS) is a cost-effective means to produce heavy oil at the Cold Lake field in Alberta, Canada. The high viscosity of bitumen is the main obstacle to economic production, but the bitumen viscosity decreases significantly with temperature. Steam is injected at fracturing conditions, resulting in complex interactions of reservoir expansion (dilation) and contraction (recompaction) that propagate stress and strain fields in the overburden.
The mechanical loads on wells resulting from this production process are an important design consideration. To enhance operational integrity, a dedicated passive seismic monitoring well is installed on new development pads to provide early detection of casing failures and possible fracturing of the formation overburden. There is now an installed base of almost 90 such acoustic monitoring wells in the operator's field. With data acquisition of 15 to 30 geophones per system, recording continuously at 2000 or 3000 samples per second, the data management issues for this monitoring network are challenging.
Several classes of acoustic events have been identified, including those due to casing failure, formation heave, near-wellbore cement cracking, and production rod pump background noise, in addition to "Continuous Microseismic Radiation?? (CMR) that resembles harmonic tremors. Most casing failures are detected by observation of singular events. The detection of fracturing of the overburden, which may include the presence of bitumen and/or produced water that has migrated out of zone, is a more complex process that requires distinguishing shear events and CMR events from normal formation heave and other environmental noise.
The operator has stewarded the development of a cost-effective system that includes local pad data acquisition, uploading of selected data to a server with data archiving facilities, and downloading data to dedicated analysts. This paper will present a summary of the data management and processing technologies developed to address the challenge of managing this data-intensive problem.
For more than a decade, BP has been deploying a growing range of 4-D seismic technologies, and applying these to a variety of reservoir situations. This paper reviews the "macro" view of BP's 4-D experience and offers insights into possible emerging future trends, giving a wider context to complement other IPTC papers on specific 4-D technologies.
BP has experience in about 80 operated and 30 non-operated surveys* around the world, concentrated in the North Sea and Gulf-of-Mexico (GOM). Reservoir types surveyed include clastic, carbonate and fractured under different recovery schemes, including depletion, secondary water-floods and tertiary EOR schemes. The main historical "mode?? of 4-D data acquisition for BP has been with marine surface-tow streamer operations, acquired every 2-5 years. However, by the time of this presentation, BP will have installed and be operating its third permanent ocean bottom cable (OBC) seismic monitoring system.
The bulk of successful track-record to date has been in oil reservoirs under water-flood, using streamer data. Significant value has been generated through improved targeting of infill and development wells, and increasingly through improved reservoir management and reducing drilling hazards. Permanent seabed cable systems are now providing high quality wide-azimuth 3D seismic images and ‘on demand' reservoir surveillance to meet the development challenges of the most complex reservoirs. Other emerging technologies include land 4-D, permanent in-well 4-D VSPs, passive seismic monitoring, and development of quantitative integration of 4-D data into reservoir models.
With 4-D now being increasingly accepted as a valuable and maturing reservoir management tool, and with many fields and projects around the world moving into the production phase, a global expansion in 4-D activity, certainly within BP, is now emerging. This will require careful deployment of the most appropriate technologies from an ever-expanding 4-D toolkit, as considered in this paper.
Over the course of the last 10-15 years, BP has helped lead the testing, development and widespread deployment of 4-D seismic technologies that are now used around a significant proportion of its worldwide asset portfolio (Figure 1). From initial investigations in the early-mid-1990's using legacy repeat 3-D surveys to investigate the possibility of detecting 4-D effects over established oil-fields, 4-D application is now considered routine in many areas with proven business value, and very often a fully integral part of field management. Early testing and deployment was dominated by the North Sea "4-D laboratory", rapidly followed by the deepwater Gulf of Mexico and now an ever-increasing expansion towards more global application to both existing (e.g. Alaska) and new and emerging production (e.g. Azerbaijan, Angola). Technologies have developed and diversified from simple marine streamer operations to now include high-spec overlapping and steerable streamers, permanent ocean bottom cable (OBC) systems, of which BP now has the world's first three systems, and the early testing of permanent in-well VSP monitoring. Processing, interpretation and integration technologies continue to evolve to ensure maximum value from the acquired data.
However, despite the major strides in the maturity and acceptance of the 4-D monitoring method, some big challenges and questions remain. Why is 4-D not used on many more fields and on different types of reservoir? Why hasn't every operator and region decided to use 4-D technology yet? What are the appropriate technologies to use? What will be the future role of 4-D monitoring in ever more efficient field exploitation and in the drive towards ultimate recovery?