Time-lapse 3D Seismic Surveys Research Articles

Monitoring Results after 36 Ktonnes of Deep CO2 Injection at the Aquistore CO2 Storage Site, Saskatchewan, Canada

The Aquistore CO2 Storage Site is located in southeastern Saskatchewan, Canada. CO2 is injected into a brine-filled sandstone formation at ∼3200 m depth immediately above the Precambrian basement. Sustained injection rates of 400-600 tonnes/day were achieved at the site starting in the fall of 2015 with a total of 88 ktonnes having been injected by the end of September, 2016. Seismic monitoring methods have been employed to track the subsurface CO2 plume and to record any injection-induced seismicity. Passive seismic monitoring is being conducted using two orthogonal arrays of short-period geophones, 3 broadband seismographs, and an array of downhole geophones. No significant injection-related seismicity (Mw > -1) has been detected during the first 17 months of CO2 injection. The first post-injection time-lapse 3D seismic surveys (surface and VSP) were conducted at the site in February, 2016. The VSP data were acquired with a distributed acoustic sensing system using a 2750 m casing-conveyed optical fibre cable in the observation well. 3D seismic modelling of fluid flow simulations in conjunction with seismic repeatability estimates obtained from field data indicate that the time-lapse VSP should be capable of imaging the CO2 plume after a total injection of ∼30 ktonnes. In addition, this first monitor survey tests the ability of surface seismic data acquired with a sparse permanent array to detect or image the CO2 plume after limited injection. Time-lapse logging is being conducted on a regular basis to provide in situ measurement of the change in seismic velocity associated with changes in CO2 saturation.

Integrated characterization of hydraulic fracture treatments in the Barnett Shale: The Stocker geophysical experiment

We integrated several independent geophysical and geologic methods to examine the effects of stratigraphic and structural heterogeneities on the growth of hydraulic fracture networks from two horizontal wells in the Barnett Shale, Fort Worth Basin, Texas. Our data set included time-lapse 3D seismic surveys, microseismic data, wireline logs, and distributed temperature sensing (DTS) data. We first created a local stratigraphic framework using wireline logs. In our area, the lower Barnett Shale consists of siliceous mudstones (the primary reservoir) intercalated with carbonate submarine fan deposits. The latter are low porosity (i.e., nonreservoir) and, if thick enough are potential baffles to the growth of hydraulic fractures. We used stochastic inversion to define the 3D distribution of fan lobes with much better resolution than could be obtained using deterministic inversion and obtained a geologically reasonable lithology prediction. The lowest of the fan lobes partially overlies the two horizontal wells, and its limits could be defined using wireline logs, the stochastic inversion, and seismic attributes (e.g., coherence, seismic facies classification). As suggested by the distribution of microseismic events, the extent of this lobe (locally up to 80 ft/24-m-thick) had a significant impact on the growth of the hydraulic fracture networks. The DTS data showed that high production correlates to dense microseismic activity in this area. Our time-lapse seismic analyses suggested that velocity changes induced by the hydraulic injections are detectable, although (largely because of logistical problems) the data were inadequately sampled to quantitatively define these changes. Alone, none of the analyses described herein provided an adequate understanding of the subsurface. However, once integrated, our multidisciplinary work provided a coherent, if still largely qualitative, understanding of the relationships between the geology and the growth of hydraulic fracture networks and some of the geophysical and engineering methods that can be used to define those links.

CO2 storage monitoring: leakage detection and measurement in subsurface volumes from 3D seismic data at Sleipner

Demonstrating secure containment is a key plank of CO2 storage monitoring. Here we use the time-lapse 3D seismic surveys at the Sleipner CO2 storage site to assess their ability to provide robust and uniform three-dimensional spatial surveillance of the Storage Complex and provide a quantitative leakage detection tool. We develop a spatial-spectral methodology to determine the actual detection limits of the datasets which takes into account both the reflectivity of a thin CO2 layer and also its lateral extent. Using a tuning relationship to convert reflectivity to layer thickness, preliminary analysis indicates that, at the top of the Utsira reservoir, CO2 accumulations with pore volumes greater than about 3000 m3 should be robustly detectable for layer thicknesses greater than one metre, which will generally be the case. Making the conservative assumption of full CO2 saturation, this pore volume corresponds to a CO2 mass detection threshold of around 2100 tonnes. Within the overburden, at shallower depths, CO2 becomes progressively more reflective, less dense, and correspondingly more detectable, as it passes from the dense phase into a gaseous state. Our preliminary analysis indicates that the detection threshold falls to around 950 tonnes of CO2 at 590 m depth, and to around 315 tonnes at 490 m depth, where repeatability noise levels are particularly low. Detection capability can be equated to the maximum allowable leakage rate consistent with a storage site meeting its greenhouse gas emissions mitigation objective. A number of studies have suggested that leakage rates around 0.01% per year or less would ensure effective mitigation performance. So for a hypothetical large-scale storage project, the detection capability of the Sleipner seismics would far exceed that required to demonstrate the effective mitigation leakage limit. More generally it is likely that well-designed 3D seismic monitoring systems will have robust 3D detection capability significantly superior to what is required to prove greenhouse gas mitigation efficacy.

Development of a Permanent OBC System for CCS Monitoring in Shallow Marine Environments

In the CCS monitoring, time-lapse 3D seismic survey is necessary and microseismic monitoring is also required to assure the safe CCS operations. In order to fulfill these requirements efficiently, we are developing a permanent Ocean Bottom Cable system (OBC) in shallow marine environments. The system can figure out the extent of CO2 injected area and assure that CO2 is not escaped above seal rocks. The use of the system is advantageous from the long term view of the cost. In this paper, we, firstly, present a simulation study based on the data from the Nagaoka CCS test site. 4D response was evaluated using crossplot ofNRMS and PRED indices so that we could estimate the discrimination degree between 4D responses caused by CO2 injection and other 4D noises. Basic test experiments of a permanent OBC system have been conducted in Sites A and B in Japan and repeated seismic surveys using airgun source were shot for evaluating the 4D noise response. Tidal correction is found not to be simple as the wavelet shape itself is modified in the shallow water condition. P-SV reflections are recorded with three-component geophones installed in the OBC which will contribute to the CCS reservoir characterization and monitoring. A microseismic event with the magnitude of 0.6 occurred at the depth of 103 kilometers just below Site A was detected. As the CO2 geological sequestration will be conducted within several thousand meters, detectable limit is estimated down to magnitude minus two in an ideal condition.

Estimation of Steam Chamber Extent Using 4D Seismic

Summary The Steam-Assisted Gravity Drainage (SAGD) process has been successfully implemented to produce ultra-viscous bitumen from the Athabasca oil sands in the province of Alberta. In the Hangingstone area, 15 pairs of SAGD wells had been drilled in the reservoir by 2006, each a maximum of 30 m in thickness and approximately 300 m in depth. The production reached an average of 8,000 BOPD in recent years. The reservoir is geologically characterized as a stacked incised valley with fills in fluvial to upper-estuarine channels. Thin mudstone layers and abrupt changes in facies caused by sedimentary deposits present complexities and difficulties for SAGD implementation. A 3D seismic survey was conducted in 2002 to obtain a clear view of geology that was fully utilized for planning additional wells. In order to evaluate SAGD efficiency and performance, a time-lapse 3D seismic survey was carried out in 2006. In this paper, P-wave velocity (Vp) maps, transformed from the seismic travel-time maps, were interpreted with a new methodology for evaluating the areal extent of the steam chamber zone created by the SAGD process. In the previous experimental study of seismic velocity measurements with oil sands cores, Vp was found to steeply drop with an increase in temperature and to gently decrease with an increase in pore-pressure. Based on the experimental results, a petrophysical model was formulated to express Vp as a function of temperature, pressure and water saturation. The high-pressure and high-temperature zone of the SAGD process should generate differences between the first (2002) and second (2006) Vp maps from which we can estimate the area of the reduced bitumen viscosity with a temperature increase. As effects of pressure are probably more areally extensive than effects of temperature, these two effects on the Vp maps need to be segregated. As a new method, a scaling factor for the Vp reduction was first estimated to adjust the laboratory-scale and field-scale. We then calculated a distribution of Vp reduction corresponding to steam chamber conditions in order to decouple composite effects of temperature and pressure, based on the petrophysical model. Distinguishing the high-temperature and high pore-pressure zone from the low-temperature and high pore-pressure zone, we could determine a steam chamber distribution. The bitumen volume in the steam chamber zone was estimated and compared with the actual production. The methodology, interpretation procedures and results obtained are presented in detail.

Seismic monitoring ofin situcombustion process in a heavy oil field

Three time-lapse 3D seismic surveys are analysed to monitor the effect of in situ combustion, a thermal-enhanced oil recovery process in the Balol heavy oil reservoir in India. The baseline data were acquired prior to the start of the in situ combustion process in four injection wells, while the two monitor surveys were acquired 1 and 2 years after injection start, respectively. We present the results of baseline and second monitor surveys. Fluid substitution studies based on acoustic well logs predict a seismic amplitude decrease at the top reservoir and an increase at the base reservoir. Both the amplitude dimming at the top reservoir and the brightening at the base reservoir are observed in the field data. The extent of the most pronounced 4D anomaly is estimated from the seismic amplitude and time shift analysis. The interesting result of seismic analysis is that the anomalies are laterally shifted towards the northwest, rather than the expected east, from the injector location suggesting a northwest movement of the in situ combustion front. No clear evidence of air leakage into other sand layers, neither above nor below the reservoir sand, is observed. This does not necessarily mean that all the injected air is following the reservoir sand, especially if the thief sand layers are thin. These layers might be difficult to observe on seismic data.

４Ｄ地震探査によるオイルサンド貯留層の動的挙動把握

Time-lapse three-dimensional (3D) seismic monitoring study was conducted in the JACOS Hangingstone steam assisted gravity drainage (SAGD) operation area, Alberta, Canada. The objective of the study was to delineate steam-affected areas using differences between two 3D seismic data acquired at different production stages for efficient reservoir management.The time-lapse surveys were acquired in February, 2002 and in March, 2006. As repeatability is important for the time-lapse seismic surveys, the two 3D seismic surveys were recorded with nearly identical field acquisition parameters and the data sets of both surveys were processed with identical processing flows.P-wave and S-wave velocities of oil sands core plugs from the field were also measured under various pressure and temperature conditions to understand the relationship between seismic velocities and reservoir conditions. The laboratory measurement results were combined and a rock physics model was proposed to predict velocity changes of the oil sands under reservoir conditions expected during SAGD operations.The two seismic volumes show significant differences in seismic character within the reservoir and time delays below the reservoir around the active SAGD well pairs. Synthetic seismic data based on the rock physics model were analyzed to evaluate seismic response changes of the time-lapse 3D seismic survey. From our analysis, the differences of the seismic responses between the two 3D seismic volumes can be quantitatively explained by P-wave velocity decrease of the oil sands layers due to the steam-injection. In addition, our result suggests that a larger area would be influenced by pressure than by temperature.In conclusion, the time-lapse 3D seismic monitoring along with the rock physics model is useful for qualitative and quantitative estimate of the rock property changes of the interwell reservoir sands in the field.

A case history of time-lapse 3D seismic surveys at Cold Lake, Alberta, Canada

Time-lapse 3D seismic surveys were acquired across a bitumen field at Cold Lake, Alberta, Canada, during a production cycle (1990) and a steam-injection cycle (1992) of a thermal-enhanced oil recovery (EOR) program. We observed changes in interval traveltime and amplitude distributions between the processed surveys. We interpret the increased traveltimes observed over most of the injection survey to be a result of lowered interval velocities in the reservoir, caused primarily by higher temperature and lower effective pressure. Reflection-strength variations within the reservoir are present in each data set and change spatially between the surveys. In general, we interpret the amplitude anomalies seen only on the production survey to be caused by local free gas and the amplitude anomalies seen only on the injection survey, which are close to the perforation depths, to be caused by thin, vertically restricted steamed zones.