IBP3018 MINIMIZING DRILLING RISKS FOR EXPLORATION WELL IN DEEP WATER USING SEISMIC WHILE DRILLING TECHNOLOGY Sanchez Adrian 1, Mora Alfonso 2 Aguilera Leonardo 3, Gaitan Rito 4 Copyright 2010, Brazilian Petroleum, Gas and Biofuels Institute - IBP This Technical Paper was prepared for presentation at the Rio Oil & Gas Expo and Conference 2010, held between September, 13-16, 2010, in Rio de Janeiro. This Technical Paper was selected for presentation by the Technical Committee of the event according to the information contained in the abstract submitted by the author(s). The contents of the Technical Paper, as presented, were not reviewed by IBP. The organizers are not supposed to translate or correct the submitted papers. The material as it is presented, does not necessarily represent Brazilian Petroleum, Gas and Biofuels Institute opinion, nor that of its Members or Representatives. Authors consent to the publication of this Technical Paper in the Rio Oil & Gas Expo and Conference 2010 Proceedings. Abstract PEMEX has implemented an extensive campaign to drill deepwater wells along the Gulf of Mexico (Mexican region) as part of their exploration program. One of the challenges in this region is the presence of salt, which affects the subsurface geology and creates a very complex structural environment. In this case study, a well was drilled beneath a salt dome in the southeast area of the Gulf of Mexico. This area presented a very strong structural complexity as a result of the salt tectonics of this dome. The 3D surface seismic analysis revealed the possible shallow gas hazards in this area, which added further constraints to the well placement. Perforating the well presented additional challenges beyond those of previously deepwater wells drilled because the presence of salt generates tectonic forces produced by the salt movement during migration to shallower zones, and in particular, because the well could cross salt sediments in the top part of the dome. We will present the results obtained after apply seismic-while-drilling technology to reduce some of the uncertainties produced by the presence of salt. We will also show how this information was used to look in front of the drill bit and measure the distance from the well to the salt flank in real time, allowing for decision making while drilling to optimize the drilling process. 1. Introduction We found several sedimentary basins in the Gulf of Mexico having different characteristics with the presence of salt presence being the most significant challenge. In those complex environments, the surface seismic is strongly affected for the salt. In some cases, salt makes it impossible to identify the borders of and base of salt domes, adding additional depth uncertainties due the velocity changes. Also, due the lack of borehole information in exploration areas, there are some uncertainties that cannot be eliminated until the first well has been drilled. Once that borehole information is available, it can be integrated with seismic information to calibrate the models with data measured at the wellbore. For this lack of borehole data, the information that could be recorded in real time during the drilling phase plays an important role in reducing the uncertainties (such as velocity) in exploration areas. The Kabilil-1 well was drilled beneath a salt dome in the southeast region of the Gulf of Mexico. This area presented a very strong structural complexity as a result of the salt tectonics of this dome. To explore the Miocene and Oligocene formations, the well was designed to be drilled vertically to a depth of 3,500 m and subsequently directional below the saline dome, reaching a maximum angle of 25 with a target depth of 5,350 m (measured depth). Perforating this well presented additional challenges beyond those of previously drilled deepwater wells because the presence of salt generates tectonic forces produced by the salt movement during migration to shallower zones, and particularly because the well could cross salt sediments in the top part of the dome at around 1800 m that could cause some additional problems for the drillers (Figure 1). Another challenge facing the drillers was to set the 16-in. casing just below to the fault plane, which was expected to be reached at 2200 m. This geological fault was thought to be the entrance point of a series of sediments that were pushed in an upward direction during the salt migration, which might have fluids with higher pore pressure that could create perforation problems. The drilling plan was to use the real-time velocity data obtained from the vertical seismic profile (VSP)/checkshot while drilling to update the seismic depth conversion, position the drill bit more accurately, and set the casing at the desired position crossing the fault. Another challenge for the drill team was to 1 Geophysics Engineer-Schlumberger 2 M.Sc. Petroleum-PEMEX 3,4 Geologists-PEMEX
drill very close to the salt flank, use a previously performed 3D geomechanics study to determine the influence of the salt on the stresses around the dome, and define how this could affect the wellbore stability for the well section closer to the salt flank. To mitigate the risks described, it was decided to include seismic while drilling in real time as a tool to reduce well uncertainties. Figure 1. Seismic section showing the possible salt where the well was to be drilled (red area), fault plane (red line) just below the possible salt body, and the critical zone where the well will be near the salt flank. 2. Seismic-While-Drilling Fundamentals Seismic-while-drilling technology provides conventional borehole seismic data in real while the well is being drilled. The system basically consists of a set of seismic sensors; i.e., an assembly containing multicomponent geophones (X,Y,Z) and two hydrophone collars in a logging-while-drilling (LWD) tool that allows recording borehole seismic data. Also, the system needs telemetry as part of the bottomhole assembly (BHA) to transmit the recorded data to the surface using the measurement-while-drilling technology (MWD) that transmits data to the surface using mud pulses. The energy source; i.e., the airgun array, which is part of this system is deployed a few meters below the water s surface and is fired during connections. Therefore, no additional rig time is required to run this service (Figure 2). These measurements, which include seismic time-to-depth conversion and obtaining reflections below the drill bit, are conducted to help to the drilling team make drilling and well construction decisions such as steering and deciding on casing and coring points. This seismic-while-drilling technology provides standard borehole seismic information in real time that can be exploited for drilling optimization, cost savings, and safety improvements. Checkshot (time/depth) data are used to place the bit on the seismic map and help well navigation and casing point selection in addition to avoiding drilling hazards such as pore pressure that is observed on the seismic. Real-time seismic velocities can be used to update pore-pressure predictions from surface seismic. Ultimately, the real-time velocities, combined with look-ahead images formed by the seismic reflections from horizons ahead of the bit, provide a direct measurement of the distance to a marker of interest. Figure 2. Left Seismic-while-drilling tool with sensor configuration. Right Seismic-while-drilling data acquisition: energy source fired, the first arrival (green) detected for the tool, later reflections below the drill bit (yellow) arrive at the tool, and finally this information is transmitted to surface using MWD telemetry (red). 2
3. Feasibility Study To determine if the seismic-while-drilling technology could really help in solving the drilling challenges for this complex well, it was necessary to perform a feasibility study. This study consisted of simulated data acquisition with the information available and building a 3D model with the information provided for the G&G team; i.e., interpreted horizons, velocity from surface seismic, density values, and the well deviation. The study was performed for two different applications: 1) salt detection below the drill bit and 2) determine salt proximity to the well trajectory. 3.1. VSP in the 16-in. Section to Look Ahead of the Bit The model that was built handled two different geological scenarios. In the first scenario, it was assumed that the well would be drilled through salt sediment between 1800 m and 2000 m. The salt tongue, according to the interpreters, could be associated with the salt dome. This option presented some risks for the drill team due the additional needs for drilling inside the salt, which normally requires changes in the mud weight and can also result in the need for additional casing at the salt exit. For the second scenario, it was assumed that the well would be drilled only in clastic sediments, basically a sequence of sandstone and shale, which is the best scenario for drilling team without any additional drilling challenges compared with scenario one. For both scenarios, the simulation was performed by deploying sensors inside the well along the entire 16-in. section (between 1500 m to 2200 m) and the energy source at the rig location for a zero-offset VSP geometry. The plan was to reproduce real-time acquisition by obtaining the synthetic data for both cases and process them to obtain the results (Figure 3). Figure 3. Left Assuming the well is drilled through salt with processed VSP showing the synthetic response with strong amplitudes at the top and base of salt. Right Scenario where the well is drilled only through clastic sediments and the synthetic VSP results showing weak amplitudes. Based on the seismic amplitudes obtained in this simulation, this feasibility study showed that is possible to differentiate between both possible geological scenarios based on the seismic amplitudes obtained in the simulation where a characteristic response is observed for the salt body and for clastic sediments. For the salt, we can see a clear response (strong amplitudes) for the top and base; for clastic sediments, the observed reflections have poor amplitudes. Those amplitude variations are due to the fact that the seismic reflections are sensitive to the acoustic impedance (velocity x density) contrasts between the different geological formations and the salt shows a very strong velocity contrast against the sediments surrounding it. 3.2. Salt Proximity Survey in the 13 3/8-in. Section to Determine the Distance Separating the Well from the Salt Flank For this real-time salt proximity survey, the same 3D model previously created was used. This model was completely updated with the salt dome interpretation and velocities, information that is very critical for this design. The idea is to determine the optimal source location to guarantee that the energy will cross through the salt and arrive at the sensors. We tested different source positions with several azimuths to identify the best position in which to confine the ray path to a 2D plane (to constrain the inversion). Based on the results obtained through this exercise, it was 3
determined that the optimal source location to guarantee the energy will be received for the sensors confined to a 2D plane was at 2700 m with an azimuth of 270 degrees (Figure 4). Figure 4. Salt proximity survey design showing the optimal source position at 2700 m with an azimuth of 270 degrees. 4. Job Planning and Execution To support the operations simultaneously when multidisciplinary groups are in different locations: 1.The crew working on the boat In charge of the navigation using a differential positioning system for accurate boat positions and the technical team supports the compressors and energy source 2. Field engineers working on the rig Perform data acquisition and QC of the data recorded 3. Processing team Work in the computer center to perform the data processing and QC of the data transmitted in real time from the field (through satellite system). This team works together with the area interpreters on the analysis of the results obtained during the entire project. 4.1. Checkshot and VSP in the 16-in. Section to Look in Front of the Bit The results obtained in the feasibility study confirmed that seismic while drilling can be a valuable tool for resolving drilling uncertainties. It was therefore proposed seismic-while-drilling technology be used in the interval between 1500 m to 2200 m, which corresponds to the 16-in. casing section. The seismic LWD tool was included in the BHA located 33 m from the drill bit. This tool will be recording the seismic energy using three multicomponent geophones and hydrophones to confirm that the well is vertical or deviated. For the energy source, we used an array containing eight airguns with a total capacity of 1,200-ci and a 2,000-psi firing pressure. A boat was used for the source deployment, (Figure 5) allowing for the possibility of a deviated the well (in case of salt presence) and to perform a vertical-incidence VSP to obtain better accuracy in the drillbit position on the seismic map. Due to space limitations on the rig, the boat was located 71 m away from the rig with an azimuth of 80 degrees. Figure 5. Left Boat with airgun array deployed by the crane. Right Array with eight airguns 4
A total of 17 levels (Figure 6) between 1503 m and 1955 m were transmitted to surface in real time. These data were excellent quality. This information was received in the processing center where analysis and data interpretation were performed. To assist in making decisions while drilling, 11 updates were delivered to the G&Gs, drillers, and operations teams involved in the project. Figure 6. Left Hydrophone data showing clearly the first arrival waveform and the transit time in red. Right VSP data processed in real time to determine the events below the drill bit. Once that the data arrived to the processing center, tables containing the checkshot information (time-to-depth relationships) were created and delivered. This information was used to update the drillbit position on the seismic map. Transmitting the first five levels in real time made it possible to initiate the VSP processing, look ahead below the drill bit, and obtain a corridor stack with information below the drill bit (Figure 7). This VSP was updated constantly with the new levels acquired and confirmed that the sediments to be drilled were showing the pattern identifying a sequence of clastic sediments (not very strong amplitude changes) instead the salt body. This information was analyzed by the area seismic interpreters and provided a valid interpretation. These data were integrated with the surface seismic data available for the well to confirm the match with the VSP and the drillbit position. When the well was drilled through the interval between 1800 m and 2000 m. the geology was confirmed to be sandstone and shale, and also confirming the model and the results obtained with the real-time VSP. Figure 7. Surface seismic section showing the match with the real-time VSP and the drillbit position. On the VSP, the data below the drill bit show homogenous reflections and not the strong amplitude expected for salt presence. This interval was drilled without any problems and eliminated any questions about the salt presence. The drilling continued and the next challenge was to set the 16-in. casing at the right position just below the fault plane. The real-time checkshot made it possible to map accurately the drillbit position on the seismic section and with the measured velocities, was it possible to estimate the distance from the current drillbit position to cross the fault plane. When the drilling began, the fault zone was estimated to be located at 2080 m, and the sequence of sediments dipping 5
upward was estimated to be at 2140 m. This information was shared with the drillers and once that the drill bit arrived at 2140 m and was mapped on the seismic section (Figure 8), the decision was made to stop drilling and set the casing to avoid any drilling problems. The mud weight was almost at the maximum possible value and made it very risky to enter those formations below the faults without any margin to increase the mud weight in case an abnormal pressure might be found. Figure 8. Defining the fault position for setting the 16-in. casing but before drilling the sediments with upward dips. For this section of the well, the checkshots and VSP in real time (while drilling) reduced the uncertainties associated with the salt body presence in the well trajectory and also to set the casing across the fault before drilling a sequence of sediments that could have an abnormal pressure and compromise the well success. 4.2. Salt Proximity Survey in the 13 3/8-in. Section to Determine Distance between the Well and the Salt Flank For this data acquisition, the boat was mobilized according to the feasibility study by staying 2700 m away from the rig with an azimuth of 270 degrees. The BHA configuration was identical with that in the previous section; i.e., the seismic LWD tool was located 33 m away from the drill bit. The tool will be recording data using 3-C geophones plus hydrophones; however, the first arrival traveltimes will be taken from the hydrophone sensor and transmitted in real time while the other channels will be recorded in memory mode only. The suggested acquisition interval for the entire section was between 2200 m and 3400 m. Because of the distance between the boat the rig team, communication is an important factor for this kind of survey geometry because it is necessary to ensure that the signal sent from the rig to activate the source is perfectly synchronized. Also, an accurate navigation system is important to keep the boat in the desired position. A gun-control module facilitated communication via an ultrahigh frequency antenna (UHFA) with the surface system equipment on the rig. We recorded a total of 18 levels between 2175 m to 2658 m. This information was used for the processing team to perform the inversion and obtain the distance between the well trajectory and the salt flank. Figure 9. Seismic data, recorded for salt proximity survey, were acquired at 18 levels between 2175 m to 2658 m MD with the data showing the first-arrival energy in the three axes used to compute the arrival angle. 6
To perform the inversion and compute the salt flank location, the 3D velocity model was constrained with the new information available. The salt velocity was assumed to be 4500 m/s from previous measurements of salt bodies; the water velocity used was 1500 m/s; and the velocity for the sediments above the salt dome was determined from the checkshot survey acquired in the previous section using the seismic-while-drilling tool. A real-time salt proximity solution was computed for every station. These data were delivered to the G&Gs and drill team every few hours, indicating the current distance of the wellbore from the salt flank. The results obtained showed that the well was closer than expected to the salt dome (Figure 10); i.e., an expected minimum distance of 200m. Receiver Depth MD Horizontal Distance Between Receiver and Salt Flank (m) (m) 2175.7 196. 4 2204.3 185. 7 2232.9 176. 0 2261.1 182. 0 2289.4 184. 0 2318.2 187. 5 2347.0 183. 4 2375.8 178. 4 2404.4 175. 8 2432.6 177. 9 2460.9 172. 7 2489.1 171. 4 2517.2 167. 7 2545.8 164. 1 2573.0 163. 0 2601.3 171. 3 2629.6 179. 8 2658.1 175. 7 Figure 10. Left Salt proximity results (red dots) vs. interpretation. Upper center Salt flank from interpretation vs. salt proximity. Lower center Interpreted salt was moved to adjust with salt proximity results. Right Table showing the distances between salt flank and well position for each recorded station. According to the inversion results, the closest distance between the well and the salt flank was 163 m at a depth of 2573 m. At this distance, no drilling problems occurred. For this reason, it was not necessary to change the well trajectory, allowing for successfully steering the well, keeping the vertical trajectory planned, and staying a minimum 150 m from the salt flank. Processing and interpretation support was provided 24/7. The acquisition plan changed once the drillers determined that the critical zone was already drilled. For this reason, the acquisition was stopped at 2658 m when the well began to separate from the salt dome, as can be seen in Figure 10 for the deepest level. 7. Conclusions Based on the results obtained with the seismic while drilling, using real-time VSP to obtain information below the drill bit made it possible to determine that the well would not traverse a salt body. Instead, drill would go through a clastic sediment sequence, which provided confidence to continue drilling this interval with the same parameters. Using the checkshot information in real time made it possible to accurately position the drill bit on the seismic section and reduce any uncertainty related to depth conversion. Also, availability of this information allowed to optimize the position of the 16-in. casing avoiding any possible problems below the fault. With the salt proximity survey, it was possible to compute the distance between the well trajectory and the salt flank in real time. This reduced the uncertainties related to seismic depth conversion and positioning and provided confidence to the drillers to maintain the well trajectory through this critical interval. It was confirmed that the prestack depth migration (PSDM) provided an accurate response regarding the salt dome depth compared with the depth of other available seismic sections (based on the salt proximity results). The velocities obtained in real time were used by the geomechanics team to constrain their models, especially for pore pressure prediction, which brings additional value to the information recorded. 7
7. Acknowledgment The authors would like to express their appreciation to PEMEX for providing support and releasing the data that allowed for presenting this paper at this important technical congress. We would also like to acknowledge the deepwater PEMEX team (Activo Integral Holok Temoa), and also Subgerencia de Ingeniería de la División Marina, Gerencia de Ingeniería y Tecnología de la Unidad de Perforación y Mantenimiento de Pozos, for their vision to use advanced technologies for the new challenges found in this complex deepwater environment. A special thanks to Schlumberger for their support in publishing this paper, to the field engineers involved in this project: Michel Verticcio, Michele Bresson, and Ron Miles; and to the processing team: Roberto Castañeda and Manuel Vega. 8. References HAWTHORN, A., DERI, P. Hazard Avoidance and Well Placement from Borehole Seismic While Drilling, CPS/SEG 2009 International Geophysical Conference and Symposium, Beijing, 2009. PERRIN, J.C., JANAK, P., JOHNS, J., FRIGNET, B. Seismic-While Drilling: 2001-2006 Experience at Total and the Way Forward, EAGE/SPE SWD Workshop, Dublin, March 2007. SKERYANC, T., DURRAND, C., DERI, P., HAWTHORN, A. Drilling In Time: Geo-steering a Well using Real-Time Borehole Seismic Measurements: A Case History from the Gulf of Mexico. SEG 2005. ESMERSOY, C., HAWTHORN, A., DURRAND, C., ARMSTRONG, P. Seismic MWD: Drilling in Time, on Time, It's about Time, Leading Edge, January 2005. DERI, C. P., LANDGREN, K.M.; A Mechanized Process for Proximity Survey Interpretation, First Break, Volume 5, pages 59-66, 1987. 8