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Well Placement Using Borehole Images and Bed Bounda ry Mapping in an Underground Gas Storage Project in Italy

Massimiliano Borghi, Daniele Loi, Stefano Cagneschi , Stefano Mazzoni, Ermanno Donà ,, eni E&P, Augusto Zanchi, Davide Boiocchi STOGIT Joe

Gremillion, Filippo Chinellato, Nabila Lebnane, Reb ecca Lepp, Stephanie Chow, Simone Squaranti Schlumberger

This paper was presented at the 10th Offshore Mediterranean Conference and Exhibition in Ravenna, Italy, March 23-25, 2011. It was selected for presentation by OMC 2011 Programme Committee following review of information contained in the abstract submitted by the author(s). The Paper as presented at OMC 2011 has not been reviewed by the Programme Committee. ABSTRACT Multiple underground gas storage horizontal wells were drilled in 2008, 2009 and 2010 in Italy in several different fields. The wells were steered to maximize sand exposure in the target formations using a bed boundary mapping tool and borehole images. The wells were first landed based on offset pilot holes and a bit resistivity measurement. After the casing was run the production section was steered to total depth. Horizontal well drilling in Italy is challenging even for short horizontal wells because formations include steep dips, faulting and stratigraphic changes. Steering information was used in real-time by the geosteering team to overcome these issues and optimally place the wells and maximize the exposed permeability. This paper will more closely examine wells from two different fields to show how the real-time data were applied by the steering team to drill successful wells. The real-time data allowed a more optimized landing, maintenance in zone of interest, exit prevention and accurate detection of dip and the presence of shoulder beds. Steering results were verified after drilling using wireline magnetic resonance on drillpipe. Procedures were changed iteratively for each well to improve performance. By using the bed boundary mapping measurements and borehole images the geosteering team avoided sidetracks and steered these wells successfully to total depth. Without this information real-time decision making would have been more difficult and postwell interpretation less clear. INTRODUCTION As part of a multi-field gas storage project, multiple horizontal wells were drilled and steered using real-time LWD data. The objective of the wells was to expose as much sand as possible in the shortest well length. The wells were steered using teams made up of the wellsite geologist, directional drillers and field engineers out on the rig location and the geosteering team in town. The team in town was connected using satellite communications and a web-based data delivery system. The team in town worked in the operator’s office and was made up of geologist’s, petrophysicist’s and geosteering specialists. The real-time Logging While Drilling (LWD) data used for these wells came from two different LWD tools. One tool that provided a deep reading azimuthal distance-to-boundary

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measurement and a second tool that provided real-time borehole images. This data was pulsed to the surface then streamed to the web to be downloaded in the operator’s office. Proprietary interpretation software was used to calculate formation dips and invert distance-to-boundary and formation resistivities and present the data both in the office where the ENI team used the data to take the decision and modify if necessary the drilling plan. The planning and drilling procedure was similar on each well. The horizontal targets were picked out by the client geology team and a directional plan created. The plan was loaded into a geological model and a section cut for importation to the geosteering software. The model was populated with log properties from a pilot well, or a nearby existing well and a forward log model created to investigate the tool response of the steering tools to be used. Several other sections were created to characterize the tool response if the formation dip was higher or lower than expected. A pilot well was drilled to fully evaluate the reservoir near the landing location. All the geological data acquired on the Pilot Hole have been evaluated to optimize the Drain Hole planned profile section. The landing phase was sidetracked from the pilot well and the curve built using a rotary steerable tool along with resistivity and gamma ray LWD and a laterolog bit resistivity tool. The LWD measurements were used in the landing section, correlating with the pilot well and other offset wells. In OBM, the laterolog bit resistivity measurement responds at the bit where there is a current pathway from the BHA to the formation. This allowed the laterolog bit resistivity to be used as a top of sand indicator to pick the landing point. After the well was landed by the Stogit and ENI teams, the geosteering model was further updated and prewell steering meeting was held to present the modeling results and to discuss the steering plan for the lateral. Another key objective of these meetings was to look at possible contingency plans if the formation or trajectory don’t respond as planned. Finally the Horizontal phase has been drilled using the LWD tools, to navigate in the clean sands target lobes, applying the necessary corrections in realtime on the steerable equipment. First Case Study – Ripalta Field The first well drilled in this project was drilled in the Ripalta field. A layer-cake model was created based on offset wells and the map information. The map of the top of the target and the borehole images run in the pilot hole indicated that the dip was 2° to 3° upward in the well direction. A trajectory was planned to drill at the estimated formation dip in the top of the target formation. The well was landed successfully in the target formation by the operator using real-time logs and offset correlation data. Casing was run and the mud changed from a drilling mud to a drill-in type fluid after the float collar and shoe were drilled. Drilling commenced and the deep, directional distance-to-boundary measurement and borehole images gave a dip measurement that was rising 3° in the well direction, with a lower resistivity layer slightly more than one and one-half meters above. The first instruction to the rig was to build to 93°. (Figure 1 – Point #1) The trajectory then entered into a higher resistivity portion of the target, and it was decided to try to maintain the trajectory in this higher resistivity sand. The formation dip as measured by the distance-to-boundary measurements and dips from the borehole resistivity imaging tool was seen to be flattening out, the steering team in Ravenna used this information to ask the drilling team on the rig to drop inclination to 89° to try to avoid exiting the higher-resistivity formation. (Figure 1- Point #2)

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The clearest indication of what was happening was given by the raw curves from the distance-to-boundary tool. They were showing an increasing positive signal, which would indicate a conductive boundary above. The tool was sending a mixed signal; the deeper reading curves were changing very little while the shallower reading curves were seeing an approaching conductive boundary. This told the team that the trajectory was approaching an intermediate boundary, not the top of the sand but the top of the higher resistivity. Unfortunately, the dip change was too fast, and the trajectory entered the lower resistivity sand above before reentering the higher quality sand. Drilling then continued, holding 89° until an increasing negative signal and the distance-to-boundary inversion indicated a conductive bed below. (Figure 1 – Point #3). The inclination was built to 91°, but too slowly, and the trajectory crossed briefly into the lower quality resistivity sand below before reentering the good pay. The top of the structure appeared to flatten out then dip downward, and the well was drilled to TD with only a few nudges downward in inclination as attempts to keep the trajectory bed parallel with the formation. (Figure 1-Point #4)

Figure 1 is a screen capture from the geosteering s oftware illustrating the steering decision

points using the recorded tool data. The fine gree n lines are dipsticks measured by the borehole imaging tool.

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Figure 2 is a snapshot showing the realtime data an d interpretation that was provided while drilling for the second steering point

Second and Third Case Studies – Furci Field The Furci field was planned and drilled in a very efficient manner using batch drilling. The pilot wells were drilled first so that the field in the area of interest was evaluated with modern logs. An Oil Based Mud (OBM) was selected for the pilot holes and landing sections to avoid stuck pipe problems due to reactive shales that were seen in previous offset wells. Rotary steerable BHA’s were used for the landings and laterals, as well as in later pilot wells. A new 4 ¾-in. resistivity borehole imaging tool was used for these wells, and it gives higher resolution images than the ones seen in the previous example. More technical information can be seen in Appendix 1. The Furci Reservoir is included in a limited estention pliocenic torbiditic systems and consist of several lobes, and smaller laminations . The main target of project was recognized as the shallower sands lobes of main body. The procedure was similar for each well. The horizontal targets were picked out by the Stogit geology team and a development plan defined. The plan was loaded into the 3D geological model and few sections cut and studied using geosteering software. The model was populated with log properties from the pilot well and a forward log model created to investigate the tool response of the steering tools to be used. Several other sections were created to investigate tool response if the formation dip was higher or lower than expected. The plan was to use the LWD measurements in the landing section, correlating with the pilot well and other offset wells. The landing section would be sidetracked from the pilot and the curve built using a rotary steerable tool along with resistivity and gamma ray LWD and a laterolog bit resistivity tool. In OBM, the laterolog bit resistivity measurement responds at the bit where there is a current pathway from the BHA to the formation. This allowed the laterolog bit resistivity to be used as a top of sand indicator to pick the landing point.

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After the well was landed by the Stogit and ENI teams, the geosteering model was further updated and prewell steering meeting was held to present the modeling results and to discuss the steering plan for the lateral. Another key objective of these meetings was to clarify the communications plan for the lateral. With data links to the rig and inside the client’s office, it was important to verify that the links were functioning and to spell out how the steering team in Ravenna and the drilling team on the rig would communicate. Steering of first Furci well The well was landed as planned by the client team, using real-time LWD measurements. When the lateral was drilled out, the dip measured by connecting the inversion points from the distance-to-boundary tool was down at approximately 1° in the well direction. Unfortunately, there was no independent corroboration from the real-time borehole images because a software problem meant that no real-time images were acquired for the first sixty meters. (Figure 3 – Point #1) With the relative dip appearing to be 1°, the planned build from 88° to 90° was modified: drilling continued at 88° with the intention of cutting slowly down section to expose the upper sand layers. The bed dips were confirmed when the tools were pulled halfway through the drain to fix a non-related tool problem and the software problem was resolved. It soon became apparent that the trajectory was parallel to the formation. The borehole imaging tool was showing a bulls-eye, while the bed boundary mapping tool was showing conductive beds on both sides of the trajectory, paralleling the trajectory. A small change of 0.5° decrease in the inclination was made, but that had little effect (Figure 3 – Point #2). Finally, halfway through the lateral, again the interpretation of data received by LWD tools shown that distance to shale top boundary was too close and a reaction modified strongly the planned drilling profile, decreasing inclination by 1.5° to go below formation dip and cut down through the rest of the target sand. (Figure 3 - Point #3) As drilling continued it was apparent that the dip was flattening out, and it was discussed whether inclination should be built up closer to formation dip. (Figure 3 – Point #4) It was decided to continue at the lower inclination to ensure crossing through the entire section. Towards the end of the well the dip was seen to be rising, and the steering team discussed building inclination again in case the well length could be extended, but instead the inclination was held and the well drilled to TD, with the bit close to the base of the target sands.

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Figure 3 is a screen capture from the geosteering s oftware illustrating the steering

decision points using the recorded tool data.

Figure 4 Interpreted structural model with borehole images. The correlation is confirmed with the red dipsticks plotted on the sec tion that were measured by the

resistivity borehole imaging tool.

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Steering of second Furci well: The target reservoir for the second well appeared as two larger lobes separated by a thinner lobe and two shale beds on the offset pilot hole. The objective was to drill down through the shallower lobe, then cross the thin bed and navigate in the deeper lobe. The well was drilled out as planned following the geometric trajectory. The formation dips were measured by two independent tools: the points measured by the deep directional bed boundary detection tool when connected together delineate a formation dip measured at a distance, and the borehole imaging tool measures the dip of formations that cut across the borehole. As drilling commenced the dips from the distance-to-boundary measurements indicated a flat dip, the initial sinusoids gave a dip that was flat in the well direction, then slightly rising. The ENI team decided to maintain the planned trajectory until other data indicated a change in trajectory was needed. (Figure 5 – Point #1) Drilling continued and from the correlation it appeared that the trajectory had crossed the upper lobe and the thinner middle lobe. The dips from both the borehole images and bed boundary mapping tool indicated rising dip, the decision was made to build 1° over the next fifteen meter joint to make the landing in the lower lobe softer. It later became apparent that the distance-to-boundary measurement was measuring what appeared to be the lower target below us as a resistive bed. (Figure 5 – Point #2) To get down into this resistive bed faster a “nudge” was sent to the rotary steerable tool, causing it to decrease inclination by 0.5°. Drilli ng then continued with this inclination of 88°, with an expectation that the bit would soon be crossing into the lower lobe of the target. Prior to reaching the expected point of entry a sharp change in the raw measurements from the boundary mapping tool was seen, from positive to strongly negative in the space of just a couple of meters measured depth. Such a response is typically either a fault, or a very high angle stratigraphic event such as a channel perpendicular to the well direction. (Figure 5 – Point #3) The first decision was based the feature being a fault and the appearance of what looked like a resistive bed above the trajectory. It was decided to build inclination above 90° to go up to find this sand. But as drilling continued another high angle feature was interpreted. It was decided to continue down in the section to verify the presence or absence of the lower lobe of the target. (Figure 5 – Point #4) Drilling continued, holding a tangent until it was seen on the distance-to-boundary measurement that there was only lower resistivity below, out to a distance of a couple of meters true stratigraphic thickness (TST). It was decided to retrace our path back up across what could either be an upfaulted lower lobe or the upper lobe. The inclination was built up to 91°, drilling upsection, until we started to see higher resistivity zones above the trajectory with a dip of 0.5°. Evaluating this consistent var iation a modification of initial plan was defined, deciding to complete the drilling of the well in the upper lobe achieving the minimum clean sands extension required. The inclination was built further to 92° ensure crossing the upper lobe before the end of the well, (Figure 5 – Point #5) Drilling up through the upper lobe, the logs and images seemed to be a repeat section, confirming the interpreted position in the stratigraphy. The formation began to dip downward

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toward the end of the well, but to ensure that we crossed more of the upper lobe the inclination was held at 92°, drilling to TD with th e bit near the top of the upper lobe.

Figure 5 is a screen capture from the geosteering s oftware illustrating the steering decision points using the recorded tool data. The plot is of the distance-to-boundary

inversion plotted on top of the interpreted model.

. . Figure 6 is a snapshot showing the realtime data at the point of a suspected fault or

high angle stratigraphic event. The distance-to-bo undary inversion solved for a steep upward dipping conductive boundary, this has a simi lar signature to a fault.

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CONCLUSIONS This horizontal well project was drilled by a multi-company, multi-national team of people working in offices and on rigs around Italy, with support from Houston and Paris. Any successes were due to the teamwork and technology combined with the leadership from Stogit and ENI. The wells drilled were challenging, and the technology applied such as distance to bed boundary measurements and resistivity borehole imaging reduced uncertainty and made overcoming the challenges feasible. Having two different techniques for measuring formation dip allowed for confirmation between techniques. If the distance-to-boundary dip estimation matched the borehole image dip, then they are probably correct. Tools and software improved over the course of the project. A new 4 ¾” borehole resistivity imaging tool was successfully used and both the surface acquisition software and the geosteering interpretation software changed radically for the better over the project length. ACKNOWLEDGEMENTS

Thanks to ENI and Stogit for allowing this paper to be written and for the opportunity to participate in this project. REFERENCES Qiming Li, Dzevat Omeragic, Larry Chou, Libo Yang, Khanh Duong, Schlumberger “New Directional Electromagnetic Tool for Proactive Geosteering and Accurate Formation Evaluation While Drilling” SPWLA 46th Annual Logging Symposium, 2005 Qiming Li, Ted Bornemann, John Rasmus, Hanming Wang, Kyel Hodenfield, John Lovell, Schlumberger “Real-time logging while drilling image techniques and applications” SPWLA 42nd Annual Logging Symposium, 2001

APPENDIX For a complete understanding of the physics and interpretation of distance-to-boundary measurements and resistivity borehole images, see References 1 & 2. A quick guide to interpreting the distance-to-boundary raw curves and inversion can be seen in Figure 7. The tool measures the phase shift and attenuation curves that have a characteristic response near a bed boundary; a positive signal near a conductive over resistive boundary, and a negative signal near a resistive over a conductive boundary. Different depths of investigation are used to calculate distances to two boundaries during the inversion process.

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Figure 7 is a graphic showing the typical response of the distance-to-boundary measurement with the tool crossing from a conductiv e to resistive boundary or vice

versa. Polarity is independent of the crossing dir ection. A similar description for interpreting borehole images is shown in Figure 8. The tool’s sensor rotates as the drilling string is rotated. The data is plotted on a log by cutting the image at the Top of the hole (TOH), creating log that is centered on the bottom of the hole. If a feature begins at the top of the hole, the trajectory is said to be drilling upsection. If a feature begins at the bottom of the hole, the trajectory is drilling downsection. Crossing down then up (or the inverse) is called a “bullseye”, and implies the trajectory is parallel to dip at that point, as do parallel features on the image.

Figure 8 is a graphic showing the basic concepts in volved in interpreting borehole

images. Upward facing features indicate drilling u psection. TOH is Top of Hole, BOH is Bottom of Hole.