Copyright 2003, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in Denver, Colorado, U.S.A., 5 8 October 2003. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract

This paper briefly describes a process developed to reduce drilling risks and well costs and gives details on its application to three deviated development wells in Camisea, Peru. Previous offset vertical and deviated wells in this area encountered wellbore instability, drilling fluid loss, and reactive shales. In some cases these events made it necessary to drill multiple sidetrack wells.

The process provided specific advantages while drilling technically difficult trajectories. Integral to the process was development of a mechanical earth model (MEM) for prediction of drilling events and down hole drilling risk management. The model, created using data from multiple disciplines (seismic, drilling, geology, wireline logs, core testing), enabled the drilling team to understand potential drilling hazards and quickly act to mitigate risks, as well as to make rapid informed decisions while drilling. Examples demonstrate how the process compared forward predictions with actual results and how the model was updated during drilling.

The first well reached total depth (TD) 5 days ahead of schedule even though the trajectory was in a difficult stress azimuth and several nondrilling problems occurred. Teamwork and communication among the drilling location and four offsite offices played a critical role in the decision process. Predrill predictions matched post-drill information in most cases. Lessons learned from the first well were applied to subsequent well plans.

This process can be applied to any exploratory or development well, but high-risk, high-cost wells receive maximum benefit. Although wellbore instability resulting from tectonic stress was the main risk in this field, the process is equally valid for drilling issues such as overpressured regimes, underbalanced drilling or extended-reach wellbores.

Introduction The Camisea blocks (38/42) are located in the tectonic

active foothills of the Peruvian Andes (Fig. 1). Initial discovery of the San Martin structures and drilling of exploratory wells occurred in the mid 1980s and early 1990s. Wellbore instability, drilling fluid loss, and reactive shales were common drilling problems and in some wells made it necessary to drill multiple sidetracks.

In this remote jungle area, environmental issues and logistics constrain multiple pad locations for development wells. Drilling of multiple deviated wells is done from a single pad, similar to offshore platform drilling. Early in the planning, it was realized that directional wells would be more costly and incur additional risks. To evaluate the potential risk and plan for mitigation, a core team was designated to analyze previous drilling problems, create a plan for reduced risk drilling, and monitor and update the plan while drilling. The team consisted of experts in geomechanics, drilling, geology, petrophysics, and seismic from the operator and service companies.

As members of the team were geographically separated, a real-time monitoring system (Fig. 2) was used to keep everyone informed and to disseminate information. This system allowed secure posting of reports and documents to share with other team members along with real-time monitoring of rig parameters and downhole sensors via the Internet.

To show how the process worked, we begin by covering the initial planning for the first well, describing how the plan was applied and updated, then examining results from three wells.

Developing the Process Drilling in technically demanding areas brings associated risk of the unknown. Without a geomechanics model constructed, small problems can become costly. Decisions are often made less on fact and more on feel. Building a geomechanics model after a problem occurs in real time is not a realistic solution given the short time frame needed for most drilling decisions. Having a plan and geomechanics model in place enables personnel to focus on signals before drilling events become a serious problem. When problems do occur, a model allows rapid, informed decisions to be made by the drilling team.

Development of this process and the MEM is a direct response to address drilling problems for a field. The process

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Using a Dynamic Mechanical Earth Model and Integrated Drilling Team to Reduce Well Costs and Drilling Risks in San Martin Field Donald Lee, SPE, Schlumberger, Juan Pablo Cassanelli, Pluspetrol, Marcelo Frydman, SPE, Schlumberger, Julio Palacio, Schlumberger, Roger Delgado, Pluspetrol, Bryan Collins, SPE, Schlumberger

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follows a four-phase procedure of data audit, pre-drill planning, drilling phase and post-job analysis with a feedback loop designed to continuously improve the cycle.1, 2

In the data audit phase, available data are gathered, organized, and examined to determine what key problems exist and if there are sufficient data to build a MEM. The pre-drill planning phase is used to build, calibrate, and verify the MEM and produce a drilling map. The drilling map is a description of risks, mitigations, recommended mud weights, geological and other information associated with a specific wellbore trajectory. It is the plan developed by the team to understand drilling and geomechanical risks before drilling is started. The drilling phase covers monitoring drilling parameters in real time, application of preventive actions, identifying contingency plans, verification of the model with new data, and updating of the model if necessary. Post job analysis includes review of the drilling phase and capturing of lessons learned to use for future drilling.

For San Martin field, the data audit started with a non-productive time (NPT) analysis of previous drilling events from offset wells (Fig. 3). The audit identified wellbore instability, reactive clays, hole cleaning, bit and bottom hole assembly (BHA) performance as major NPT contributors. Differential sticking, hydraulic fracturing, and drilling oblique to bedding were additional issues identified.3 Each of the problem areas was examined to determine its impact on drilling the planned trajectory and then how to reduce NPT. 4,5,6,7 Drilling events were visualized in 3D to determine their relationship both spacially and to geological horizons (Fig. 4).

Drilling, wire-line, geological, and seismic data were used to develop the MEM. Data were less dense above the reservoir, so an additional uncertainty existed in the initial model. Regional database correlations were used when necessary to fill in for missing data. Sensitivity analysis on input data using Monte Carlo modeling (Fig. 5) identified unconfined compressive strength (UCS) as having the most impact on stability results. Triaxial tests on whole core plugs from the reservoir were used to confirm and calibrate mechanical properties derived from wire-line logs. Wellbore stability results were compared with borehole images and oriented two-axis calipers to verify both shear and tensile failure modes (Fig 6). 8,9

In the overburden, multiple coupled modes of well-bore instability (stress, mechanical, reactive clay) were apparent, but not enough data were available to characterize the effect of each failure mode. Mitigation for each type of instability was included in the risk section of the drilling map used for the first well. Well 1 The Start of Real Time SM1001 was the first directional well drilled in the San Martin structure and reached TD 5 days ahead of schedule with minimal stability problems. The plan called for a 52o deviated wellbore after kick-off from vertical with azimuth close to maximum horizontal stress direction, a potentially difficult direction to drill based upon stress direction and magnitudes. While drilling at 500 m from the first target, an improved geological interpretation required dropping inclination quickly until reaching vertical, making the trajectory more complex. Mud log, logging while drilling (LWD), surface, down hole

drilling measurements, cuttings and cavings analysis allowed continuous monitoring of wellbore conditions and drilling performance. Comparison with expected parameters (equilivant circulating density (ECD), hook load, torque, weight on bit, vibration, etc) helped identify cavings build up, verify hole cleaning, and track bit and BHA performance. All this information was available in real time via the secure Internet distribution site and allowed the drilling team to make better decisions based on the same information.

One of the uncertainty areas identified in the pre-drill planning was horizontal stress magnitudes, especially in the overburden. These magnitudes are a key part of determining wellbore failure modes. The first opportunity to check the model in this area was at the 13 3/8 in. casing shoe. The casing point was set slightly shallower when symptoms of increasing instability, as predicted by the MEM, were observed at the rig site. Breakdown pressure was not reached on the formation integrity test (FIT), however, the tests were analyzed for minimum horizontal stress.10 When the maximum pressure reached was used as a lower bound for breakdown pressure, results showed initial estimation of differential horizontal stress was too high. The MEM was updated with the new information and mud weight windows were re-computed for the next hole section.

This was an important piece of information, because previous analysis from offset wells was not conclusive enough to separate stress related shear failure from chemical and/or mechanical related failure. A directional offset well in the area had multiple catastrophic problems in this intercalated, micro fractured shale section. MEM mud weight allowed drilling with minimum formation breakout or collapse resulting from mud invasion through micro fractures. With a lower stress component as indicated from the FIT, the approach to reduce wellbore instability through the reactive clays could be better treated with improved mud properties (potassium, glycol) than with only a higher mud weight.

Confirmation that the MEM was accurate came from two additional sources. The MEM predicted shear failure in the bottom part of the second section. Failure was verified by angular cavings appearing at the surface at depths predicted by the MEM (Fig 7). In addition, oriented two-axis calipers run after drilling showed hole enlargement, mainly in the wellbore azimuth and at the bottom the wellbore. Therefore, hole enlargement in this section was mainly due to the drilling process, mud properties were controlling reactive clays, and the MEM correctly predicted stress related shear failure. The MEM shear failure prediction enabled the well to be drilled at conditions close to the stability borderline. The small quantities of cavings were managed with hole cleaning while reducing the unnecessary mud weight overbalance.

FIT at subsequent casing shoes were examined for both formation breakdown and minimum horizontal stress. A comparison of the MEM minimum horizontal stress prediction and actual results after calibration in first hole section were very close and show the model is a very good predictor of minimum horizontal stress.

To construct the original MEM, log data from multiple wellbores were spliced to form a continuous data set. New wire line log data showed the original MEM was a good representation of basic geomechanic logs. The new log data

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were used to update the model and replace synthetic sections with measured data. Post job analysis of the calibrated model compared to the real events while drilling, provided a better understanding of the drilling events, along with improved procedures for the next well. Well 2 Applying Lessons Learned

Key lessons learned in the first well were applied in the planning of SM1004. Now the MEM was calibrated and the failure mechanism was better understood in sections above the reservoir. This well trajectory was more difficult in that it called for a 52o deviation with an azimuth that moved from west to north. A better bit selection and improved BHA configuration maintained the drilling performance for the first three sections consistently 7 days ahead of schedule, making the first big drilling performance improvement. The MEM correctly predicted minimum horizontal stress from FIT at three casing shoes. Cavings caused by low mud weight were also predicted from the model. Targets were modified during drilling based upon interpretation of new 3D seismic. A new trajectory achieved the revised geological requirements. The MEM was updated and mud weights were corrected for the new plan.

In the last hole section, a piece of junk was accidentally dropped while a stiff BHA was run in the hole. The junk caused stuck pipe in the open hole section, and sidetrack of the wellbore was required. The MEM was used to assess the risks in placement and orientation of a whipstock for cutting a window in the casing The window was cut and drilling reached TD only 3 days behind schedule. In the sidetrack, wire-line logging was limited as a result of enlarged hole and ledges in an interbeded claystone/silty-dolomite/chert/ section called the Shinai. The liner would not pass through the formation and was set in the middle of the section. Post analysis of this section using multiple passes of an LWD tool to measure electronic borehole diameter demonstrated the hole immediately enlarges when drilled and continues to enlarge with excessive mechanical action such as reaming, back-reaming, or vibration during drilling. Recommendations for drilling through the Shinai with minimal mechanical impact were outlined in the plan for the next wellbore.

Well 3 Beating Previous Benchmarks

The SM1002 well trajectory was deviated at 55o with wellbore azimuth of 80o and reached TD 9.8 days ahead of schedule. Improvements were made in all drilling performance categories. BHA and bit configurations were optimized to drill every section in a single run. Rotary steerable systems were used to stay on trajectory, improving hole cleaning and hydraulics.

In the 16 in. section, larger cavings appeared at the surface. Though these few cavings did not cause any drilling problems, they signaled possible low mud weight or perhaps geological change drilling in this direction. During casing cementation, fluid return to the surface was lost and then returned, 38 bbl later. Fluid densities in the wellbore and outside the wellbore before and after the losses were analyzed. FIT at the shoe verified MEM minimum horizontal stress values and indicated possible existence of natural fractures.11 According to the MEM, a fracture should not have been created, as cementing

ECD did not reach fracture re-opening pressures. Seismic data were examined and a fault or fracture system near the casing shoe was identified. The fracture had initially been drilled through with lower ECD and a filter cake was formed before fluid loss occurred. The cementing preflush likely removed the filter cake, and with ECD higher than pore pressure, fluid flowed into the fracture. Fluid solids started to reduce permeability, the fracture sealed, and fluid returned to the surface (Fig. 8). 12

At the 11 in. shoe extended leak off test, a very unusual pressure response was measured. The first cycle reached breakdown and a slow leakoff was observed as expected. The test was repeated and when breakdown was reached, pressure rapidly dropped even after pumps were shut down. Careful examination of the data and comparison with the MEM minimum horizontal stress pointed to a downward fracture growth into a permeable sandstone. To assess if the fracture could grow to reach the permeable formation, MEM parameters were input in a fracture height simulator.13 Using the volume of fluid pumped after breakdown pressure (2.3bbl) the simulator predicted 11 m of growth downward, into the permeable sand. This helped explain the unusual pressure response (Fig. 9).

In the 8 in. section though the Shinai, careful drilling practices were used as recommended from lessons learned on the previous well. In this section, where other assemblies had dropped angle drastically, the rotary steerable system maintained trajectory, improving hole quality. No problems were encountered during wireline logging or running casing. Examination of calipers from different tools helped the team to understand both cause and timing of hole enlargement. Several passes from an LWD tool, which electronic measured hole diameter just behind the bit, and oriented 2 axis calipers from wireline logs were compared. The electronic hole measurement showed the hole size shortly after drilling through the Shinai. There is enlargement but very little difference between passes (Fig. 10). The two-axis caliper measurement showed enlargement magnitude to be smaller than the electronic diameter but was in overall agreement with the location of hole enlargement. Oriented calipers also indicated that the enlargement is stress induced and in the same stress azimuth as predicted from the MEM. This indicates that the borehole enlarged somewhat during the drilling process, but the combination of careful drilling practices while tripping in and out of the hole prevented the borehole size from increasing.

Results from Application of the Process

In the previous sections, examples were given to explain how the process works and decisions that the drilling team made using the MEM. How has this process affected the drilling performance? Two indicators were used to quantify drilling results.

Comparison of actual days with scheduled drilling days is a quick method to show performance against a plan. Fig. 11 combines two comparisons that help illustrate improvement in drilling days. The graph compares drilling days to TD for the three wells drilled in San Martin using this process. The blue column represents percent improvement of actual days to TD versus scheduled days to TD. The red line shows how the

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planned days to TD have decreased over the three wells. Though the number of days planned to drill to TD is decreasing, the process continues to reduce cost by lowering actual days drilled. Even the most difficult well, SM1004, reached TD in 43% fewer days than an offset deviated well.

Applying mitigation techniques reduced the probability and severity of unplanned drilling events and lowered risk. Proper preventive actions, identified in advance by the integrated drilling team, were developed into a risk prevention program and implemented on each section drilled. Mitigations were easily established using MEM results to understand the root cause of each problem. Drilling events were assigned severity and probability of occurrence to determine a qualitative risk exposure. Fig. 12 shows the drastic reduction of risk exposure related to pack off and casing not reaching bottom for offset wells (left) and the three wells drilled (right) using the process.

Other Uses for the MEM

One of the powerful additional benefits of developing an MEM to help with drilling is its use in answering other questions about the field. Completion design from type of completion to hardware requirements to well placement can be developed using the MEMs stress, strength, and pressure predictions. Required inputs for maximum drawdown, perforation orientation, and hydraulic fracturing design are also available from the MEM. Combine this production optimization analysis with reservoir size and producibility for net present value and return on investment to determine financial performance and risk assessment for the field. Even longer time related issues such as reservoir compaction, subsidence and reservoir stress changes with production can be examined, making the MEM valuable for the life of the field. Conclusions

Multidisciplinary, integrated teamwork was a key factor in the successful drilling of three wells in San Martin field. The teams multidisciplinary expertise brought the best solutions to resolve drilling events, propose mitigations, and define procedures.

Building an MEM and using a drilling map for each well within a risk management process provided invaluable help in reducing unscheduled events and improving drilling performance. The drilling team was able to make better decisions and reduce cost.

There was quick application of lessons learned on each well.

Fast updates to the original program developed a live plan for improved safety.

The value of real time information was maximized. The team minimized wellbore stability issues and

quickly reacted with informed decisions. The number of BHAs was reduced and BHA

performance improved.

A coherent use of technology (MWD, LWD, rotary steerable systems) was derived from fit-for-purpose solutions.

Risk reduction, critical in overall performance

improvement, was accomplished as described below. A dynamic MEM for the field was built by a multi-

disciplinary team before drilling the first well. Drilling related risks and areas of uncertainty were

identified so that steps could be taken to monitor key drilling indicators.

Informed decisions were made in real time using the MEM.

The MEM was used as a predictive tool to aid in understanding stability failure modes.

All these improvements are based on a Predrill model that can be easily updated in near real time. Using this process dramatically accelerated the learning curve, reduced risk and lowered cost for drilling wells in San Martin field. Acknowledgements The authors thank Pluspetrol and all partners of Block 88 Upstream for their contribution and permission to publish this paper.

References

1. Last, N., Plumb, R.A., Harkness, R., Charlez, P., Alsen, J., McLean, M., An Integrated Approach to Managing Wellbore Instability in the Cusiana Field, Columbia, South America SPE 30464, Dallas 22-25 (Oct 1995)

2. Plumb, R.A., Edwards, S., Pidcock, G., Lee, D.W., The

Mechanical Earth Model Concept and Its Application to High-Risk Well Construction Projects SPE 59128, (Feb 2000)

3. Okland, D., Cook, J.M., Bedding-Related Borehole

Instability in High-Angle Wells, SPE/ISRM 47285 (July 1998)

4. Plumb, R.A., Influence of Composition and Texture on the

Failure Properties of Clastic Rocks, SPE/ISRM 28022, Eurock, (Aug 1994)

5. Frydman, M., da Fontoura, S.A.B., Application of a

Coupled Chemical-hydromechanical Model to Wellbore Stability in Shales IBP 26200, (Oct 2000)

6. Frydman, M., da Fontoura, S.A.B., Modeling Aspects of

Wellbore Stability in Shales SPE 69529 (Mar 2001)

7. Herron, S.L., Herron, M.M., Plumb, R.A., Identification of Clay-Supported and Framework-Supported Domains From Geochemical and Geological Well Log Data SPE 24726, (Oct 1992)

8. Zoback, M.D, Moos, D., Mastin, L. Well bore breakouts

and in-situ stress. Journal of Geophysical Research, 90, 5523-5530. (1985)

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9. Plumb, R.A. & Hickman, S.H. Stress-induced borehole elongation: a comparison between the four-arm dipmeter and the Borehole Televiewer in the Auburn geothermal well Journal of Geophysical Research, 90, 5513-5521, (1985)

10. Economidies, M.J., Nolte, K.G, Reservoir Stimulation

second edition, Prentice-Hall Inc., Englewood Cliffs, NJ (1989)

11. Nolte, K.G., Fracture-Pressure Analysis for Nonideal

Behavior SPE 20704, (1991)

12. Gruesbeck, C., Collins, R.E.,Entrainment and Deposition of Fines Particles in Porous Media, SPEJ (December 1982), 847-850

13. FracCADE User Manual, Schlumberger (2000)

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Figures

Figure 1. The Camisea blocks (38/42) located in the tectonic active foothills of the Peruvian Andes.

Figure 2. Real-time monitoring system used to keep the drilling team informed and to disseminate information.

Figure 3. NPT analysis of drilling events from offset wells

by formation.

Figure 4. Drilling events visualized in 3D to determine their relationship both spacially and to geological horizons.

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Figure 5. Sensitivity analysis on input data to shear failure

using Monte-Carlo modeling.

Figure 6. Wellbore stability results compared to calipers to

verify shear failure modes.

Figure 7. Angular cavings appearing at the surface at

depths predicted by the MEM.

Figure 8. Diagram of fluid flowing into a fracture (left) and

solids reducing permeability, sealing the fracture (right). 12

Figure 9. Fracture growth simulation predicting 11 m of

growth downward, into the permeable sand.

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Figure 10. LWD electronic measurement of diameters (right track) showing hole size shortly after drilling through

the Shinai.

Figure 11. Comparison of drilling days to TD for the three

wells drilled in San Martin using this process.

Figure 12. Risk exposure before (left) and after (right) the process was applied.