STUDY OF DRILLING SYSTEM IN RELEVENCE TO FIELDS IN NORTH EAST PART OF INDIA BY M/S HALLIBURTON

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1 STUDY OF DRILLING SYSTEM IN RELEVENCE TO FIELDS IN NORTH EAST PART OF INDIA BY M/S HALLIBURTON

2 OBJECTIVE To engage a reputed consultancy firm /consultants having multidisciplinary expertise for a. Facilitate best predictions for how the geology will respond during drilling operations through Geo mechanics study b. Designing drilling programs to drill quality producible hole - with efficient BHA to Increase recoveries, - Lower costs - by minimizing (NPT) - Cost effective casing design - Boosting production rates with minimum capital expenditure

3 FIELDS OF STUDY Under the consultancy service OIL identified four fields for study and provided data of offset wells as below- MORAN FIELD BAGHJAN / BAREKURI FIELD MECHAKI FIELD CHABUA FIELD MFC (Moran 116) BGN(Baghjan 18 ) MKC (Mechaki 1) DIAH (Chabua -03) MFN (Moran 117) BGQ (Baghjan 19) TX (Mechaki 2) DIAO (Chabua -05) MFF (Batua 1 ) DFU(Barekuri 06 ) MKA (Mechaki 3) CS (Chabua - 14 ) TV (Barekuri 13 ) MKB (Mechaki 4) CN (Chabua - 16)

4 PROJECT COMPLETION PHASE PHASE I Data collection /site visit / Problem Identification root cause analysis of different down hole problem( four IDENTIFIED fields) PHASE II Geo Mechanical study and preparation of the geo modeling PHASE III PHASE IV Data review, Analysis and well design workflow for drilling of vertical and directional ( S bend, J bend and Horizontal) wells and completion for optimized deliverability from reservoir. Suggestions towards specifications for down hole and wellhead equipments (if any) for problematic wells in the area of study PHASE V Well operation and management plans PHASE VI Submission and presentation of final report

5 TEAMS FOR THE PROJECT OIL TEAM HALLIBURTON TEAM A JPHUKAN CO - ORDINATOR ROB POUNDS COMPLETION ADVISOR, TEAM LEADER S K GOGOI CED (PLANNING) KEVIN HALL GEOMECHANICS EXPERT DEEPAK JAIN RESERVOIR ENGINEER HARSHAD DIXIT RESERVOIR EXPERT UTPAL DEKA DY.CE(P-Oil) VIVEK SHARMA DRILLING ADVISOR PRAMITABH BARUA CHIEF GEOLOGIST SHYAMANTA GOGOI CHIEF CHEMIST Phase- I To start the Project, of the contract the team from Halliburton Consulting visited Oil India Limited, Duliajan from 11/02/2015 to 14/02/2015 for data collection (G & R Drilling, chemical and production department, field visit (Drill site at Moran and Barekuri) Phase- II Geo-mechanics study was carried out for the four fields. The findings from GM study are: a. Kopili section is over pressured in all the four fields b. Pressure ramps up at top of Kopili and again decreases in Narpuh, Prang, becoming close to hydrostatic in Lakadong Theria. c. For Chabua field the pressures in Lk-Th are sub hydrostatic. d. Mud weights used to drill Kopili are less than optimum leading to well bore breakouts/washouts.

6 Data Analysis Phase III - Data Analysis & Recommendations From the data review based on Offset well data (drilling), petrophysical logs and Calliper record Geo-mechanic study Following observations can be summarized: 1. Caliper Section Over-gauged in Kopili and Prang 2. Kopili formation over pressured 3. No Losses encountered in Barail and Tipam during drilling (Maximum mud weight recorded 80lbscft) 4. Increased formation exposure time contributes to reduced drilling performance 5. PDC bits capable to drill long sections before being pulled out 6. Stuck pipe incidence recorded in Kopili (shale), Prang (Limestone), Lakadong Theria (Sandstone) formations 7. Stuck pipe incidence noted during P/O or R/I operations. Recommendations Recommendations: Drilling Practices Leak Off test should be recorded LOT will give a correct idea of the Geo-mechanic stress regime PIT test to be carried for higher mud weights Record four arm caliper logs in the Kopili LK-Th Sections PDC bit should be able to drill entire sections(spe ) Eight letter bit grading and flow rate on bit performance sheet. Recommendations: Well design Kopili shouldn t be drilled together with reservoir zone. - Drilling problems in Kopili increases exposure time for reservoir zone. Kopili is over-pressured formation. Higher mud weight required for Kopili exerts high differential pressure in reservoir zone. Drilling Mud contamination from Kopili cuttings may cause formation damage in reservoir section. Increase Mud Weight while drilling Kopili as per Geo-Mechanical study. - Reduces formation failure due to shear. Reduce Mud weight while drilling reservoir zone as per pore pressure requirement to reduce formation damage.

7 BASIS OF DESIGN (BOD) Basis of Design (BOD) for Drilling Following are the key guiding principles for the suggested well designs 1. OPTIMIZED DELIVERABILITY FROM RESERVOIR: This is the most important aspect of the proposed well design. The main producing reservoir in Eocene formations is Lakadong Theria sandstone. By exposing Lk-Th to higher mud weights and higher exposure time it is a possible that near well reservoir is getting damaged during the drilling. To Increase productivity from well it would be a good idea to drill this part separately. 2. ISOLATE TROUBLESOME FORMATIONS: Kopili is the troublesome formation resulting in big bore hole washouts/ breakouts. This can have two effects on the wellbore. One effect is that the falling cuttings can result in stuck pipe conditions. The second is that that enlarged wellbore will reduce the cleaning efficiency there by making mud contaminated with low gravity solids. This mud contamination can severely effect near formation permeability being drilled immediately below Kopil section.another thing noted during the study was that the tight wellbore problems occurred in all the different type of formations but they became enhanced once Kopili and the rest of the formations below it were opened. This could be due to change in mud properties when Kopili was being exposed for longer durations 3. USE OF CORRECT MUD WEIGHTS: Use of correct mud weight based on the Geo-mechanics study is highly recommended. The suggested mud weights required to hold kopili together are on the higher side but none of the formations except for basement have shown any loss zone. Also the predicted fracture gradient is sufficient to support a higher mud weight When drilling the Lk-Th reservoir sandstones the mud weight can be reduced to reduce the formation damage. Also the non-damaging fluid can be used to drill across these sections.

8 Vertical / Deviated Well Design - Barekuri/Baghjan Grade Wt (PPF) Base TOC Hole size 20 Casing K surface /8 Casing N surface 17.1/ /8 Casing N / Liner P / Liner N / /8 Prod Tbg Annulus fluid

9 8 ½ Section 8 ½ proposed Bottom Hole Assembly is a Mud-motor Directional Assembly. There is a rotating near bit stabilizer or long gauge slick bore bit proposed to be used in the BHA. The bit proposed for this section is PDC. The other parameters for 8 ½ Section to maintain a fast drilling ROP is WOB: Ton, RPM: 80-90, Flow Rate: GPM Proposed BHA: Torque & Drag Analysis:

10 Vertical / Deviated Well Mechaki Grade Wt (PPF) Base TOC Hole size 20 Casing K surface /8 Casing P-110 N Ann. fluid surface 17.1/ /8 Casing P / Liner P / /2 Liner P /8 Prod Tbg

11 Torque and drag in 12 ¼ and 8.1/2 Section

12 Vertical / Deviated WELL DESIGN FOR CHABUA FIELD Grade Wt (PPF) Base TOC Hole size 20 Casing K surface /8 Casing P-110 N Ann. fluid surface 17.1/ /8 Casing N / Liner P / /8 Prod Tbg

13 Vertical / Deviated WELL DESIGN FOR MORAN FIELD Grade Wt (PPF) Base TOC Hole size 20 Casing K surface /8 Casing P-110 N Ann. fluid surface 17.1/ /8 Casing P / Liner P / /8 Prod Tbg

14 Vertical / Deviated WELL DESIGN (Contingency) FOR MORAN FIELD Grade Wt (PPF) Base TOC Hole size 20 Casing K surface /8 Csg P-110 N Ann. fluid surface 17.1/ /8 Casing P / Liner P / Liner N-80 N /8 Prod Tbg

15 Non-availability of Top drive systems on the rig: Top drive is useful to drill stands instead of singles there by reducing connection times. In addition one of the biggest uses for top drive systems is to back ream. From the OIL reports for offset well it is clear that inability to instantaneously start rotation contributes significantly to stuck pipe events. The pipe cannot be back reamed in the tight spot so driller is left with limited capability of applying pull to come out of tight zones. This can sometimes wedge the BHA against the ledges and create stuck pipe. Drilling Technology and Guidelines for Improvement in ROP Challenges in Achieving Optimized Drilling Rate or Penetration especially in Eocene formations Over gauged Wellbore Calliper in all the wells analysed for the four fields reflect borehole enlargement to the extent of 100% and beyond especially in Shale sections. Drastically reduce the rate of penetration due to two effects:- With more cuttings being generated in the wellbore the efficiency to remove these cuttings goes down due to reduced annular velocity. This will lead to re-grinding of the cuttings and significant energy from bit and hydraulics gets utilized to clear up the already drilled formations rather than making new hole. Additional trips will be required to clear out the wellbore. The ledges created by uneven borehole gauge will result in BHA hanging and wireline tool not being able to reach the TD of the drilled section. An effective way to deal with shale breakout is to strengthen the formation by increasing the mud weight. A leak off test should be done at start of new section and mud weight guidelines as recommended by Geo-mechanic study should be followed. It is important that the mud weights are increased before entering the troubled zone. Once the breakout starts occurring, increasing mud weights will not have much effect to control the gauge of the wellbore. Multiple bit trips Due to use of roller cone bits, multiple bit trips are required. Multiple bit trips combined with unstable formations does not augur well for good quality borehole. The time lost during the trip run is a non-productive time. Repeated running in & pulling out causes swab and surge loads on the wellbore and can accelerate deterioration of borehole gauge with time. A solution to this problem is use of PDC bits with gauge protection features to ensure longer bit life. Poor ROP while drilling (Roller Cone /PDC): Average ROP to drill 12 ¼ section is m/hr and to drill 8 ½ Section (Eocene) formations is 4-5 m/hr. When we look at the unconfined compressive strengths of the rock from the geo-mechanic study, the formations are in range of psi UCS. This would put them under low strength rocks category. To drill this type of formation both roller cones and PDC should be capable to deliver ROP > 5m/hr. This is not happening due to loss of bit energy in chasing enlarged wellbore and lack of matched drilling system. Excess cuttings build-up in wellbore reduces the bit cutter exposure to drilling the formation; bit balling for example, being a case of this. Such situations can be improved by taking care of mud weight and flow rates. Heavy mud weight will improve wellbore stability but also create a differential across the formation. This will result in chip hold down effect. So the increase in mud weight would work both ways and an optimum mud weight can be selected based on feedback from the well. This will take an experimental learning curve. Top priority should be to maintain the gauge of the wellbore. Flow rates and bit TFA should be selected in such a way that near bit area is cleaned properly. A general guideline for rock bits is to maintain the jet velocity of 300 ft/sec. For PDC bits the horsepower per square inch (HSI) should be in range of 2.5 to 7. This will ensure that cutters on the bit are clean and bite the formation when on bottom. A matched system is drilling assembly where the bit and BHA are configured taking the role played by each components. For example suppose a rotary assembly, that is a BHA without Mud Motor or Rotary Steerable, is required to drill a particular section by PDC bit. This would need good stabilization requirements on the BHA to prevent whirl motions on the bit. At the same time bit cutters aggressiveness need to be compatible with formations being drilled. Soft formations will require large cutters with adequate junk slot area for bit cleaning. Hard formations will need smaller cutters and lateral motion limiters on the bit to prevent damage on bit and BHA component. In case a motor assembly is used, the matched system can incorporate use of small bit to bend, small bit lengths and stepped gauge on bit to provide directional capability to the system. The bit and BHA proposed in this report is aimed at utilizing such matched drilling for improvements in ROP. Of course, fine tuning would be required based on the actual results from the field data.

16 Technology/Methods to Focus for Improving Drilling Time Geo-mechanical Modelling, Model updates and control over Wellbore Stability: The first requirement for improving drilling time estimate is to ensure smooth wellbore. Even if top drive system or rotary steerable system is introduced in future, wellbore instability will result in low penetration rates. Top drive can reduce the chances of stuck pipe by reaming/back reaming through tight spots. Rotary steerable will remove time spent on steering, but as observed in S type of wells, application of rotary technology does not result in removing the wellbore related problems entirely. This Drilling systems study specifically aimed at Geo-mechanics study for four fields of Oil India. Result of the study is development of a base model for geo-mechanics. However there are some important inputs such as leak off test data & core strength data that were not available for the study. A strong recommendation is to update for the geo-mechanical models regularly either in real time or post drilling to reduce the uncertainty. Leak off tests should be planned in some wells to give accurate idea of formation fracture strength. Below is a pictorial representation for the same. Real help from these model updates would come in form of fine tuning the mud weights that can be used in the wells to prevent the wellbore breakouts. Another benefit of the geo-mechanic model will be in form of reducing the number of casings required by increasing the confidence level in leak of data points. Simplified well architecture and isolation of production zones will result in increased productivity from reservoir at reduced well costs.

17 Matched Drilling system: In the metal cutting / machine shop industry it would be unheard of to attempt to drill or mill with an un-stabilized cutter. Anyone who has ever used a twist drill, especially with a hand held electric drill, will know that the drill is hard to control when starting a hole. The two flutes on a typical twist drill will cut a three lobed pattern causing considerable vibration and a tendency to throw the drill off center.

18 Some General Guidelines on Bit Shale has a better drilling response to drill speed. Limestone has a better drilling response to bit weight. Bits with roller bearings can be run at a higher speed than bits with journal bearings. Bits with sealed bearings have a longer life than bits with open bearings. Bits with journal bearings can be run at higher weights than bits with roller bearings. PDC & Diamond product bits can run at higher speeds than roller-cone bits. Bits with high offset may wear more on gauge. Examination of dulls can also help you decide which bit to use. Tripping can ruin a new bit Make the bit up to proper torque. Hoist and lower the bit slowly through ledges and doglegs. Hoist and lower the bit slowly at liner tops. Avoid sudden stops. Drillpipe stretch can cause a bit to hit the hole bottom. If reaming is required, use a light weight and low speed. Establish a bottomhole pattern Rotate the bit and circulate mud when approaching bottom. This will prevent plugged nozzles and clear out fill. Lightly tag bottom with low speed. Gradually increase speed and then gradually increase weight. Use a drill-off test to select best weight on bit (WOB) and speed Select speed. Select bit weight. Depending on bit selected, refer to appropriate manufacturer s recommended maximum speed and WOB. Lock brake. Record drill-off time for 5,000-lbm increments of weight indicator decrease. Repeat this procedure for different speeds. Drill at the weight and speed that give the fastest drill-off time. The bit is not always to blame for low ROP Mud weight may be too high with respect to formation pressure. Mud solids may need to be controlled. Pump pressure or pump volume may be too low. Formation hardness may have increased. Speed and weight may not be the best for bit type and formation. Use drill-off test. Bit may not have adequate stabilization.

19 Bit Dull Grading: Bit dull grading is very important activity and record for bit performance downhole. A properly graded dull bit will help in future bit selections and reduction in downhole problems. IADC follows an 8 character dull bit grading system as given below: F

20 Drilling System Study of the Northeast Fields IFB No. CDG2594P14

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