Bit selection The bit selection process Assemble offset

Bit selection • The bit selection process • • • Assemble offset well data Develop a description of the well to be drilled Review offset well bit runs Develop candidate bit programs Confirm that the selected bits are consistent with the proposed BHA’s Perform an economic evaluation, to identify the preferred bit program

Assemble offset well data • Identify the nearest, most similar wells to the proposed location • Gather as much information as possible about drilling these wells • Include bit records, mud logs, wireline logs, daily drilling reports, mud reports, directional reports

Develop a description of the well to be drilled • Characterize the proposed hole geometry • hole size • casing points, • trajectory

Develop a description of the well to be drilled • Outline the anticipated values of rock hardness and abrasivity at all depths • Sonic travel time logs give qualitative indications of formation hardness. • Low travel times - high rock compressive strengths

Develop a description of the well to be drilled • Outline the anticipated values of rock hardness and abrasivity at all depths • Abrasivity is more difficult to quantify • It is possible to form a qualitative assessment of the rock’s potential for abrasive bit wear. • Abrasiveness is related to • • Hardness of its constituent minerals Bulk compressive strength Grain size distribution Shape

Develop a description of the well to be drilled • Make note of any formations that may have a special impact on bit performance • Divide the well into distinct zones • Each zone corresponds to a significant change in formation properties or drilling condition

Review offset well bit runs • Determine what bits were used to drill through each formation likely to be penetrated • Identify which bit gave the best or worst performance • Look at the bit grading • Use the bit performance to infer formation hardness and abrasivity Harold Vance Department of Petroleum Engineering

Identify candidate bits • Identify which bits are candidates for each zone to be penetrated • Consider fixed cutter and roller cone bits Harold Vance Department of Petroleum Engineering

Roller Cone Bits • Key design considerations for roller cone bits are: • • cutting structure bearing seal types gauge protection • Should be matched to the formations hardness and abrasivity Harold Vance Department of Petroleum Engineering

Fixed Cutter Bits • Key design considerations for fixed cutter bits are: • • cutting structure body material and profile gauge stabilizing (anti-whirl) features • Should be matched to formations hardness and abrasivity Harold Vance Department of Petroleum Engineering

Fixed Cutter considerations • PCD cutters wear rapidly in hard formations • Impregnated and natural diamond bits tolerate very hard and abrasive formations • Gauge protection is dependent on abrasiveness Harold Vance Department of Petroleum Engineering

Develop candidate bit programs • At this stage, develop several alternative bit programs. • Consists of type of bit, start and end depths, and anticipated penetration rates. Harold Vance Department of Petroleum Engineering

Confirm that the selected bits are consistent with the proposed BHA’s • Do the operating parameters of the proposed BHA’s inhibit performance? • Is WOB limited? • Do the selected downhole motors exceed the rpm capabilities of the bits? Harold Vance Department of Petroleum Engineering

Perform an economic evaluation, to identify the preferred bit program • Use the estimated penetration rate and bit life to predict the probable cost for each bit run: • Chi = Cri. Ti + Cbi • Predicted cost of the interval is the sum of all the bit costs for the particular bit program. • Rank all the alternative bit programs Harold Vance Department of Petroleum Engineering

Bit selection for Dry Gas, Must and Foam drilling • Roller cone • Fixed cutter Harold Vance Department of Petroleum Engineering

Roller Cone Bits • Dry gas drilling produces a smoother hole bottom than with mud, and full coverage of the bottom of the hole with cutters is not as important. • Larger teeth can be used for harder formations • Abrasive wear is normally higher for dry gas drilling Harold Vance Department of Petroleum Engineering

Roller Cone Bits • Cone offset is not as important with dry gas drilling • Good gauge protection is very important • Utilize sealed bearings Harold Vance Department of Petroleum Engineering

Fixed Cutter Bits • PDC bits are usually a poor choice for dry gas drilling • Not has heat tolerant • Diamond bits may be heat tolerant. Harold Vance Department of Petroleum Engineering

Bit selection for gasified and liquid systems • Not much difference from conventional drilling Harold Vance Department of Petroleum Engineering

Underbalanced perforating • Can be performed with wireline or with tubing conveyed perforating guns. Harold Vance Department of Petroleum Engineering

Drillstring design • Similar to conventional drilling • There will be less buoyancy • BHA should be designed so that all compression is in the BHA • An exception is in horizontal wellbores. Harold Vance Department of Petroleum Engineering

Example 6 Harold Vance Department of Petroleum Engineering