Developing reserves in Kazakhstan's Chinarevskoe field frequently requires the operator to drill an 8.5-in. vertical hole section through extremely hard carbonates which contain high concentrations of problematic chert inclusions. The first significant chert layer is encountered at 3050-3110m, which has 10-50% chert content. Penetrating the chert interval with PDC bits has been challenging and in many cases impossible due to the cutters' inability to withstand high impact forces, which resulted in catastrophic cutter damage. The application of impregnated bits on high-speed turbines (1300-1400 RPM) led to significant improvement in run lengths and this BHA became the standard approach. 1 One impregnated bit could drill approximately 550m at 3.4m/hr. The hole section typically requires three bits to reach TD.However, the impregnated bit generated very small cuttings and high frictional heat altered chip appearance hampering lithology characterization and efforts to identify formation properties. Additionally, the centrifuge was unable to separate the extremely small cuttings from the drilling fluid, resulting in a gradual increase in mud weight over the interval creating the need for constant mud replacement.Tests with PDC were once again attempted, but when the bit encountered a high percentage chert interval, the bits were damaged and pulled in poor dull condition (7-6-CR). After repeated attempts with PDC, the operator realized wellbore verticality was compromised, which required correction run with impreg/turbine BHA with not optimum parameters leading to extra drilling time. The drilling team conceded the chert layers could not be drilled with a conventional PDC/motor BHA. The operator required PDC bit that could efficiently drill long intervals of carbonate formation at high ROP with a durable cutting structure that would remain intact when encountering the chert intervals.To develop a durable bit solution, engineers used an FEA-based modeling system to implement an innovative hybrid-type bit by strategically positioning multiple conical diamond elements (CDE) and conventional PDC cutters across the entire cutting structure from bit center to gauge. This new-style cutting structure leverages the CDE's aggressive shape and superior impact and wear resistance to create a high-efficiency plowing/shearing action that improves performance in difficult formations. The analysis indicated the new hybrid bit would improve performance and be capable of surviving shock and vibration while drilling the hard carbonate/chert formations.The CDE bit was field tested on rotary steerable BHA and drilled 615m at an ROP of 9.1m/hr through the carbonate formation that contained 10-40% chert inclusions throughout the entire interval. Compared to offsets drilled with an impreg/turbine BHA, the CDE bit drilled 12% more meters at 166% higher ROP while providing good wellbore quality and came out with excellent dull condition (1-1-CT). The bit generated much larger cuttings enabling wellsite geologists to readily identify lithology t...

The history of La Ceiba field began 10 years ago when six exploration wells were drilled to assess the potential of this field. The wells were drilled with several incidents of stuck pipe and the resulting necessary side-tracks to reach the final depth. Until last year no further attempt had been made to drill in this field. With little information available from the exploration wells concerning drilling practices, the drilling campaign began with the goal of improving the previous performance, making the drilling of the complete wells faster and safer than in the previous drilling. An engineering process was begun to find the best drilling solution for the field, starting with proven technologies such as positive displacement motors (PDM) and drill bits used in similar fields; however, this methods alone were not sufficient to meet the challenges of the field. New technologies were used for the different challenges and applications through coordinated work between the drilling engineering departments of the different parties involved in this field and using all the information available in the drill bit selection database, including logs and stability data for the tools selected to drill each phase of the wells. With evolution of the learning curve, drilling progressed from initial drilling involving 12 runs with time-consuming trips to surface to change either the drill bit or PDM, to drilling the same interval in 5 runs with the time on bottom increasing compare to previous experiences due to the introduction of tools more suitable to the environment requirements a rotary steerable systems (RSS) in combination with a specially designed drill bit. Problems commonly faced in the upper sections were, the trajectory was not strictly followed, were solved with the introduction of the RSS in this section; use of the tool saved 10 days of rig time and set a bench mark for the field and similar wells in western Venezuela. The development of this field shows that by solving the issues related to the well depth, temperature and constraints well design for these wells in western Venezuela, it will be possible to reach the oil reserves, at the same time decreasing the time spent in the drilling process.

Drilling the hard/abrasive Travis Peak/Hosston and Cotton Valley formations in East Texas/North Louisiana creates a distinctive challenge for polycrystalline diamond compact (PDC) bits. Conventional PDC cutters fail quickly due to abrasive wear/spalling and/or delamination of the diamond table. Most bits are typically pulled in poor dull condition graded 1-2-WT or worse. The situation has caused stagnation in PDC performance and limited additional gains in total footage and rate of penetration (ROP). Recent scientific studies have indicated that thermal fatigue of the diamond table is the main contributing factor leading to cutter failure and is restricting further advancement of PDC drilling in East Texas and other hard and abrasive applications. To improve cutter performance the industry must:

Exploratory drilling in the Faroe-Shetland Basin of the northeast Atlantic Ocean has been ongoing for several years. One of the greatest challenges of such drilling programs is cost-effectively drilling through the thick layers of Paleogene volcanic rock, which has thicknesses and depths that vary depending on the location of the regional tectonic geography. With the high expense inherent to remote offshore operations, total drilling costs will increase when expected penetration rates and interval lengths are limited due to drillbit inefficiency. An operator planned to drill a second well in the Brugdan prospect, which lies in License 006, Block 6104/21 off the Faroe Islands. The challenge of drilling through a hard, long section of basalt/volcanic sequence presented a great opportunity for investigating and implementing new drillbit materials and design changes to diamond-impregnated bits. A study for materials testing was focused on diamond grit/matrix combinations for wear, durability, and ROP on two representative basalt outcrop columns provided by the customer. The analysis of the physical characteristics of the rock provided an insight of the matrix and diamond combinations for blade material and grit hot-pressed inserts (GHIs) that would offer a reliable product to meet the challenge and drill the long section. Materials testing followed at the drillbit manufacturing facility to find the appropriate diamond-impregnated recipe. A competitive diamond-impregnated bit was developed for the 12¼-in section, resulting in an internal world record and an unprecedented drilling performance in the extremely hard and long volcanic sequence.

Exploration offshore Australia requires the operator to drill an 8½” vertical borehole through the difficult Plover sandstone. The highly abrasive formation, with unconfined compressive strength between 15–30kpsi, has been problematic causing extremely short PDC bit runs and low rates of penetration (ROP). Erratic torque response was causing a reduction in bottom hole assembly (BHA) performance and system reliability. The operator required a PDC bit solution to increase run lengths and ROP. To solve the problems, a new system was devised that enables a PDC shearing element to fully rotate while drilling to increase cutting efficiency/bit durability while reducing frictional heat. To strategically position the rolling cutters (RC) to obtain maximum benefit, a forensic analysis was performed on PDCs used in offsets. After investigation, engineers identified accelerated wear flats in the shoulder area and a new PDC design (RC813) was implemented by positioning two 13mm rolling cutters in the shoulder area on each of the eight-blades. The target objectives would be to drill the 8½” hole section through the Plover with one PDC bit and improve ROP. The first well required one conventional PDC and one RC813 to drill through the Plover to TD. The standard PDC (10blades/16mm) drilled 90m (3739–3829m) at an average ROP of 5.4m/hr. The bit was pulled for low ROP and graded 8–3-CR-C-X-IN-BT-PR. The rolling cutter equipped RC813 drilled 126m (3829–3955m) at a ROP of 4.3m/hr. The RC813 was pulled in good condition and dull graded 1-2-CT-S-X-IN-PN-TD. Parameter/bit adjustments in the second well enabled an RC813 to drill the entire Plover interval (3283m–3425m) in one run at an ROP of 9.26m/hr. The rolling cutter PDC bit run was 319% faster than a direct offset that required four standard bits to TD the section at an average ROP of 3.1m/hr. The RC813 torque response was smooth compared to erratic torque response of standard PDC in Plover. The increased meterage and ROP saved the operator over $1million USD.