The advancements in drilling technology have led to rapid and sustained improvements in drilling operations. This gradual development of tools and techniques has resulted in time savings and safety improvements. The number of directional and horizontal wells is growing every year and many of these are being drilled in more challenging oilfield environments such as deep gas fields, carbonate reservoirs and high pressure-high temperature zones. There is also an increasing demand for precision directional and horizontal drilling in mature oil fields. Such advancement of technology and tools require an appropriate approach of developing the available technical manpower with related drilling competencies. Therefore, a competency based model becomes essential for National Oil Companies (NOCs) to develop their technical manpower to keep pace with the technology development.
Effective competency development is a combination of awareness, knowledge, skills and attitude that must be demonstrated to meet the performance standards required for their jobs. The paper emphasizes the need for a customized competency model for a drilling engineer in order to meet the major challenges as mentioned above. The Drilling Competencies in an Upstream National Oil Company needs to be categorized in three main disciplines which are Drilling Engineering, Drilling Operations and Drilling Techno Commercial. Therefore, exposure to these core competencies is essential for an effective drilling engineer. A case study of an Upstream Oil & Gas Company has been illustrated in this regard.
The implementation of the Drilling competency model will result in improved job satisfaction, better talent management and employee retention. Such approach of competency modeling of different job families in upstream NOCs will empower them to achieve their goal with admirable clarity, better hydrocarbon discovery index cum increase in production and field management expertise. The proposed Drilling Competency Model can serve as a guide for other National Oil Companies in their endeavor to achieve excellence.
As a general trend the complexity of drilling operations and bottom hole assemblies (BHAs) is increasing. It has become common to rotary drill directional wells with higher dogleg severity (DLS), more aggressive parameters are being used to improve drilling performance, and hole-opening while drilling tools are being used more frequently. The implication of these trends is an increased risk of BHA and drillstring failures due to higher component stresses accelerating fatigue rates. On other hand, with increasing sensitivity to rig spread cost and operations efficiency, there is an increased focus on reducing operational nonproductive time (NPT). Drillstring failures can cause significant NPT as the drilling operation needs to stop and time must be spent fishing to recover a failed BHA component downhole or, potentially, the well must be abandoned and the hole sidetracked to continue drilling. Therefore, addressing fatigue failure concerns at the BHA design stage is critical; mitigating the risk of BHA and drillstring failures is less costly than recovering from drillstring and BHA failure while drilling. Proper design can also increase the service life of the BHA components.
Conventionally, an assessment of the BHA component fatigue failure risk has not been a standard automated part of the BHA design process during the well design stage, but rather mitigated via the inspection of tubulars as per industry standards. A new automated workflow for modeling BHA static loads has been developed and used to deliver a more comprehensive solution for BHA design. The workflow is implemented within a well design software application that enables a drilling engineer to efficiently evaluate the effect of different borehole curvature magnitudes at a range of wellbore inclinations, to understand the risk associated with the plan and deviation from the plan in the execution phase. The modeling results help a drilling engineer to ensure that from the planning stage the BHA components bending moment and bending stress levels remain below the recommended thresholds at the execution and provide theoretically infinite component life. Using this information a drilling engineer can optimize the BHA or other parameters to reduce the risk, and formulate a better plan & contingency.
This modeling approach has been evaluated through several case studies which demonstrate how it can help to optimize BHA design and minimize or avoid fatigue failures. The case studies presented in this paper are some examples of downhole BHA component failures that could have been avoided through early planning phase identification of the risk.
Inflow control devices (ICD) completion is a downhole flow control solution that is designed to balance influx contributions across wellbore horizontal section, to delay water breakthrough or coning hot-spots and to increase ultimate cumulative oil recovery. This paper illustrates a novel and successful systematic workflow to implement this technology in order to effectively manage the marginal green reservoir uncertainties while achieving field development requirements. In general, this production-upsides justification and design process started from an early stage full field ICD completion feasibility study; followed by single well pre-drill ICD design through dynamic simulation as preparation for real time drilling operation support. Subsequently, ICD nozzle-configuration optimization and packer placement design fine-tuning were performed before run in hole during real time operation. The final optimized design for ICD and tracer tally can then be proposed for on-site execution. The key enabler of this process is a novel and time-efficient single well dynamic simulation method, which is compiling the dynamic time-lapse production responds with various ICD nozzle and packer design optimisation workflow. The sensitivities of various design scenarios were applied as a working range to guide on-site ICD installation.
This paper highlight the design and optimization workflow from the perspective of dynamic modeling against the conventional nodal-based or single time-step production scenario simulation carried out. In illustrating the more ‘down-to-earth’ production upside results when time-lapse impact are considered, single well dynamic modeling can provide a more realistic real-time design especially in marginal oilfield application and critical decision-making during real-time. Against the typical over-optimistic production upsides analysis result portrayed by conventional single time-step production scenario simulation, some actual design cases as conservatively predicted by dynamic modeling single well will be demonstrated to influence decision-making when ICD's upsides is marginal . This crucial differentiation in due dilligence upside analysis will guide towards most optimal ICD's configuration RIH or reciprocally applying standalone screen (SAS) instead against the ICD's RIH minimal production benefits against its cost value. The results showed that the uncertainties and production repercussion that are affecting the decision of either running ICD's or SAS during real-time ICD's modeling updates are handled more inclusively and objectively with time-lapse based dynamic prediction.
Each company has its own method of capturing data during the Drilling and Well Construction process, and these methods will vary from simple spreadsheets to more complex systems that captures the live data and stores it. Each company will also have a method of capturing the lessons learned, usually in the form or an End of Well Report or wash up meeting with all of the service companies. Turning this data into useful information and thence to knowledge is at the moment a difficult problem
This transition process had been brought about by combining two specialist pieces of software. The first has the ability to take in date from all sorts of sources ranging from spread sheets via daily reporting systems to historical log data or real time data stream, mud logs etc. and then to present that data in a form that is useful to the drilling engineer in designing a well. The software also allows storage of experiences, both positive and negative, and links them to wells, rigs, specific types of equipment or operations.
This central store of data and the ability to transition it into useful information gives the engineer designing a well the ability to identify the risks and also the spread of times taken for various operations.
The second piece of software uses probabilistic calculations and the ability to place branches into the process that take into account the risks identified using the data storage software. Once a risk is identified then the mitigation steps are identified: how it will be addressed, what is needed and when.
All this information is taken into account when calculating the time and cost, giving a spread from Technical Limit through to Worst Case. More importantly all of the steps, and assumptions are stored in one place rather than the traditional multiple spreadsheets that generate the "Excel Hell" scenario.
By following a simple process with only two pieces of software the accuracy of well costing and scheduling can be increased additionally the understanding and mitigation of risk improves and lessons learned are no longer lost as personnel move within the company or the industry.
The drilling industry is an expensive part of the oil and gas sector, especially when drilling through a combination of low pressure and high pressure formations in exploration wells. When these zones are experienced while drilling, maintaining the BHP inside the drilling window is critical to ensure drilling fluid is not lost or formation fluids are not gained. Conventional solutions to help mitigate drilling through the troublesome formations include isolating thief zones, pumping LCM and cementing. These remedies could increase the overall project cost and add delays. One common problem associated with these solutions is how do you verify that the problem is corrected before drilling continues?
From having analyzed a case study from the Duvernay wells in Western Canada, it demonstrates that Managed Pressure Drilling (MPD) was applied with lighter drilling fluids to help adjust the bottom-hole pressure (BHP) as desired before the problematic formations. Through the Winterburn formation, constant losses were recorded and LCM was squeezed by applying the required surface-back-pressure (SBP). A formation limit test for the Winterburn formation was recorded and the bottom-hole equivalent circulating density (BH ECD) at 1495 kg/m3, showed 283 liters losses. Due to continued losses into Winterburn Formation, 1.5 m3 of 1100 kg/m3 LCM pill was mixed, spotted into the annular and then squeezed on top of the formation.
The LCM squeezing operation was started by applying 11,500 kPa static SBP which increased the BH ECD to 1700 kg/m3. After the LCM squeeze operation the well was reamed, and an extra 6 meters was drilled before performing a new formation integrity test (FIT). The second FIT was performed at the bottom of the formation and BH ECD had increased up to 1575 kg/m3 by applying 6,800 kPa SBP and the healing lost circulation zones were continued while drilling unconventionally through the MPD system. In the Beaverhill Lake formation, overpressured zones were encountered but drilling continued and dealt with both abnormal formation pressures. Lost circulation occurred in Winterburn formation with low pore pressure. The constant mud losses in this formation indicated that this problem was resulted from formation permeability, porosity and fractures that can be resolved by squeezing LCM. MPD brought value to the project by performing FIT in each formation, by monitoring and controlling precise LCM and cement squeeze operations. It also provided a solution for both types of abnormal formation problems as drilling continued and maintaining BHP inside the drilling window, increasing the overall safety of the project by detecting micro influxes and controlling them safely.
According to the pressure profile window, this paper illustrates how MPD successfully drilled through an upper formation of low pore pressure, with lost circulation problem, and lower formation with abnormal higher pore pressure without setting a casing between them. It also discusses the effect an MPD-LCM squeeze has on the fracture gradient of a formation and how the drilling window can be increased and manipulated to the operator's advantage.
This paper aims to report the field test results of several drill bits with enhanced hydraulic design features including optimum nozzle orientation and blade height as well as new patent-pending flow guide. These drill bits were developed based on numerous experimental and numerical tests. Computational Fluid Dynamics (CFD) was used to model the effect of various design features on bit hydraulics and then they were tested in Pressurized Drilling Lab (PDL). After the encouraging results of the experimental bits, several bits with enhanced hydraulic design were manufactured and sent to the filed for the final tests. The drilled formations were mostly soft to medium hard and ranged from shale to limestone. In most of reported cases, these bits outperformed the competition bits with Rate of Penetration (ROP) improvement ranging from 24% to 108% resulting in cost and time savings for operating companies.
Nana, D. (Schlumberger) | Buyers, G. (REPSOL) | Burton, D. (REPSOL) | Gomes, J. (REPSOL) | Pulpan, E. (REPSOL) | Tickoo, A. (REPSOL) | Meyer, A. W. (Schlumberger) | Munozrivera, M. (Schlumberger) | Silko, N. (Schlumberger) | Demidov, D. (Schlumberger)
Potential reservoir formation damage was avoided when curing up to 87.4 m3/hr (550 barrels per hour (bbl/hr)) losses of drilling fluid in a carbonate reservoir. In addition to traditional lost circulation assessment and treatment consideration, self-degrading fibers were used as part of the lost circulation system, and these preserved the reservoir from any consequential formation damage.
The treatment procedure consisted of pumping a given volume of treatment pill through bypass ports present in the drilling string and displacing it down to the loss zone (located 56 m below the bit). Managed pressure drilling (MPD) was used to minimize hydrostatic pressure above the said loss zone during pill placement (statically under-balanced mud weight). Since drilling was meant to continue after the treatment, the pill had to be squeezed to and through the reservoir to prevent loss from re-occurring when drilling resumed. The only available solutions at the time of need were either a thixotropic acid soluble cement plug (TASCP) or, the proprietary degradable fiber. Preference was given to the degradable fiber since it involved less rig time and does not need any subsequent dissolving treatment. An appropriate spacer was pumped ahead and behind the degradable fiber to prevent intermixing of incompatible fluids. The treatment was pumped using the rig mud pumps.
The loss rate registered prior to the treatment was 87.4 m3/hr (550 bbl/hr) at a pumping rate of 2650 l/min (700 gal/min). The equivalent circulating density (ECD) was 1.22 SG (10.2 ppg). Out of 19 m3 (120 bbl) of prepared degradable fiber pill, 15.6 m3 (98 bbl) were pumped and displaced into the reservoir, leaving the estimated top of the pill at 5850 m measured depth (MD). The top of the loss zone was estimated to be at 5856 m TVD/MD. The bypass port was then closed. It was then observed that the loss rate reduced to 3.65 m3/hr (23 bbl/hr) when circulating the hole clean at 5800 m TVD/MD and maintaining the same ECD of 1.22 SG (10.2 ppg) with the help of MPD equipment; pumping down string at 3028 l/min (800 gal/min) and boosting the marine riser at 757 l/min (200 gal/min). This pill was designed to self-degrade after 4 days. The pill lasted for 5 days, and the loss rate came back to its original level, providing evidence that the fiber had self-degraded as expected. MPD helped minimize further loss through the reduction of hydrostatic overbalanced pressure. Later, openhole wireline logs were run and did not reveal any change in expected porosity or permeability.
This paper presents a case study in which the introduction of degradable fiber through a bypass port in the bottomhole assembly (BHA) cured severe loss of nonaqueous fluid (NAF) in a deepwater exploration well without damaging the formation. This case provides evidence that properly designed fiber-based pills can be used in the reservoir section without any major consequences on the well production potential.
As hydrocarbon reserves become scarcer, exploration and development efforts are increasing in locations where the downhole environment is hostile. This paper introduces a new measurement and logging while drilling (MLWD) system capable of operating at up to 200°C (392°F).
In some areas of the world, operators are developing fields in which the great depth of the reservoir results in extremely high pressure. In other areas, the primary concern is the extremely high reservoir temperature. Such environments present challenges when running tools containing any type of electronics. These electronics must be protected from pressure and be either protected from heat or designed to tolerate high temperatures.
High-temperature (HT) wireline logging tools have existed for many years. These tools mostly use flasking technology to insulate the electronics from high reservoir temperatures. The short duration of most wireline runs makes flasking a practical solution, but MLWD tools operate in the well for too long for this technology to remain effective. Instead, the electronics must be designed to operate at high temperatures without insulation. This requirement has previously limited the range of temperatures in which operators use measurement-while-drilling (MWD) and logging-while-drilling (LWD) tools. The new system contains electronics designed to operate at up to 200°C. It has undergone extensive field testing and has demonstrated its reliability over long periods of sustained high temperatures. The system comprises a base-services collar, providing real-time measurements of well trajectory, borehole pressure, drillstring dynamics, and natural formation gamma ray emissions. It also includes a set of additional collars, providing resistivity, density, and neutron-porosity measurements in zones where these have traditionally been unavailable.
The new system has been used in multiple regions in multiple HT wells, delivering significant time and cost savings to operators. It has allowed the wells to be drilled more quickly as a result of the reduced need for temperature mitigation and has further reduced costs by eliminating or reducing the need for dedicated wireline logging runs.
The oilfield industry is facing more challenges as wells have become more complex. Companies are designing casing programs that utilize larger casing sizes and setting them deeper than ever before. For cased hole sidetracking projects, this means sidetracks with increasing levels of difficulty such as thicker casing walls, double casing exits, and extended ratholes. These new challenges also represent issues involving premature cutting structure damage, ringouts, coreouts, twistoff, and undergauge windows and ratholes that require unplanned or additional runs—both of which result in nonproductive time to the operator. The ability to analyze and predict the performance of milling tools is critical, and reliability performance curves provide value to the remedial operation planning phase of the sidetrack project. These curves can also be used as a decision-making tool while on a job.
These are the first known reliability and performance curves for sidetrack milling tools. The curves are built using 10 years of historical data, including mill type, size, and casing grade. The parameters were selected based on acceptable gauge criteria, among others. Up to six casing grades can be analyzed and compared for median hours of milling, average ROP, percentage of cutting structure wear, and milling tool reliability.
These curves establish a baseline of performance for mills in their current and future designed state. Any future design changes can then be referenced against these curves to monitor improvement of the tools over time. Engineers may also utilize the curves to conduct operational risk assessments and estimate the performance of mills, especially in challenging environments such as hard formations or thick or double casing string applications. Educated decisions can then be made to prevent or reduce unexpected time loss.
Reliability curves are being generated to improve planning for sidetracking operations as well as making informed decisions on when to pull a mill and replace with the backup. This helps to maintain a full-gauge window or rathole, avoiding tool failures, unplanned trips, and nonproductive time. This decision-making tool can save valuable rig time, which is increasingly important with larger spread rates and deeper wells.
A real scenario was analyzed from a previous job and demonstrated that using the curves as a decisionmaking tool could have saved 30% of the actual downtime.
Advances in technology are pushing the boundaries of what is possible with wireline cable conveyance with heavy payloads. New high-strength cables, conveyance systems, wireline tractors, prejob modeling software, and a wide range of additional enabling technologies have shifted the conventional norm for wireline perforating applications, thereby allowing for the successful shooting of very long perforating gun strings. Detailed job planning is required and, with the help of conveyance planning and shock modeling, perforating bottomhole assemblies can be optimized and maximized payloads of perforating guns can be run. Successful operations have been completed in which 100 ft or more of perforating guns from 2 7/8-in. to 7-in. have been deployed and shot in a single descent in many areas including Qatar, Oman, UK, Norway, Mexico, and Brazil.
Combining the new hardware breakthroughs with advanced software modeling has enabled the implementation of ultralong and heavy wireline perforating jobs in both offshore and land operations. These new wireline perforating techniques have improved efficiency and logistics while reducing rig time and cost; they will be of interest to all operators conducting perforating operations.