Underbalanced drilling via air drilling is deeply rooted in the Northeast United States due to its distinct geology, high rates of penetration (ROP) and drilling efficiency, and low cost of circulating material. The active drilling programs of several independent operators in the Marcellus and Utica Basins are well suited for air drilling down to the final kick off point by virtue of competent, stable formations, low static reservoir pressures, and manageable water ingress to the wells. Air drilling provides near-atmospheric pressure at the borehole bottom, since there is no fluid column with resulting hydrostatic pressure. The result is very high ROP with essentially 100% drilling efficiency, allowing the completion of intervals in one or two bit runs. A service company deployed a cross-functional product development team to optimize oilfield air bits for these applications over the last two years, resulting in decreased drilling costs through increased performance and reliability.
The oilfield air drilling environment places unique challenges on drill bit design due to the increased risk of downhole vibrations, corrosion, abrasive wear, heat generation, and seal infiltration of very fine cuttings. The application requirements have increased due to deeper intervals requiring passage through multiple high unconfined compressive strength formations, extended tangent angles, and rising input energy levels. Accordingly, enhancements to both the cutting structures and sealed bearing systems were vigorously pursued. Several cutting structure design iterations were evaluated in both laboratory and field tests. A new sealed bearing system was developed and implemented for increased life and reliability. Modifications to the bit body for stability were included, and the bit hydraulics were further optimized.
Through an understanding of the objectives and application challenges, unique solutions were developed for Northeast oilfield air drilling applications. The optimization process for the new air bit designs is described, and the resulting positive performance metrics are presented. Improvements were observed in distance drilled, ROP, seal effective rate, and dull condition. Lessons learned were also used to refine the recommended drilling parameters and practices through the challenging formations encountered in these tangent sections, which can span in excess of 7000 feet. These enhancements all contributed to reduced drilling cost and days per well, for increased rig productivity.
The natural gas fields throughout the Marcellus and Utica Basins in the Northeast U.S. continue to deliver rising total gas production for the U.S. and the world through increased capacities in pipelines and LNG trains. Improved drilling performance as documented in this paper are driving continuous improvement in the overall upstream drilling economics of the region.
Mansir, Hassan (COREteQ Systems Limited) | Rimmer, Michael (COREteQ Systems Limited) | Waldner, Leon (CNOOC International) | Graham, John (Suncor Energy) | Hong, Claire (Cenovus Energy) | Wycislik, Kerry (Cenovus Energy) | Duong, Bruce (Alberta Innovates)
The development of a High-Temperature Permanent Magnet Motor (PMM) was initiated with the main objective to bring forth a technical solution to significantly increase temperature capability and run life of ESPs in Steam Assisted Gravity Drainage (SAGD) beyond current technology. This is in response to operators needs for improved safety margins and increased production rates. Existing ESP motor technologies are limited to approximately 300 C internal motor winding temperatures, driven by the available motor electrical insulation systems. The use of PMMs in SAGD was also prohibited by the availability of magnet materials capable of operating in such temperatures, without partial or full demagnetization. The project's aim is to break this barrier and extend internal temperatures to 350 C and beyond, allowing well ambient temperatures to be pushed beyond the 260 C downhole environment. In addition, for assurance of motor reliability, rigorous and methodical design validation and qualification testing of basic materials, components, sub-assemblies were undertaken.
Brady, Jerry (Brady Technologies of Alaska) | Passmore, Kevin (Halliburton) | Paskvan, Frank (BP) | Wilkes, Jason (Southwest Research Institute) | Allison, Tim (Southwest Research Institute) | Swanson, Erik (Xdot Engineering and Analysis) | Klein, John (Roto-Therm Incorporated)
This is the first time a compressor and turbo expander have been built small enough to be run through tubing and operated autonomously from the surface. A brief review of the overall system design and critical component design and testing are followed by a detailed review of the surface testing of the entire prototype machine at simulated downhole conditions. The SPARC concept uses the excess production pressure (energy) that is usually wasted across a choke or elsewhere in the production system to generate power through a downhole turbo-expander that runs a downhole gas compressor to reinject a portion of the gas stream. The system consists of a downhole separator, compressor, turbo-expander and other standard downhole equipment for the necessary plumbing. The successful test results of the bearing and thrust disk component testing at up to 1,000 psig and 450 F are provided, followed by the successful yard test results of the entire SPARC prototype machine at downhole flowing conditions, including all the rotating equipment (turbo expander, compressor, and shaft), in situ process-lubrication system, and autonomous controls.
Sand management has become in one of the most vital factors in today's upstream oil and gas industry, more and more are the cases where the sand control systems play an important factor to determine the economic viability of each project. This paper will focus in a solution for sand problems in ESP systems applying to sand slug breakdown using a 10 V-Mesh Sand Screen to homogenize the solid inflow in the system so it would be easier to handle the solids through the ESP's stages. The implementation of the screen intake for the homogenization of solids in an ESP well allowed to efficiently manage sand slugs, improving the pump efficiency and avoiding blocking problems in the pump caused by sand. Furthermore, the system allows increasing the frequency of operation of the ESP motor to have a greater drawdown, increasing the production of the fluid from 1600 BFPD to 1800 BFPD. The behavior of the sensor data such as vibration, current, and voltage remained stable throughout the period evaluated, extending the run life of the system.
Historically, motor temperature analysis in electric submersible pumping systems (ESP) attracted the most attention due to the vulnerability of insulation under temperature. For wells with low or moderate downhole temperatures, motor temperature alone is not effective to protect the system against no-flow conditions. This issue has become more critical in unconventional gassy wells, many ESP failure modes are more associated to high temperatures in the pump than the motor. Under gas locking or no flow conditions when production (cooling) fluid stagnates, the pump generates much more heat than the motor and experiences a faster temperature rise becoming a serious issue for the health of the ESP. Traditional pump intake and discharge thermocouples (TC) cannot detect this phenomenon because their locations are too far from the source of heat generation. This paper describes testing where several TCs were placed in an ESP pump. Temperatures were monitored when the pump was operated through different gas volume fractions (GVF) and flow rates. A gas locking condition was also simulated in a test loop to study the transient condition. Subsequently, a thermal model was developed and compared to the testing data.
The test used a fully enclosed, high-pressure gas loop. A 12-stage, mixed flow type with best efficiency point (BEP) at 600 BPD pump was horizontally mounted in a test bench. Ten TCs were installed at the bottom bearing, No.1, 6, and 12 diffuser bearing in both X and Y directions, respectively. Three TCs were attached to the pump housing on bottom, middle, and top locations. Pump intake/discharge temperature and pressure were captured during testing. The mixture volume of nitrogen and water was measured and supplied to the pump intake. Experimental data was acquired continuously for evaluating different operational conditions. The intake pressure, GVF, flow rate and rotational speeds were controlled in the experiments. In a static state, the thermal model started with energy equilibrium and calculated the temperature rise due to the difference between the pump brake horsepower and hydraulic horsepower. In a transient state, finite-element analysis (FEA) was used to predict the thermal profile from the stage bearing to the pump housing.
Based on the thermal testing and modelling results, several ESP failure modes and tear-down examples will be discussed. The concept of minimum continuous thermal flow (MCTF) will be mentioned. A reservoir model was used to understand the difference in the nitrogen/water testing system and to develop the possible strategy to recover from pump gas locking. In summary, the pump temperature study provided a better understanding of the pump gas locking condition, a better method to conduct ESP health monitoring and improve reliability by avoiding overheating the pump.
This paper adds a comprehensive knowledge of pump temperature analysis to the ESP industry. The results will help define the running limitations of an ESP in a gas condition and improve design, application and operation to mitigate the gas locking issue in unconventional oil production.
Reciprocating compressors are positive displacement machines in which the compressing and displacing element is a piston having a reciprocating motion within a cylinder. The high-speed category also is referred to as "separable," and the low-speed category also is known as "integral." The American Petroleum Institute (API) has produced two industry standards, API Standard 11P and API Standard 618, which are frequently employed to govern the design and manufacture of reciprocating compressors. The term "separable" is used because this category of reciprocating compressors is separate from its driver. Either an engine or an electric motor usually drives a separable compressor. Often a gearbox is required in the compression train. Operating speed is typically between 900 and 1,800 rpm. Separable units are skid mounted and self-contained. They are easy to install, offer a relatively small initial cost, are easily moved to different sites, and are available in sizes appropriate for field gathering--both onshore and offshore. However, separable compressors have higher maintenance costs than integral compressors. Figure 1 is a cross section of a typical separable compressor. Figure 1 shows a separable engine-driven compressor package.
In a centrifugal compressor, energy is transferred from a set of rotating impeller blades to the gas. The designation "centrifugal" implies that the gas flow is radial, and the energy transfer is caused from a change in the centrifugal forces acting on the gas. Centrifugal compressors deliver high flow capacity per unit of installed space and weight, have good reliability, and require significantly less maintenance than reciprocating compressors.
Bit classification allows efficient selection and use of polycrystalline diamond compact (PDC) and diamond drill bit. The classification system currently in use was developed by the International Association of Drilling Contractors (IADC). IADC classification codes for each bit are generated by placing the bit style into the category that best describes it so that similar bit types are grouped within a single category. The version currently used was introduced in 1992 using criteria that were cooperatively developed by drill-bit manufacturers under the auspices of SPE., The system leaves a rather broad latitude for interpretation and is not as precise or useful as the IADC Classification System for Roller-Cone Bits. It does not consider hydraulic features incorporated into a bit and does not attempt to give a detailed description of body style beyond basic classification of the overall length of the bit cutting face.
Compressors used in the oil and gas industry are divided into six groups according to their intended service. These are flash gas compressors, gas lift compressors, reinjection compressors, booster compressors, vapor-recovery compressors, and casinghead compressors. Flash gas compressors are used in oil handling facilities to compress gas that is "flashed" from a hydrocarbon liquid when the liquid flows from a higher pressure to a lower pressure separator. Flash gas compressors typically handle low flow rates and produce high compression ratios. Gas lift compressors are frequently used in oil handling facilities where compression of formation gases and gas lift gas is required. Gas lift compressor duty is frequently of low to medium throughput with high compression ratios. Many gas lift compressors are installed on offshore facilities. The reinjection of natural gas is employed to increase or to maintain oil production. Reinjection compressors can be required to deliver gas at discharge pressures in excess of 10,000 psi. Reinjection compressors also are used for underground storage of natural gas. Compressors, applied to these services, have large compression ratios, high power requirements, and low volume flow rates.