On offshore rigs, oil-based mud (OBM) cuttings can create logistical and environmental risks. Onshore disposal requires costly transport, and bad weather can halt shipping operations. The liability for waste treated onshore belongs to the operator. Although offshore disposal removes this liability, UK North Sea regulations specify that oil on cuttings (OOC) must be less than 1%. (by weight?) A rigsite thermomechanical cuttings cleaner (TCC) applies high temperatures to help reduce OOC to less than 1% and recovers base oil and water for reuse.
A TCC unit was installed on a semisubmersible rig to process OBM cuttings for a 24-well program. Mechanical action is applied directly to the cuttings by means of hammers that create friction, causing temperatures to exceed the boiling points of water and oil so that hydrocarbons are separated. The oil and water vapors are removed and condensed where the base oil and water are further separated and recovered. The TCC process on this rig was supported by vacuum-pump conveyance equipment and specialized storage tanks. Cuttings were no longer shipped to shore, and crane lifts associated with "skip-and-ship" operations were minimized significantly.
The TCC unit processed 14,500 metric tons (MT) of OBM cuttings throughout the duration of the 24- well program. The total footage drilled with OBM was more than 160,000 ft. All cuttings were disposed offshore. Approximately 13,500 bbl of base oil (valued at USD 135/bbl) was recovered for reuse in the drilling fluid system. The TCC unit ran for a total of 3,500 hours with zero downtime or nonproductive time (NPT) associated with cuttings disposal. The average is approximately 150 operating hours per well. One important benefit was the dramatic reduction of skips handling and crane lifts, which provided safer working conditions for rig crews. On a conventional skip-and-ship operation, the operator would fill and transport up to 35 skips per day. This translates to 2,380 crane lifts per well that were unnecessary. Offloading delays caused by bad weather were no longer a factor, thus helping reduce uncertainty and saving valuable rig time. Processing this volume of drill cuttings offshore meant that more than 57,000 skip crane lifts were avoided. The TCC mobilization process for this program was executed efficiently by coordinating with quayside contractors (welders, platers, electricians, etc.) to complete much of the installation work scope onshore.
Thermal treatment enables operators to address stringent offshore discharge regulations globally, excluding countries with zero discharge policies. Cost benefits include the following: No "wait on weather" time (rig day rate = USD 300,000) No dedicated vessels for transport No quayside cuttings handling No trucking to treatment and disposal facilities
No "wait on weather" time (rig day rate = USD 300,000)
No dedicated vessels for transport
No quayside cuttings handling
No trucking to treatment and disposal facilities
Safety and environmental benefits add the following value: Reduced manual handling of skips Reduced crane lifts Base oil reuse Liability for waste ends at rigsite
Reduced manual handling of skips
Reduced crane lifts
Base oil reuse
Liability for waste ends at rigsite
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.
The decisions of Canada’s top court clarify when the duty to consult is triggered; confirmed that the Crown can discharge its duty to consult through the project approval process undertaken by the regulatory body; and illustrated how to, and how not to, discharge the duty. The Supreme Court of Canada has unanimously clarified several features of the crown’s duty to consult with and accommodate indigenous populations before project approvals are granted.
Weights used in the original construction of TransCanada’s Keystone Pipeline in South Dakota were identified as a preliminary cause of the failure that resulted in a 210,000-gal spill in November. SPE's report on Worst Case Discharge is designed to help US offshore operators calculate WCD to comply with the BOEM definition. The burning of oil in place (in situ) on water is a viable means of mitigating the impact of marine oil spills. This paper examines decision criteria and safe practices for deploying this method in both icy and warm conditions.
The Hibernia platform is 315 km east-southeast of St. John’s, Newfoundland. Hibernia Management and Development Company (HMDC) has again halted production from its 220,000-B/D Hibernia platform off Newfoundland and Labrador after another oil spill was reported 17 August. HMDC, an ExxonMobil-led consortium, had resumed production from Hibernia just 2 days earlier, ending a month-long shut down due to a first discharge. Husky Energy on 16 August also brought on stream for the first time since November 2018 its North Amethyst and South White Rose Extension drill centers at the White Rose field, where a failed flowline connector resulted in a 1,572-bbl spill—the largest-ever off Newfoundland and Labrador. The latest incident at Hibernia came as the platform’s deluge system—or water sprinkler system—inadvertently activated amid a loss of main power generation, causing drains to overflow, C-NLOPB said.
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.
A relief system is an emergency system for discharging gas during abnormal conditions, by manual or controlled means or by an automatic pressure relief valve from a pressurized vessel or piping system, to the atmosphere to relieve pressures in excess of the maximum allowable working pressure (MAWP). A scrubbing vessel should be provided for liquid separation if liquid hydrocarbons are anticipated. The relief-system outlet may be either vented or flared. If designed properly, vent or flare emergency-relief systems from pressure vessels may be combined. Some facilities include systems for depressuring pressure vessels in the event of an emergency shutdown. The depressuring-system control valves may be arranged to discharge into the vent, flare, or relief systems.
Positive displacement pumps were developed long before centrifugal pumps. Liquid is positively displaced from a fixed-volume container. Positive-displacement pumps are capable of developing high pressures while operating at low suction pressures. They are commonly referred to as constant-volume pumps. Unlike centrifugal pumps, their capacity is not affected by the pressure against which they operate. Flow is usually regulated by varying the speed of the pump or by recycle. Positive-displacement pumps are divided into two groups: rotary and reciprocating pumps. Rotary pumps are normally limited to services in which the fluid viscosity is very high or the flow rate too small to be handled economically by other pumps.
A liquid has a definite volume when compared to a gas, which tends to expand to fit its container. When unconfined, a liquid seeks the lowest possible level. Because of its fluidity, a liquid will conform to the shape of its container. The pressure existing at any point in a liquid body at rest is caused by the atmospheric pressure exerted on the surface plus the weight of the liquid above that point. This pressure is equal in all directions.
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.