Pressure Pulse Workovers in Heavy Oil

Objectives/Scope To reduce flaring of produced hydrocarbon during well testing operations in order to protect the environment, comply with safety regulations and conserve oil. Methods, Procedures, Process During well-testing operations the produced hydrocarbon is usually flared in the open flare pit. As per the existing company's HSE procedures, flaring during well testing is considered as a safe option. However, flaring activities needs to be minimized or eliminated as some wells are located in environmentally sensitive areas which are close to farms, Highways or camping area. Due to location constraints the flaring should be minimized to the possible extent. As the well is exploratory, the well was not connected yet to the production facility. The only means of oil transportation will be by using road tankers, for that the H2S concentration in oil needs to be reduced to a permissible limit. The heavy oil well to be tested contains H2S concentration upto 22 %(220,000 ppm) in gas. A novel process was initiated to eliminate/minimize flaring during well testing operations. H2S scavenger technology was selected for field trial to convert the produced sour liquid to be suitable for transportation through vacuum tankers to the nearest production facility. Accordingly H2S scavenger chemical was arranged and well test surface layout was modified with additional chemical dosing points. After separating the gas from oil using surge tank and separator dosed H2S Scavenger into oil line. This exercise resulted in ensuring that the H2S concentration in treated oil is at a permissible limit and the oil is suitable to be transported using road tankers. Results, Observations, Conclusions Field trail was implemented in sour heavy oil well to evaluate the feasibility of using H2S scavenger chemical to mitigate/minimize high H2S concentration in the produced fluid. Two heavy oil wells (17-200 API) were tested with this process and H2S content in oil was reduced to almost 15 ppm. Achieved economical H2S scavenger treatment cost of $18/bbl for reducing H2S in oil from 600 ppm to 15 ppm. Oil flaring was eliminated and only small quantity of the produced sour gas(0.001mmscfd) was flared safely through flare stack. Approximately 5,500 bbls of crude oil were produced from an exploratory well and safely transported by road tankers to nearby production facility during two weeks of testing period. For the first time in Kuwait an exploratory sour heavy oil well was successfully tested without flaring oil. Novel/Additional Information The innovative solution of using H2S Scavenger during testing the sour well had eliminated flaring of crude oil which avoided environmental pollution and conserved the produced oil. This success proves that sour heavy oil wells can be tested safely without flaring oil and paves the way for implementing this novel concept in future applications.

An experimental study on the multiphase flow of heavy oil gas lift was conducted on 18.25 m high vertical tube. Based on the experimental results and the wellbore heat transfer mechanism, a coupling model of wellbore pressure–temperature gradients was presented for the gas lift with light oil injected from the annulus. Moreover, the solution of coupling annulus flow with tubing flow was also established through cyclic iteration. Experimental results showed that gas injection enables heavy oil and light oil to mix rapidly and completely. Evaluation of pressure drop models shows that the error of the Ansari model is approximately 12.12%, by comparison it is the least. A novel method of gas lift assisted with light oil from the annulus was proposed to solve the actual situation wherein heavy oil cannot be easily lifted from the wellbore at Tuyuke Block in Tuha Oilfield. An instance design based on the sensitivity analysis of the gas injection rate and diluting rate was also completed. The instance design shows that the productivity of heavy oil well can be significantly improved using gas lift and blending diluting oil technology. In order to verify the feasibility and effect of gas lift assisted with light oil in heavy oil well, a pilot test was implemented in Tahe Oilfield, Xinjiang, China. The results of pilot test show clearly that the daily production rate increased from 11.6 to 38 t/day, and the ratio of light oil with heavy oil decreased from 11:1 to 4:1. From the above, gas injection can significantly reduce the usage of light oil needed, and gas lift assisted with light oil injected from the bottom hole can significantly enhance the productivity of heavy oil wells.

In rod pump applications around the world heavy oil and sand production is believed to be a dangerous combination. This paper highlights a case study of a heavy oil well in the North Kuwait field where sand production was monitored closely to avoid flow line choke and down hole failures. This case study was used as a pilot for the neighboring wells producing from the same reservoir. In case of wells producing heavy oil with considerable sand production and that undergo cyclic steam stimulation the challenge is often at the end of the production cycle. While the oil is thin and has good viscosity the sand settles itself at the bottom. However, with time as the oil gets colder and thereby heavier, it carries the sand along with it to the surface causing plug in the flow line. This is due to the high viscosity of the oil. This is believed to be the end of production period beyond which it would have been impossible to produce any further even after sand cleanup. Certain operational procedures were established to ensure the integrity of the down-hole equipment and to avoid the failures. It has been observed that by effective sand monitoring it was possible to determine the next injection cycle with more precision. This standardized the injection and production cycle. The flow line choke up problems were completely eliminated as the production period would cease as soon as some sand would begin to appear at the surface. It was possible to establish API gravity cutoff for oil production thus avoiding rod and pump failures. This implementation has been undertaken for the entire field and has shown significant operational efficiency. A pilot was conducted to justify the use of sand production as an indication for the next production cycle for heavy oil well under cyclic steam stimulation.

Offshore heavy oil production based on moderately sand production has obtained good effect in branch horizontal wells but heavy oil has is the characteristics of high viscosity, high wax content, and poor fluidity which affect seriously the lifting of heavy oil, and even result in pump plugging and damaged, these questions cannot be ignored in the process of cold recovery of heavy oil in horizontal wells. For reducing heavy oil viscosity and improving heavy oil liquidity, electronics-acoustic dual mode for recovering heavy oil is proposed in order to reduce viscosity and improve the productivity of heavy oil wells. Electronics heating and high-power ultrasonic are used together and distributed along the horizontal section; transmission cable is transported to horizontal well section through continuous tubing. In the paper, the realization method of electro-acoustic dual effect to heavy oil wells is introduced, and key technologies of the scheme are analyzed, such as power supply for electronics heating, ultrasonic transducer structure, and ultrasonic generator. Especially, depending on the simulation and laboratory testing, the optimal working parameters were determined which can provide reference for designing electronics-acoustic equipment. This scheme can not only be applied for heavy oil production, but also be used in low-permeability reservoirs, dense rock reservoir exploitation, etc. There is no doubt that the scheme has a good prospect in petroleum production.

Although there is abundant heavy oil resource in Bohai oilfield, only limited oil production is obtained by non-thermal production technologies such as ESP in past. The practical challenging of thermal production technologies, for instance, CCS and SAGD is the difficulty to install the large conventional steam generator onto offshore production platform. In order to recover offshore heavy oil in Bohai Oilfield, the largest offshore oilfield in China, at large oil production rate in the limited production platform lifetime, a portable steam and gas generator is developed to produce high temperature and high pressure steam, CO2 and N2 on production platform using diesel oil or natural gas as fuel. The temperature of produced steam could be regulated, usually 150 to 300, and the pressure is up to 20MPa. The components such as fuel tank, water treatment, air injection unit could be easily resembled on the production platform. The steam generated and exhausted CO2and N2 could be injected into oil well to stimulate offshore heavy oil reservoir in huff and puff or SAGP processes. In past three years, there are 2 non-thermally completed heavy oil wells and 7 thermally completed heavy oil wells are successfully stimulated by co-stimulation with steam and flue gas generated by above generator. As a result, the gas generator is operated soundly, the engineering design and related implement techniques such as insulation, sand control and corrosion inhibition are feasible, and oil production rate increased obviously (more than 100 m3/day oil production rate obtained, it is up to 5 times than cold production), total increased heavy oil production compared to cold production per cycle is about 5000m3 to 10000m3. Primarily, it shows that co-stimulation is much effective and practical for offshore heavy oil production. In this paper, cases of co-stimulation with steam and flue gas are introduced in detail, and related techniques and practices discussed as well.

In Oman Southern oilfield, valve malfunctions in sucker rod pumps, driven by sand-laden heavy crude oil and low bottom-hole temperatures, have consistently led to rod failures, production instability, and elevated operational costs. These challenges are particularly critical in mature heavy oil assets where downtime, frequent interventions, and reduced run life significantly erode field economics. Conventional ball-and-seat valve systems often fail under these harsh conditions because they are unable to maintain sealing efficiency in the presence of abrasive solids and temperature-induced viscosity changes. As a result, operators have long relied on reactive maintenance and repeated workovers, both of which increase OPEX and defer production. To address this persistent problem, a novel spring-loaded valve system was introduced and tested in six representative wells. The design, co-developed with the customer, incorporated enhanced sealing dynamics and sand-tolerant features to counteract the root causes of failure. Field implementation demonstrated tangible improvements: production increased by an average of 20%, pump strokes stabilized with smoother operation, and no interventions were required during the monitored period. Comparative analysis of pre- and post-installation performance highlighted measurable reductions in downtime, repair frequency, and associated costs. Beyond operational reliability, the economic impact was equally compelling. For example, incremental gains of approximately 60 BOPD per well, at an oil price of USD 70/bbl., translate to more than USD 1.5 million additional annual revenue across a 10-well cluster. These improvements were coupled with a projected 40% extension in pump run life, thereby deferring capital replacement costs and improving asset reliability. This innovation not only resolves long-standing valve failure issues but also provides a competitive advantage by balancing technical robustness with economic sustainability. While early outcomes are promising, ongoing monitoring is in place to confirm long-term durability and scalability across larger well populations. The study highlights the broader potential of spring-loaded valve systems to optimize sucker rod pump efficiency, reduce intervention frequency, and deliver cost savings in heavy oil environments where conventional technologies fall short.

This paper describes the implementation of a performance analysis (PA) review and a comprehensive root cause failure analysis (RCFA) for the artificial lift system (ALS) failures in heavy oil wells. The subject wells, located in Egyptian Eastern Desert (EED), have been operated by Canadian-Egyptian joint venture. Progressive cavity pump (PCP) and beam pump (BP) have been selected as the preferred ALS methods. With the objective of improving ALS performance, RCFA identifies the main causes of ALS failures and proposes guidelines and recommendations with a new open source service for the current and future development for EED Oil companies. PA has been applied using some Key Performance Indicators (KPI), such as: failure index, recurrence index, and average run life in order to track all failed and crucial issues. RCFA has been applied to different ALS, such as: BP and PCP. Therefore, the definition or limitation of the boundaries of each system and the classification of failures were performed. RCFA covered failures between 2012 and 2018 for average 150 active wells and 622 failures. Finally, the new open source service applied as a trial to evolve the failure tracking and decision making methodology. PA review showed a high failure and recurrence index that reached 3.0 and 3.7, respectively, in 2014 then declined to 1.0 and 1.7, respectively, in 2017 as a result of comprehensive corrective actions implemented. RCFA showed that rod string failure in BP was and still is a dominant failure with 200 failures over the last six years. Moreover, Down-hole pump failure in PCP was the major PCP failure system although its failures declined from 80 failures in 2014 to 14 failures in 2018. Several field cases were presented to cover the dominant cause of failures for both BP and PCP wells. Most wells had a significant improvement in their mean time to failure (MTTF) after reviewing design, installation and operation procedures. The procedure for carrying out this methodology and implementing lessons learned has been presented in this paper. In addition, the new open source integration service provides an increased visibility about individual well performance issues and more broadly, about field performance and ALS failures.

In consideration of the difficulty to setup conventional steam generator on offshore production platform, a compact steam and flue gas generator is developed to thermally stimulate offshore heavy oil reservoir, which consists of water treatment and injection unit, fuel injection unit, air injection unit, and metering and controlling unit. The temperature of steam and flue gas generated is usually 200-350°C with 13.1-28.3wt% flue gas, the injection pressure could be up to 20MPa, and steam injection rate is 80-270 m3/day. In past two years, cyclic steam-flue gas co-injection are applied to 8 offshore horizontal heavy oil wells completed thermally or non-thermally with screen pipe, and up to 3 times of oil production rate in average is observed compared to that of cold production, the peak oil production is more than 100 m3/day. In order to optimize the steam and flue gas co-injection strategy, laboratory experiments such as rheological characteristic measurement and PVT visualization of mixture of heavy oil and flue gas, 1D micro model displacement and 3D macro sandpack model stimulation, and numerical simulation are carried out to investigate the EOR principles. It shows significant synergistic EOR effect in steam and flue gas co-injection because of the foamy oil flow, improvement in heating and sweeping efficiency and gravity assisted drainage, besides of the combined reduction in oil viscosity by heating and gas solution. Flue gas plays an important role in co-stimulation of heavy oil with lower viscosity (500-2000mPa•s under reservoir condition) for the foamy oil flow and enlargement of heating and sweeping efficiency, at the same time, steam heating becomes more important for heavy oil with larger viscosity. At last, based on above researching results an empirical formula is developed to optimize ratio of flue gas to steam according to special reservoir conditions.

The development of heavy oil fields imposes several challenges for well construction: in order to guarantee minimum flow rates, long horizontals intervals are often required. Long horizontals are associated to long reservoir exposure times which can affect final open hole quality. Rock fluid interaction issues and BHA design directly affect the drilling of sensitive formations, such as non consolidated heavy oil reservoirs. This article presents initially a comprehensive data analysis of caliper logs in offshore heavy oil wells drilled in Brazil. The analysis correlates hole enlargement with relevant parameters such as fluid type, flow regime and BHA composition. Data sources considered were real time monitoring equipment, logging data and drilling reports. Results indicate that water based fluids and turbulence proved to stimulate hole enlargement and should be avoided. The study is also supported by a unique experimental work where fluid flow conditions were simulated in a pilot unit where the wellbore was represented by a non consolidated synthetic core saturated with high viscosity oil. For a given flow rate, hole enlargement is monitored with time by a real time CT scanning technique. Experimental results are in agreement with field observations. The role of drillstring composition was not contemplated in the experimental study.

Petro-Canada operates a number of thermal and non-thermal projects in the oil sands and heavy oil areas of Eastern Alberta and Western Saskatchewan. These projects have been plagued with low pump efficiencies, slow rod fall, fluid pound, solids production and overloaded pumpjacks. Petro-Canada's solutions to these problems on steam, fireflood and primary producers in unconsolidated sand formations are presented in this paper. Specific topics include completion practices, bottomhole pump designs, sand control equipment and production techniques. Introduction Production of heavy oil, whether on primary or with the assistance of enhanced oil recovery techniques, is far more difficult than recovery of conventional light oil. Production wells at Petro-Canada have gone through many stages of development. Earlier wells were designed to obtain both production and information. Cost effectiveness, reduced maintenance and improved production were the bases of later well designs. Standardized completions have evolved for primary (Fig. 1), steam (Fig. 2) and fireflood (Fig. 3). Casings All surface casing is 244 mm. 48.1 kg/m. H-40, ST+C. Heavy oil wells use large 178 mm production casing so that sand control devices can be installed if necessary, larger tubulars can be used to reduce rod fall problems, dual completions can be considered, and conversion a f a field from primary to EOR can be readily accomplished. Primary wells are completed with 178 mm, 29.5 kg/m, K-55 ST+ C casing. The preferred casing on thermal completions is 178 mm, 34.2 kg/m, MN-80, Buttress, landed in tension but not prestressed. Fireflood wells use non-exotic alloys for all of the wellbore except across the zone of interest, where nickel alloys are run. Cements Good cement bonds, with minimal loss of cement into formations are the main objectives of Petro-Canada's cementing programs. A typical primary cement would consist of Class "A" + 3% CaCl2 for the surface casing, 2: 1:4 Pozmix for the upper 70% of the production casing, and Class "G" + 3% KCl for the lower 30% of the production casing. Fireflood wells subsitute Ciment Fondue, extended with alumina silicate firebrick, for the lower 30% of the production casing. Steam wells are frequently located in areas where lost circulation of cement is a problem. The use of lightweight cements (1,400 kg/m3) reduces the loss of cement. Free pipe for the upper 20 to 30% of the well and wellhead growth of up to 0.6 m while steaming a well is not uncommon. A typical thermal cement for a steam well could consist of 50% Class G, 25% spheres and 25% Silica Flour. Foamed thermal cements have been used on a few wells. Wellheads Blowout preventors are bolted to 279 mm, 14 MPa slip-on casing bowls welded onto the surface casing. All production casings, whether primary or thermal, are landed in slips in the surface casing bowls. Primary wellheads are bolted directly to the surface casing bowl and consist of a 279 mm by 179 mm by 14 MPa tubing head with lock down screws, tubing hanger for 73 mm EUE tubing, 179 by 73 mm bonnet, 73 mm BOP, 73 mm Flow tee and 73 mm stuffing box.

The favourable behaviour of heavy oil reservoirs under solution- gas drive has intrigued the oil industry for a long time. Many mechanistic models have been proposed to explain this behaviour. This paper investigates one of the theories that attributes the low producing GOR and high recovery of heavy oil to low gas mobility. A simulation study was carried out on a commercial black oil simulator to match the "typical" production data of heavy oil fields in Lindbergh and Frog Lake. Sensitivity studies were carried out to investigate the effect of gas relative permeability on oil recovery. The effect of sand production, which is an integral part of heavy oil production in Western Canada, was also investigated. A parameter was used in the simulator to account for the increased permeability due to sand production. The results indicate that the field performance can be matched by using low gas mobility and incorporating improved permeability due to sand production. Neither of them alone was sufficient for matching the field performance. The use of a low gas mobility was successful to explain high pressure-gradients in the field, by acting as a pressure maintenance mechanism, and leading to a high recovery under solution-gas drive. Intruduction PanCanadian has been one of the major operators in the Lindbergh and Frog Lake heavy oil fields of northeast Alberta(1). The production in these fields is from the Upper Mannville group. The producing formations contain oil of 12 – 14 ° API with in situ viscosities of 3,000 – 10,000 cp. The fields have shown recovery much in excess of what can be predicted by applying conventional flow equations. Many heavy oil wells under primary production have produced about 15% of the original oil in place (OOIP) in 10 years(1). The primary oil production in these fields is accompanied by sand production and is called "Cold Production." A typical well in the Lindbergh and Frog Lake fields under depletion has produced an average of 9,200 m3 of oil and about 230 m3 of sand in 1,000 days(1). Several tests have been carried out to determine the mechanism responsible for the favourable behaviour of these reservoirs. Metwally and Solanki(1) presented a simulation model to match the field production behaviour. The authors postulated that reservoir porosity and permeability are increased due to sand production. Additionally, the authors showed that a pressure support mechanism needs to be incorporated to match recovery data; an external aquifer was therefore incorporated into the model. Similar to Metwally and Solanki(1), we use a commercial simulator to match the production data. We show that the use of low values for gas relative permeability results in pressure maintenance and substantial oil production. Accounting for the low gas mobility along with the improved permeability resulted in a match of the field data. Sensitivity studies are reported, which show that both the effects of low gas mobility and improved permeability are required for a match.

The term "Cold Production" refers to the use of operating techniques and specialized pumping equipment to aggressively produce heavy oil reservoirs. This encourages the associated production of large quantities of the unconsolidated reservoir sand, creating a modified wellbore geometry that could include "wormholes", dilated zones, or possibly cavities. As well, produced oil in the form of an oil continuous foam resembling chocolate mousse, suggests a foamy solution gas drive occurs in situ. This leads to anomalously high oil productivity and recovery because free gas stays entrained in the foam, thereby sustaining reservoir pressure. In a recent paper(1), the mechanisms that lead to this increased productivity were outlined and the suitable reservoir types conducive to cold production techniques were identified. In this paper, these mechanistic concepts are extended to practical, intuitive modelling techniques that can be applied to existing "black oil" reservoir simulators by appropriate alterations to the input data. Importantly, these techniques have beenound to match actual cold production behaviour in applicable Western Canadian conventional heavy oil reservoirs. With a history matched model, these techniques can be used to extend the cold production scenario into the future, providing better estimates of ultimate recovery. As well, sensitivities to the process can be investigated, including exploring sensitivities to various reservoir and operating parameters (e.g., reservoir pressure, production rate strategies) and examining the impact of a preceding cold production primary depletion on subsequent secondary and tertiary recovery processes. Introduction In approximately the last ten years, many authors have written about the phenomena involved in producing heavy oil by solution gas drive. Their work has been inspired by field observations of cold production in some of the heavy oil reservoirs in Canada and enezuela, where unexpectedly high oil rates and recoveries, as well as low gas-oil ratios, have been attained. This work has included laboratory investigations of fluid and rock properties (including geomechanical studies of the so-called wormholingeffects), conceptual postulation of mechanisms in the context of actual field behaviour, as well as some attempt to mathematically capture and numerically model these mechanisms. Perhaps one of the first to set forth the mechanisms and possible mathematics was Smith(2) at Husky, who also appears to be one of the first investigators to note that the anomalous production enhancement must arise from a combination of geomechanical and fluid effects (i.e., results cannot be "excused as high permeability channels resulting from sand production"). These two categories of mechanisms"geomechanical effects and fluid effects?are the subject of the mechanisms proposed in the literature for explaining the cold productionperformance of heavy oil reservoirs. Geomechanical Effects Productivity of heavy oil wells experiencing cold production is typically much higher than would be expected"actual productivity exceeds radial Darcy flow predictions (using typical oil viscosities and air permeabilities) by factors of four to 10.

The unique problems associated with heavy oil production largely revolve around the issue of viscosity. Production technologies used to overcome the viscosity issue, such as steam injection and water flooding, increase produced water levels at heavy oil wells. Accurate knowledge and monitoring of any produced water is key to production optimization; however, accurate measurement of water content relies on a homogenous flow, and the high viscosity of heavy oils makes high flow velocities and thus, homogeneity, particularly difficult to achieve. While sampling standards acknowledge the need for a homogenous flow, no such standards currently exist for oil/water measurement. API MPMS Chapter 8.2 details the various combinations of velocity, pipe installation, and mixing devices required to achieve homogeneity for sampling and one can borrow from this standard for minimum requirements for oil/water measurement. However, mixing elements and piping configurations can create a pressure drop and are still subject to inconsistencies and complications from varying fluid velocities, densities, viscosities, etc., and none of the mixing elements are capable of creating a constant velocity. The addition of a circulation or measurement loop to the main pipeline creates a consistent environment and homogenous flow for optimized measurement conditions, regardless of varying fluid conditions. The loop utilizes a pump in line with a suction nozzle to extract a representative flow from the main pipeline for oil/water measurement and an injection nozzle to inject that flow back into the pipeline upstream of the suction nozzle. The size of the pump and mechanical design of the injector must be appropriate to increase velocity and create mixing sufficient enough to generate a homogenous flow in the portion of the main pipeline between the injection and suction nozzles. Homogeneity is maintained in the loop itself by a high velocity of 10–15 fps-well above API minimum requirements. An oil/water measurement device or OWD is placed at the pump outflow where flow conditions remain constant regardless of variations in the main pipeline.

Autonomous Inflow Control Devices (AICDs) are a relatively new technology with the potential to improve the production performance of horizontal wells. The devices control the inflow of reservoir fluid to equalise influx along the length of a horizontal well, and adjust the level of constraint depending on the fluid flowing such that water production is hindered and oil production is promoted. In order to assess the effectiveness of autonomous ICDs compared to passive ICDs, which apply a constant level of restriction, numerical simulations and sensitivity studies were conducted. A detailed model of the lower completion of a theoretical horizontal well was constructed using an Integrated Production Modelling (IPM) simulator. ICDs were represented using an Inline Programmable Element and equations to calculate the pressure drop of a range of different passive and autonomous ICDs were input. Simulations run on this model allowed the pressure drop across each ICD to be analysed, and the liquid rates at the heel and toe of the well to be compared, to assess how effective the ICDs are in promoting a balanced influx from the reservoir along the entire horizontal length of the well. Oil viscosity, heterogeneous permeability, and oil-water-contact levels were then varied to evaluate the behaviour of the ICDs in different scenarios. Analysis of the simulation results suggests that none of the tested ICDs are the best performers in every scenario. The Rate Controlled Production (RCP) Valve AICD is the most effective device in heavy oil wells and in wells with uneven oil-water-contacts. The EquiFlow AICD is the optimum performing devicein a reservoir with heterogeneous permeability, and the nozzle ICD is the most effective device in light oil wells. Comparative study of the behaviour of passive vs autonomous ICDs indicates that there is a difference in performance between these two types of ICDs. In some cases autonomous ICDs can provide significant benefits, where as in others the passive ICDs are just as effective.

The patented hydraulically regulated progressing cavity pump (HRPCP) has been tested previously in the oilfield, but its range of application is being expanded. The HRPCP can be used in any well where a PCP would be installed and provides added protection in cases where significant free gas may be present. It is as effective as a standard PCP in pumping high viscosity fluids or fluids with high solids content, or both. It retains its effectiveness as a pump even when no gas is present, although its primary benefit is the increase in PCP run-life when there is free gas present at the pump intake. The present study is to evaluate the performance of the HRPCP in new applications around the world. Previous publications on the HRPCP have looked at installations in Argentina, Venezuela, and Kuwait. There are now installations in coal seam gas (CSG) in Queensland, Australia, gassy oil wells in Colombia, and heavy oil wells in the Lloydminster area of Canada, and in wells in the newer operations in the Clearwater formation near Slave Lake in Alberta, Canada. In Canada in particular, there have been 27 installations in thirteen fields by six oil companies at the time this paper was prepared. In Colombia, the HRPCPs were installed in new wells that were expected to produce high gas volumes while still producing some sand. In the Australian CSG wells, operators wanted to land the pumps higher in the well to avoid solids problems, knowing that this would result in higher gas volume fraction at the pump intake, so the HRPCP was chosen. In the Canadian heavy oil areas, there can be a higher GOR in many wells than there was in the past, so the gas fraction at the pump intake can now be a larger factor in PCP run-life than in the past. In some of the Canadian wells, the performance data of the previous installation is available for a direct comparison. Overall, the run-life of the HRPCP has been excellent in comparison to either expectations or to the run-life of previous PCPs in the same wells or fields. In one example well, the previous PCP suffered a significant drop in efficiency (from 60% to 10%) after 90 days. The HRPCP that followed it has been running at 70% efficiency for over 180 days (and still going). In Colombia, the operator saw reduced load on the pump due to the "gas lift" effect from the gas going through the pump and up the tubing, while exceeding expectations for run-life.