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.
Sand production is considered one of the major problems that would affect the economical value of any EOR project. The produced sand will start to accumulate in the wellbore till it kills the Well. This is done by increasing the pressure drop (both frictional and hydrostatic) in the borehole to a point where no more fluid can be produced. It can also exhibit a mechanical damage to the pipes, chokes, surface facility lines and would require continues cleaning.
There are several sand control equipment that can be installed whether in the wellbore or in the formation itself. However, these sand control equipment not only add a cost element to the whole project, but also most of them reduce the Productivity Index of the well. Consequently more wells need to be drilled in order to compensate the production loss due to the installation of sand control equipment.
This paper examines the effect of using Sucker Rod Pump (SRP) and All Metal Progressive Cavity Pump (AMPCP) on the sand production. Both pumps can handle solids to some degree, however, the mechanism of each pump will affect the building of sand arch and thus will impact the amount of sand volume produced.
By comparing the sand production profiles of two vertical wells under Cyclic Steam Stimulation (CSS) completed in the same zone, it was found that the use of AMPCP can help reduce sand production significantly over the SRP. This is attributed to the difference in working mechanisms of both pumps. In AMPCP, the fluid is being pumped by a smooth movement, while in SRP, the upstroke and downstroke movement of the pump have an effect similar to the plunger, which adversely impact the sand arch building. As a result, SRP has a higher tendency to produce more sand compared to that of AMPCP.
Hundreds of wells have been drilled vertically in order to achieve the target production of the Shaly-sand reservoir. Due to the shallowness of the reservoir at depth of around 600’ and the unconsolidated nature of sandstone, sand production soon showed its hindrance potential in the development of the field. Several attempts were made to control sand production, such as using different perforation charges with different phasing and sand screens. The application of sand screens was in efficient as they were plugged within 2-3 weeks of production. They would require a cleaning operation to resume the production and such operation proved to be very costly.
Since many wells were drilled for the development of the Shaly-sand oil field, simply buying sand control equipment for this large number of wells will result in the project being un-economic. So another way of controlling the sand production had to be evaluated to implement a reasonable sand production technique with better economics.
Progressive Cavity Pumps (PCP) were used in the cold pilots that were conducted in the Shaly-sand oil field here in Kuwait, but due to the nature of CSS operation, AMPCP pumps were needed to handle the heat of the injected steam and the heat of the produced fluid. The difference between PCP and the AMPCP pumps is that the stator is made of rubber in the PCP pump while it is made of metal in AMPCP, which tolerates high temperatures of the CSS operation. Beyond this point, they share the same components and they work in the same mechanism. Another advantage of the AMPCP is that steam injection can be done directly while the pump is in the well, by simply unscrewing the rotor out of the stator. Once the steam injection is finished, the rotor is screwed back in the stator and the pump can be started.
Sanyal, Tirtharenu (Kuwait Oil Company) | Al-Hamad, Khairyah (KOC) | Jain, Anil Kumar (KOC) | Al-Haddad, Ali Abbas (KISR) | Kholosy, Sohib (KISR) | Ali, Mohammad A.J. (Kuwait Inst. Scientific Rsch.) | Abu Sennah, Heba Farag (Kuwait Oil Company)
Improved oil recovery for heavy oil reservoirs is becoming a new research study for Kuwaiti reservoirs. There are two mechanisms for improved oil recovery by thermal methods. The first method is to heat the oil to higher temperatures, and thereby, decrease its viscosity for improved mobility. The second mechanism is similar to water flooding, in which oil is displaced to the production wells. While more steam is needed for this method than for the cyclic method, it is typically more effective at recovering a larger portion of the oil.
Steam injection heats up the oil and reduce its viscosity for better mobility and higher sweep efficiency. During this process, the velocity of the moving oil increases with lower viscosity oil; and thus, the heated zone around the injection well will have high velocity. The increase of velocity in an unconsolidated formation is usually accompanied with sand movement in the reservoir creating a potential problem.
The objective of this study was to understand the effect of flowrate and viscosity on sand production in heavy oil reservoir that is subjected for thermal recovery process. The results would be useful for designing completion under steam injection where the viscosity of the oil is expected to change due to thermal operations.
A total of 21 representative core samples were selected from different wells in Kuwait. A reservoir condition core flooding system was used to flow oil into the core plugs and to examine sand production. Initially, the baseline liquid permeability was measured with low viscosity oil and low flowrate. Then, the flowrate was increased gradually and monitored to establish the value for sand movement for each plug sample. At the end of the test, the produced oil containing sand was filtered for sand content.
The result showed that sand production increased with higher viscosity oil and high flowrate. However, sand compaction at the injection face of the cores was more significant than sand production. In addition, high confining pressure contributes to additional sand production. The average critical velocity was estimated ranged from 18 to 257 ft/day for the 0.74 cp oil, 2 to 121 ft/day for the 16 cp oil, and 1 to 26 ft/day for the 684 cp oil.
Cold production as a new primary production process can be used successfully in heavy oil unconsolidated sandstones. Ideal reservoirs are 5-15 m thick uncemented sands with high saturations of <20 API oils with gas in solution without free water or gas zones. However, application of Cold Production to many other cases in other parts of the world must be investigated. Strategies to initiate sand production involve aggressive perforation and swabbing measures. Keeping sand production stable after initiation requires pumps to cope with large initial sand ratios in a foamy oil form for several weeks, and smaller amounts of sand and foamy fluid continuously for many months. Restoring stable sand production after blockage is currently an "art", and various workover methods are used: better controlled work-over approaches and new technologies are needed. Sand and "gorp" separation from oil at surface is necessary, economic and environmentally sound disposal of these materials probably involves re-injection into depleted reservoirs.
Cold Production has become an economic mainstay of heavy oil production strategies for companies in Alberta and Saskatchewan. Applications will grow in Canada and elsewhere, as the applicability limits seem relatively broad. It will continue to be a dynamic emergent technology for heavy oil because:
-Without sand co-production, heavy oil rates are usually too low to be economical, particularly in shallow, low-pressure unconsolidated sandstones.
-With sand production, cheap, small diameter vertical or inclined wells can maintain sustained rates of 5-15 m3, often for many years.
-Without sand production, perhaps 0-3% OOIP can be recovered; lower values are for l0 API oil, larger values for l4-16 API oil.
-With sanding, up to 5-12% OOIP is recoverable.
-Proper completions, workover, and sand management techniques have led to reduced production costs; costs will continue to decline as better approaches are developed.