The invention relates to the production of crude oil, and in particular to the maximizing the recovery of stabilized crude oil from an oil and gas producing facility.
The current global situation of depleting crude oil reserves, escalating crude oil price, coupled with an increasing environmental awareness and legislation on the management of CO2 emissions requires more responsible development of hydrocarbon assets. To address these issues, operating companies are investigating and implementing strategies to enhance crude oil recovery by maximizing recovery of NGLs and minimizing flaring.
Raw natural gas comes from predominantly two types of wells: oil wells and gas wells. Natural gas that comes from oil wells is typically termed “associated gas”. This gas can exist separate from oil in the formation (free gas), or dissolved in the crude oil (dissolved gas). Natural gas from gas wells, in which there is little or no crude oil, is termed “non-associated gas”. Gas wells typically produce raw natural gas along with a semi-liquid hydrocarbon condensate. Whatever the source of the natural gas, once separated from the associated liquid it commonly exists in mixtures of predominantly methane and ethane and other hydrocarbons; principally propane, butane, and pentanes.
Natural gas coming directly from a well contains many natural gas liquids that are commonly removed. In most instances, natural gas liquids (NGL's which includes ethane, propane, butanes and pentanes) have a higher commercial value as separate products, and it is thus economical to remove them from the gas stream. The processes for removal of natural gas liquids are relatively complex requiring gas pretreatment facilities like CO2 removal systems and gas dehydration, NGL extraction processes like lean oil absorption or cryogenic expander processes, NGL processing and fractionation facilities like de-methanizer, de-ethanizer, de-propanizer, de-butanizer and butane splitter. In addition, pressurized storage and off-loading facilities are also required. This results in facilities, where NGL extraction and processing are undertaken, being very complex with significant safety issues and requires large real estate with significant capital investment. For these reasons these processes are generally built as centralized processing plants and are not considered particularly for offshore facilities and many onshore developments.
On many gas processing facilities, NGL recovery facilities are not installed due to economic reasons and the gas exported will contain significant quantities of C4+ components. C4+ components, particularly LPGs (C4's) are cumbersome to handle in many cases, as they predominantly cannot be stabilized with the light condensate stream and, cannot be spiked into the export gas stream due to export gas dew point limitations. As such, in many cases, these valuable hydrocarbon components that can neither be spiked into the export gas stream or the stabilized condensate stream are utilized within the site as fuel gas or flared.
Where pipeline gas export dew-point specifications are less stringent, many gas producers export significant quantities of C4+ components with the sales gas instead of recovering the NGLs. In this case, the revenue earned is solely from the heating value (BTU) of the gas which is significantly lower than what it would be worth as liquids.
While condensates produced with non-associated gas have generally limited capacity to absorb and retain LPG components within the stabilized condensate stream, crude oil if produced in parallel has significantly higher capacity to retain these LPG and tail end C5+ components as stabilized liquids.
There are growing concerns over greenhouse gas emissions and its impact on global warming. Currently, many oil producers are still flaring associated gas produced, which is a by-product of crude oil production. According to estimates made in year 2005 to 2009, some 14 to 16 bcf is flared daily in the world. Gas flaring also has a global impact on climate change by adding some 400 million tons of CO2 in annual emissions.
Apart from being flared associated gas is currently:
In addition, there are a number of new technologies that are being considered for the processing and utilization of the associated gas. These include mini LNG, Gas to Liquid (GTL), Compressed Natural Gas (CNG) and Gas to Solid processes.
The implementation of the above facilities to utilize associated gas requires significant capital investment which may not be economically feasible, particularly for marginal fields. In the past, one major contributor that discourages investment in gas processing facilities is the low price of gas compared to crude oil. The tendency is for producers to focus on crude oil production with associated gas being more of an undesirable by-product.
In recent years, with the escalation of crude oil prices, the value natural gas and in particular NGLs (C3+ components) have also increased in tandem with crude oil prices. However, with crude oil reserves depleting and field sizes getting smaller, economics are still not favourable for many developments to take-off without re-injecting or flaring the associated gas produced.
In addition, many marginal fields discovered are not developed as the recoverable reserves are not sufficient to make the development economically viable. Yet another scenario is early abandonment of a field due to declining production. Increasing the recovery of NGLs and/or crude oil will make many of these marginal fields viable and stretches production life of fields, thus facilitating more responsible utilization of oil reserves.
In a first aspect, the invention provides a method for the production of stabilized crude oil, the method comprising the steps of: providing a stream of crude oil; injecting steam into said stream and so stripping C3− from said stream; providing a gas stream; extracting C4+ from the gas stream, and so; producing a stream from the extracted C4+; co-mingling the stripped stream with the C4+ stream, and so; producing a stream of stabilized crude oil.
In a second aspect, the invention provides a system for the production of stabilized crude oil comprising: a steam injection station arranged to receive a stream of unstabilised crude oil, said station arranged to subject said stream to an injection of steam; said steam injection station including a first outflow to deliver a stripped stream of crude to a stabilizer and a second outflow to deliver a flow of gas to a condensation station; said condensation station arranged to condense the gas to produce a condensate, said station further including an outflow to direct the condensate to the stabilizer for comingling the condensate with the stripped stream of crude; wherein the stabilizer is arranged to outflow a stream of stabilized crude resulting from said comingled streams.
In a third aspect, the invention provides A system for stripping light components from a crude oil stream, comprising a crude stripping column for receiving the crude oil stream, said column arranged to receive steam for applying to the crude oil stream; a surge vessel for receiving the stripped crude stream and arranged to separate water from said stripped crude stream; wherein the surge vessel and crude stripping column are selectively coupled so as on de-coupling the crude oil stream is permitted to by-pass the crude stripping column and flow directly into the surge vessel.
Therefore, the invention provides a process and system that maximizes the absorption of
C4+ components into the stabilized crude stream.
The process involves three operating steps where the crude is first stripped of C3− components. Heavy components, such as C4+, that are in a gas stream are extracted through condensation of the hydrocarbons, which may be through use of a dew-point control system, said control system may further be coupled with a de-propanizer. Finally the crude stream and condensate streams are co-mingled, possibly under conditions that will ensure that the vapor pressure specifications of the product liquid stream are met.
The process configuration and controls may be such that irrespective of the amount or proportion of crude and condensate produced, the amount of C4+ components in the stabilized product stream is maximized and the amount of C3− components minimized.
This may yield increased stabilized liquid production compared to a conventional multi-stage separation process and improved stabilized crude quality.
An advantage of the recovery of this process includes the minimization of the amount of propane and lighter molecular weight components in the stabilized crude stream, which will enable larger quantities of C4+ components to be absorbed into the crude stream and thus improve stabilized crude recovery, among others, whilst maintaining the TVP/RVP specification of the stabilized crude.
It will be convenient to further describe the present invention with respect to the accompanying drawings that illustrate possible arrangements of the invention. Other arrangements of the invention are possible, and consequently the particularity of the accompanying drawings is not to be understood as superseding the generality of the preceding description of the invention.
The process according to the present invention may increase the recovery of oil by between 5 to 30% over conventional processes. This is achieved by using crude oil and/or condensates from production wells to absorb intermediate hydrocarbon components (C4+) from a natural gas stream whilst maintaining the stabilized crude product within its vapor pressure specifications (TVP/RVP). This also results in improved crude oil quality (increased API gravity, reduced viscosity) and reduction of greenhouse gas emissions by up to 50% depending on whether associated gas is flared and due to the use of leaner fuel gas.
The process according to the present invention may also reduce environmental emissions of hydrocarbon gases and safety issues due to vaporization of volatile hydrocarbon components (C1, C2 and C3) from stabilized crude in the storage tanks by minimizing these components in the stabilized crude.
The present invention may be applicable for both onshore and offshore installations. The present invention may also be suitable for facilities where it is not economically viable to install a gas plant with NGL or LPG extraction facilities.
1. Crude Stripping Section
The unstabilised crude 10 is stripped of propane and lower molecular weight components in a steam stripping column 15 using superheated steam and operated in the range of 0.5 barg to 5 barg. This operation step also strips out salts from the crude stream prior to the crude being routed to the electrostatic coalesce. Thus the process also carries out desalting of the crude.
2. Condensate Recovery Section
This section 25 of the process extracts C4+ components and condensates from the associated and/or non-associated gas streams 20 whilst expelling 30 lighter components from the condensate stream using a depropanizer column. NGLs from associated and non-associated gas stream 20, laden with C3+ components stripped from the crude stream, is extracted from the gas stream using either a conventional dew-point control system or membranes and the condensate is routed to a de-propanizer column to produce condensate 35 predominantly laden with C4+ components. Alternatively, condensate extracted from the condensate recovery section may be routed to the stripping column surge vessel. This may avoid the need for a flash vessel downstream. In this case the operating pressure and temperature of the fluid in the surge drum may be adjusted such that the crude/condensate mix existing the surge drum meets the TVP specifications. This may be achieved by adjusting the temperature of the condensate stream from the condensate recovery section using a cooler.
3. Crude and Condensate Mixing and Stabilization Section
Crude 37 from the Crude Stripping Section 15 and that is de-watered with an electrostatic coalesce and condensate 35 from the de-propanizer of the Condensate Recovery Section 25 are both routed to the Crude and Condensate Mixing and Stabilization Section 40. Here the crude and condensate are mixed, cooled and routed 45 to the Flash Vessel. The Flash Vessel is operated at a temperature and pressure such that the liquids produced are stabilized to meet the TVP/RVP specification of the product. To maximize stabilized liquid production, offgas produced from the flash vessel is maintained at a preset value by adjusting the reboiler temperature of the de-propanizer column. The reboiler temperature of the depropanizer column controls the amount of C3/C4 component split in the column bottoms product and the column overhead gas stream, thus ensuring that the amount of C4s in the condensate stream is maximized without generating significant flash gas when the crude and condensate are comingled.
This process configuration maximizes the recovery of stabilized crude and ensures that valuable liquids from the associated and non-associated gas streams are recovered as stabilized product suitable for storage in atmospheric tanks.
The process is particularly suitable for facilities that handle difficult crudes that includes crudes that are waxy, highly emulsifying, high salt content and/or with high asphaltene content. This is because the process is configured to operate the crude processing section at high temperature (above wax appearance temperature and above emulsion breaking temperature) and is stripped of its light ends when operating at high temperature, thus minimizing risk of asphaltene deposition at the high temperatures in the steam stripping column. In addition, steam stripping of the crude also functions to water wash the crude, thus diluting salt concentrations. This minimizes risk of scale and salt deposition in the system and significantly enhances the performance of the downstream electrostatic coalescer. Foaming tendencies of the crude is also minimized both due to the dilution effect of condensed steam on the salts and also due to the stripping action that reduces the light end content in the crude.
Whilst the Crude Stripping Section minimizes the C3− content in the crude stream, the Condensate Recovery Section maximizes the recovery C4+ components thus ensuring that the final crude and condensate that is mixed in the Crude and Condensate Mixing and Stabilization Section has maximum C4+ components and thus maximum stabilized liquid recovery within its TVP and RVP specification. As a reboiled column is only provided for the condensate depropanizer column at the Condensate Recovery Section, the heat duty and column size is minimized compared to the case when crude is routed to a stabilizer column. In addition, as condensates extracted are clean, issues associated with fouling of the reboiler tubes are avoided.
For crude that have high asphaltene content and which have a tendency for asphaltene deposition when mixed with condensates at high temperatures, the temperature at which the mixing occurs can be adjusted by appropriately pre-cooling the gas and condensate stream prior to mixing at the Crude and Condensate Mixing and Stabilization Section.
The present invention uses the ability of crude oil to absorb some of the C3 components and essentially all the C4+ components from the gas stream and to retain within the stabilized crude oil product these valuable NGL products. This results in increased stabilized crude oil recovery and improved quality of crude, namely, higher API gravity and reduced crude oil viscosity.
As demonstrated in
In the
In subsequent operations shown in the
The amount of superheated steam used is dependent on the composition of the crude and operating pressure of the column but is typically approximately 1 lb steam per gallon of crude feed to the stripping column. The number of theoretical trays used is in the range of 3 to 10 theoretical stages. The number of theoretical trays used is a trade-off between steam consumption requirements, compression power and column height to minimize the amount of C3− components in the stripped crude stream whilst the C4+ components are maximized. To avoid decomposition of the heavy ends of the crude, the temperature of the bulk crude at the bottom of the stripping column is typically maintained within approximately 100° C. The temperature of the steam supply should be such that localized decomposition of crude (when in contact with hot superheated steam) is minimized whilst high enough to provide sufficient heat and minimize steam consumption for stripping. Typically steam supply temperature is in the range of 120 to 180° C. and includes a superheat of approximately 30° C.
The process 50 selectively displaces the light (C3−) components in the crude whilst maintaining as much of the C4+ components within the crude stream. Nonetheless, the overall process is configured such that any C4+ components that are stripped out of the crude in this section are recovered from the gas stream in the dew-point control section 130 of the process. As such, the main objective of this section of the process is to strip as much of the C3− components from the crude stream. As a result, the vapor pressure of the crude is dropped to well below the TVP/RVP specification of the stabilized crude. The use of steam stripping (as opposed to heating the crude using a reboiler) minimizes the temperature rise of the crude during the stripping process, thus minimizing decomposition of the crude and preventing coking. It also avoids the need for a reboiler which for dirty and fouling crude with high asphaltene content, will cause scale and asphaltene deposition at the reboiler tubes.
In addition, the benefits of crude stripping include:
The steam stripping column can be a conventional column with trayed, structured, random packing or other internals suitable to promote vapor liquid contact. For a conventional column, a liquid hold-up boot is required to provide sufficient liquid residence time for vapor liquid separation and to provide adequate surge volume for the downstream pump.
Alternatively, the column 80 may be configured as shown in
When crude production begins to decline, crude from the downstream crude transfer pumps may be recycled to the stripping column to ensure that minimum column turndown is not exceeded.
Offgas from the crude stripping column, depending on the operating pressure is either comingled with offgas from the downstream Flash Vessel 110, is cooled and routed to the Flash Gas Compression Train 140. Alternatively, if the stripping column 80 is operated at a higher pressure than that of the Flash Vessel 110, the offgas from the stripping column may be cooled and routed to the inter-stage of the Flash Gas Compression train.
Hot stripped crude from the Stripping Column is routed to the Stripping Column Surge Vessel where 3 phase (gas, crude and water) separation is performed. Any gas separated is comingled with superheated stripping steam and routed to the Stripping Column. Crude is discharged from the vessel under level control via a pump to the electrostatic coalescer.
The process recovers C4+ components from the associated and non-associated gas streams. The condensates may be extracted from the gas stream by a dew-point control system using JT-Valve, turbo-expander, mechanical refrigeration, membranes or a combination. Liquids recovered from the dew-point control system 135 and possibly the compression train scrubbers are letdown in pressure and routed to de-propanizer column.
The reboiler temperature of the depropanizer 145 is set to maximize the recovery of C4+ components. The de-propanizer column 145 rejects into the overhead gas stream, most of the C3 and lower molecular weight components whilst the C4+ components are routed to the column bottoms. The TVP of the column bottoms is adjusted, such that, when the condensate comingles with the crude stream, the combined crude and condensate stream TVP/RVP (typically approximately 12 psia) specification is met. This is accomplished by adjusting the reboiler temperature set-point. A flash gas flow control signal from the Crude Condensate Mixing and Stabilization section of the process provide a cascade control set-point to reboiler temperature controller. This ensures that the recovery of stabilized liquid is always maximized irrespective of the actual flowrate of crude and associated gas (and thus condensate) or their flow ratios. The process is essentially configured such that the condensate is stabilized (in the depropanizer column 145) to a level that is just adequate that the TVP/RVP of the combined crude and condensate product stream meets the storage and export specification. The depropanizer column will ensure that light ends from the condensate stream are displaced into the offgas stream and heavier ends are routed to the column bottom stream.
The Depropanizer column 145 can be a conventional column with trayed, structured, random packing or other internals suitable to promote vapor liquid contact. For a conventional column, a liquid hold-up boot is required to provide sufficient liquid residence time for vapor liquid separation and to provide adequate surge volume for the downstream pump.
Crude that is stripped of C3− components in the Crude Stripping Section of the process is then routed to the electrostatic coalescer 100, if required, to dehydrate the crude to meet crude BS&W content. The steam stripping operation also functions to water wash the crude and thus enhances the operation of the electrostatic coalescer 100. The dewatered crude is then comingled with condensate from condensate de-propanizer. Alternatively, if dehydration of the condensate stream is required, mixing of the crude and condensate streams can be done upstream of the electrostatic coalescer 100. In this case, the condensate may need to be pre-cooled and the operating pressure of the electrostatic coalescer maintained such that vapor break-out will not occur within the electrostatic coalescer.
The mixed stream is then routed to the crude-crude heat exchanger 70 for heat recovery and then to a cooler 105 before the pressure is letdown typically to a pressure of approximately 0.5 to 1 barg. The operating pressure is such that there will be sufficient head for the liquid to overcome the downstream system pressure drop en-route to storage. The fluid is then routed to a flash vessel 110 for vapor liquid separation. The operating temperature of the flash vessel is set such that crude and condensate mix will be stabilized to the desired TVP/RVP specification. Typically, the temperature is set at approximately 60 to 70° C.
Offgas from the Flash Vessel is comingled with offgas from the stripping column, cooled and routed to the flash gas compression train. To maximize the recovery of stabilized liquid, the offgas rate from the Flash Vessel is always maintained at a pre-set value, typically at approximately 0.5 to 1 MMscfd. This is done by means of a cascade control loop, where the flow controller output of the offgas from the Flash Vessel is used as the control set point of the depropanizer reboiler temperature controller. This ensures that the amount of butanes (C4s) that is extracted from the condensates routed to the depropanizer column is maximized to the limit that can be handled by the mixed crude and condensate stream whilst meeting the TVP/RVP specification. This ensures that the recovery of stabilized liquid is always maximized irrespective of the actual flowrate of crude and associated gas (and thus condensate) or their flow ratios. The process is essentially configured such that the condensate is stabilized (in the depropanizer column) to a level that is just adequate that the TVP/RVP of the combined crude and condensate product stream meets the storage and export specification. Liquids from the Flash Vessel is then routed to a cooler 115 and sent to storage via a level control valve. Alternatively, the crude may be pumped to storage.
The process of the present invention has application in production facilities where crude and gas are produced simultaneously and where it is not economical to install conventional NGL extraction facilities. This includes onshore and offshore facilities that simultaneously produce and process crude with associated and non-associated gas. The case study in the following sub-section demonstrates how the process of the present invention can be used on facilities that produce and process non-associated gas and crude in parallel.
A case study is carried out for a gas well stream of 160 MMscfd of non-associated gas and 16,000 bpd of condensate; another feed from oil well of 21,000 bpd of crude oil and 11 MMscfd associated gas. Four different processing facilities are considered, they are:
A LPG facility designed for a nominal capacity of 170 MMscfd of export gas, 10,000 bpd of LPG and 34,000 bpd of crude oil.
Condensate rich in LPG components will be extracted at the hydrocarbon dew point control unit 225. The condensate is then routed to the LPG fractionation unit 255. The LPG fractionation unit consist de-ethanizer and debutanizer columns 255 to produce mixed LPG and stabilized condensate products. The stabilized condensate will mix with stabilized crude oil and send to oil storage tank whereas the LPG 260 will be stored in pressurized LPG bullets or refrigerated tanks.
Considering the initial year of production, the following tabulation gives the material balance of pertinent streams for the process depicted in the figure above.
A multi stage separation is a more commonly used process configuration for offshore facilities due to its simplicity and as traditionally the industry focus has not been to enhance recovery of stabilized liquid and reduce environmental emissions at the expense of capital expenditure (CAPEX) and facility complexity. It comprises several stage of separation and heating to separate water and gas and in the process stabilizes the crude oil to the specified TVP specification. Commonly, flash gas compression will be installed to recovery vapor from the liquid separation train.
This process configuration, shown in
Considering the same inlet feed stream, the following tabulation gives the material balance of pertinent streams for the process depicted in the figure above.
Table #5 gives the comparison in terms of product recovery and properties of the product stream for the above four process configurations considered.
Among all the four processes considered, the system of the present invention recovered the most amount of stabilized crude, in the range of an incremental production of 460 to 2220 bpd compared to the other 3 processes with improved stabilized crude properties (lowest RVP/TVP, highest crude API gravity and lowest crude viscosity).
(1)Total heating duty included 8000 kg/h of superheated steam for stripping.
(2)Fuel gas consumption calculation based on 30% thermal efficiency of power gas turbine, 80% thermal efficiency of boiler and 5 MW power load of miscellaneous.
Based on the above tabulation the following conclusions are drawn:
1. The 3 stage separation process gives the lowest stabilized liquid product recovery among all the cases considered. A significant quantity of the C4+ components end up in the export gas stream which has significantly lower economic value than if exported as stabilized liquid. This process configuration, however, is the most widely used for offshore applications due to its simplicity and low utility requirements.
2. The addition of a dew-point control system with a condensate stabilizer only marginally improves the recovery of stabilized liquids over the more conventional 3 stage separation system. This indicates that it is not economically justified to invest in the incremental CAPEX associated with the additional dew-point control system and condensate stabilizer column which is why the majority of offshore facilities do not have such systems.
3. With LPG recovery, the incremental crude recovery is significant, approximately 1,760 bpd compared to a multi-stage separation system. In addition, approximately 9200 bpd of mixed LPG is also produced. There appears to be significant merits to installing LPG recovery facilities for this case study. However with LPG recovery, both CAPEX and OPEX are significantly increased. For offshore facilities apart from the incremental CAPEX associated with the LPG extraction and fractionation facilities, dedicated LPG storage and offloading facilities, usually provided by dedicated FSOs, are also required. OPEX includes additional manning for the LPG recovery and fractionation facilities, LPG storage FSO and dedicated shuttle tankers for LPG transport. In addition, LPG storage and offloading facilities offshore significantly increases the facility complexity, risk and HSE (Health, Safety and Environment) profile of the facility. For these reasons these facilities are seldom installed offshore unless in few cases where there is significant economic drivers for LPG storage and recovery.
4. Compared to the multi-stage (3 stage) separation process (which is predominantly used in offshore facilities), the results from the process of the present invention in an incremental stabilized liquid production of approximately 2,220 bpd. The system also results in higher stabilized crude recovery than the LPG recovery system although it does not produce a separate mixed LPG product stream. However, much of the C4 components are instead absorbed into the stabilized crude stream. Compared to the LPG extraction process, this embodiment of the present invention is significantly less complex and does not require LPG storage and offloading facilities.
It is noted that significant quantities of light component like C2-, C3 components are stripped from the stabilized oil in the present process.
A feature of the crude stripping column system of
In
Thus the main advantages of the column configuration according to the present invention, and as depicted in the embodiment of
1. The system availability remains high and the introduction of the column does not impact the availability of the system compared to a multistage separation system.
2. The column height is significantly reduced as the liquid hold-up requirements are now housed in a separate vessel. This is particularly beneficial for floating facilities where tall columns can impair its performance.
The performance of C4+ recovery only improves marginally (approximately 87.5% recovery of C4+ components) with the addition of a dew-point control system and a condensate stabilizer column as reflected in
It follows that the system and process of the present invention introduces a process configuration which may increase stabilised liquid yield from an oil and gas processing facility by as much as 30% more than that achievable using a conventional and widely used multistage separation process.
Advantages of the present invention may include:
Number | Date | Country | Kind |
---|---|---|---|
PI 2011001234 | Mar 2011 | MY | national |
Filing Document | Filing Date | Country | Kind | 371c Date |
---|---|---|---|---|
PCT/IB12/00505 | 3/16/2012 | WO | 00 | 9/13/2013 |