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Provide a write up of 500 words on why some of the associated gas that is separated on the companys FPDSO - Nhyira - is flared, while a huge portion of the remainder is re-injected into the wells. Discuss the possible use of the remaining 10% of the separated gas. Explain the processes involved in the utilisation of the remaining 10% of the separated gas (1,000 words).
Discussions on why flaring is done
The popular image of offshore work often centers on a muddy drill floor, where wells are drilled to target then reservoirs of oil and gas below the surface. The top end of each production well sprouts a branching series of pipes, gauges and valves called 'Christmas tree. At this point, crude oil is a hot, frothy, corrosive, high pressure, fluid containing gas, water and sand.( Evenbase Recruitment Ltd,2013)
After separation, the crude oil is metered and pumped into the pipeline or stored until sent ashore by tanker. The gas separated from the oil may be used for fuel, or compressed and piped to shore or re-injected into the reservoir. Any gas that cannot be used is burnt in the platform's flare.( Evenbase Recruitment Ltd,2013). (Copyright 2013 Evenbase Recruitment Ltd, trading as OilCareers.com : All Rights Reserved http://www.oilcareers.com/content/career/FAQ.asp)
However, most of the separate gasses are flared due to pressure build up in vessels, such that if the pressure exceeds it set point the pressure relief valve releases the excess gas to flare and most of the time during the process, low pressure gasses are develop which cannot be compressed further so therefore there is a need to flare it. Since expelling these gasses into the environment is hazardous the flared gasses are burnt for it to become non-hazardous to the environment.
Moreover, flaring in the floating production, storage and offloading ( FPSO) and that of the floating production, drilling, storage and offloading (FPDSO) system as shown below.
(Topside Platform-Hull, 2013) (Topsides Platform-Hulls Conference and exhibition February 5-7, 2013. www.topside.com, Moody garden Covent).
Flaring in the FPDSO is carried out as shown below
Fig.1. Flare gas process with a recovery system (John Zink)
As shown above, the flare system consists of:
a vapor header that collects the flare gases from various sources
a knockout vessel
a liquid seal vessel
The flare itself.
The flare gas recovery unit connection is typically located between the knockout vessel and the liquid seal. Any liquids in the flare gas should be removed before introduction into the flare gas recovery unit. (John Zink, )
As the flare header pressure reaches the predetermined pressure control set point, a liquid ring compressor starts up and begins to compress the flare gas. The compressor uses an operating liquid, usually water, to perform the work of compression on the recovered gas. The operating liquid is cooled in a shell-and-tube heat exchanger, evaporative cooler or air-cooled heat exchanger to control compressor discharge temperature. (John Zink, )
The compressor discharges the gas into a three-phase separator that separates the operating liquid from the flare gas and then the condensed hydrocarbons from the operating liquid. Instead of venting process vent streams into the flare system, the compressed gases are made available to the operating plant's fuel gas supply or possibly as a process feedstock.
When all compressors are operating at full capacity and if the process vent flow rate continues to increase, flare gas will begin to pass through the liquid seal and flow to the flare stack and then these flared gasses are burnt to prevent it from get tern to the environment.(John Zink, ) (www.johnzink.com/products/flare-gas-recovery/process-diagram 1:37, 1/31/2013)
Discussions on the need for re-injection
To maintain the pressure in the reservoir water is often injected into the reservoir. The prime source of the injected water is seawater, but produced water could be reinjected as well. The description below describes a typical seawater injection system.
The seawater injected into the reservoir is either cold seawater directly from the seawater lift pumps or hot seawater used for cooling prior to flowing to the water injection system. The seawater is filtered to remove particles of the seawater with Coarse Filters to 80 microns. The Fine Filters downstream of the Coarse Filter will assure deep filtration down to 2-5 microns. The filtered seawater is deaearated, oxygen removal, in the Deaearator. Vacuum Pumps and Ejectors will create vacuum in the Deaerator and remove the majority of the oxygen. Typically a Deaerator will achieve 50 ppb residual oxygen content. A common specification for injection water is 10-20 ppb. This is achieved by injecting oxygen scavenger into the injection water.
The filtered and deaerated seawater can be injected in the reservoir by increasing the pressure through pumping. The Water Injection Booster Pump increases the pressure 5-8 barg to assure sufficient NPSH for the injection pumps. The Water Injection Pump increases the pressure to the required injection pressure, typically 200-300 barg. The injection water is then distributed to the subsea water injection wells. (http://www.bluewater.com/process.asp#5 , 2/4/2013,2:36am.)
Fig. 2 FPDSO/FPSO process with water injection (http://www.offshore-technology.com/projects/triton/ 2/4/2013, 2:15am)
However, the process as shown in fig.2. Are as follows:
The processing of the well fluids on an FPSO is primarily located at the topside. The topside is located 3.5 m above the tanker deck. The topside is divided into several modules that provide the required functionality. These modules are comprised of crude separation, gas compression, gas treatment, utilities, power generation, etc.
The well fluids (oil, produced water and gas) flow from the subsea wells and/or manifolds through flow lines, pipelines and risers to the FPSO. The well fluids enter the Turret Mooring System (TMS) and are transferred from the geostatical part of the TMS to the rotating part of the TMS through the swivels. From the swivels the well fluids flow into the crude separation unit, in this unit the well fluids are heated in the Production Heater to a suitable temperature for achieving the bulk oil and water separation as well as separating hydrocarbon gas from the liquids in the Production Separator.(http://www.bluewater.com/process.asp#5 , 2/4/2013,2:36am.)
Moreover, to maintain higher efficiency in the FPDSO/FPSO one well have to ensure that the following are achieved:
The recoverable amount of original or residual hydrocarbons in place in a reservoir, expressed as a percentage of total hydrocarbons in place.
The percentage of original oil in place displaced from a formation by a flooding fluid.
Adding new wells in an existing field within the original well patterns to accelerate recovery or to test recovery methods.
Enhanced oil recovery
One or more of a variety of processes that seek to improve recovery of hydrocarbon from a reservoir after the primary production phase.
Repressuring of an oil-field to maintain original pressure. The use of water flooding or natural gas recycling during primary recovery to provide additional formation pressure.
Improved oil recovery (IOR)
Any of various methods, chiefly reservoir drive mechanisms and enhanced recover techniques, designed to improve the flow of hydrocarbons from the reservoir to the wellbore or to recover more oil after the primary and secondary methods (water and gas floods) are uneconomic. (http://en.wikipedia.org/wiki/Shale_oil_extraction)
In conclusion, as discussed above water or gas injection in oil production is a process of injecting water or gas back into the oil reservoir through an injection tree mounted on a wellhead. The re-injected water displaces the oil from the reservoir and also maintains the reservoir fluid pressure so as to ensure a constant flow rate of hydrocarbons.
Discussions on the use of the remaining 10% of the gas
After the primary separation process(on the fpso or plate form) the water passes through several purification stages to ensure that particles that could cause plugging of the reservoir are eliminated. This process protects the permeability of the reservoir. The water is also deoxygenized(topreventcorrosion)
note: unused fluid is treated before it is dumped into the sea.
The infrastructure required to process the wet gas
Natural gas produced from underground reservoirs must be processed to remove water, impurities, and heavier hydrocarbons. The impurities are usually hydrogen sulfide and carbon dioxide. The heavier hydrocarbons or natural gas liquids (NGLs) are ethane (C2H6), propane (C3H8), butane (C4H10), and natural gasoline.
However, the infrastructure required to process the wet-gas are as shown in the schematic process below:
Fig.3. Natural Gas Processing - Schematics (simplified process flow diagram)
The raw natural gas feedstock from a gas well or a group of wells is cooled to lower the gas temperature to below its hydrocarbon dew point at the feedstock pressure and that condenses a good part of the gas condensate hydrocarbons. The feedstock mixture of gas, liquid condensate and water is then routed to a high pressure separator vessel where the water and the raw natural gas are separated and removed. The raw natural gas from the high pressure separator is sent to the main gas compressor.
The gas condensate from the high pressure separator flows through a throttling control valve to a low pressure separator. The reduction in pressure across the control valve causes the condensate to undergo a partial vaporization referred to as a flash vaporization. The raw natural gas from the low pressure separator is sent to a "booster" compressor which raises the gas pressure and sends it through a cooler and on to the main gas compressor. The main gas compressor raises the pressure of the gases from the high and low pressure separators to whatever pressure is required for the pipeline transportation of the gas to the raw natural gas processing plant. The main gas compressor discharge pressure will depend upon the distance to the raw natural gas processing plant and it may require that a multi-stage compressor be used.
At the raw natural gas processing plant, the gas will be dehydrated and acid gases and other impurities will be removed from the gas. Then, the ethane (C2), propane (C3), butanes (C4), and pentanes (C5)-plus higher molecular weight hydrocarbons referred to as C5+-will also be removed and recovered as byproducts.
The water removed from both the high and low pressure separators may need to be processed to remove hydrogen sulfide (H2S) before the water can be disposed of underground or reused in some fashion.
Some of the raw natural gas may be re-injected into the producing formation to help maintain the reservoir pressure, or for storage pending later installation of a pipeline.
(Natural gas processing, a page from the website of the Energy Information Administration)
The workings of a Floating Storage Regasification Unit
A floating storage and offloading unit (FSO) is a floating storage device, which is a simplified FPSO without the capability for oil or gas processing. Most FSOs are old single hull supertankers that have been converted. An example is Knock Nevis, ex Seawise Giant, was for long time world's largest ship, which had been converted to an FSO to be used offshore Qatar.
At the other end of the LNG logistics chain, where the natural gas is brought back to ambient temperature and pressure, ships may also be used as FSRUs. A LNG floating storage and regasification unit (FSRU) is a floating storage and regasification system, which receives liquefied natural gas (LNG) from offloading LNG carriers, and the onboard regasification system provides natural gas send-out through flexible risers and pipeline to shore. Mooring systems for FSO, FPSO & FSU units are available in market which allow the vessel to be moored on a ice sheet as shown below:
("The world's first LNG Floating Storage and Regasification conversion''). Skipsrevyen. Retrieved 2008-08-02)
Fig.4. Schematics of an FPSO and Drilling Platforms
One of the fastest growing shipping sectors at present is the dedicated fleet of specialist ships carrying liquefied natural gas, increasingly important as this fuel is one of the cleanest and greenest available. However an LNG ship carries her cargo in liquefied form at atmospheric pressure, but at an astonishing minus 162 degrees C, at which temperature it will be loaded, transported and pumped ashore into refrigerated storage tanks at the discharge port. Then, before the methane can be pumped into the gas grid, it must be warmed up to become gas again. This takes place at a regasification plant ashore. The refrigerated tanks and the regasification plant are expensive and elaborate components in a specialist LNG terminal. The cost of such a terminal is sometimes prohibitive, which is one reason that there are rather few of them, even though imported LNG is clearly an "up and coming" cargo.
Moreover the floating storage regasification unit is a "short cut" that will enable the fuel to come ashore in gaseous form to be pumped straight into the shore-side gas grid without expensive infrastructure. It can be of two distinct types, one an otherwise conventional LNG carrier with a regasification unit fitted on board, the other a converted LNG carrier which will take up a permanent mooring close to where the gas is required and which can accommodate the refrigerated cargoes delivered by other LNG vessels (.www.keppelshipyard.com, 2/5/2013, 11:52pm.)
In conclusion the Floating regasification allows prospective importers to gain fast and relatively cost efficient access to global LNG supply, this include:
the ability to fast track regasification access for new LNG importers
Lower upfront capital investment compared to onshore facilities
Can be relocated if demand is short-term and / or seasonal
Allows customers in new markets to gain confidence in LNG
Good solution for when availability of land is limite
(© Copyright 2000-2013 Teekay Corporation. All Rights Reserved,
a. The most active reservoir in terms of exploration and production activities
There are four reservoirs in terms of exploration and production, these are:
Tano Basin(between Ghana and Cote d'Ivoire )
Saltpong / central Basin
Keta / Accra basin ( between Ghana and Togo)
Onshore / Volta basin(between Volta Region, Eastern Region and Northern Region)
With the most active basin been that of the Tano Basin.
Discussion of the unitised field - Jubilee field.
The jubilee field, which consist of two major blocks that is, west cape three points WCTP block, under the operatorship of kosmos Energy, returned a historic finding in the mahogany 1 well in 2007 and followed by another discovery, in the adjoining deep water Tano block operated by Tullow oil .
However, for the purposes of smooth operation in the jubilee field between these two major companies a Unitisation and Unit Operating Agreement (UUOA) was signed among the partners in the WCTP block and Deepwater Tano block, on July 13, 2009, with the Ministry of Energy, the partners agreed to develop the two discoveries jointly to optimize resource recovery.
The unitized area, in 2011,being developed together as the Jubilee Field, straddles the two blocks and produce about 85,000 barrels of oil per day, against a projection of 120,000 barrels/day by the second half of that year, representing a shortfall of 35,000 b/d.As reported in the Business Analyst July 6, 2011 edition (See West Cape Three Points to Attract Better Terms below.) that the country was on the verge of improving on the terms of the WCTP block, as the exploration phase of the petroleum agreement covering that block came to an end on July 22, 2011.(business Analyst, 2012)
Kosmos Energy operates the WCTP Block with 30.875% interest, the same as Anadarko, with Tullow Ghana Limited having 22.896% interest, whilst GNPC increased its holdings from 10.0% to 12.5% on commerciality, with the EO Group having 3.5%,whilst Sabre Oil and Gas Holdings has 1.854% working interest.
Kosmos is also a partner with 18% interest in the Tullow Ghana Limited operated (49.95%) DT Block, which also has Anadarko WCTP (18%), GNPC (10%), and the Sabre Oil and Gas Holdings Limited (4.05%) as partners.(business Analyst, 2012)
Tullow Oil became the Unit Operator, with Kosmos Energy as Technical operator. The Jubilee field is currently producing crude oil at a little over 70,000 barrels/day and straddles the two WCTP and DT blocks. The field is expected to peak at 120,000 barrels per day by the end of the third quarter of this year.
In June 2007, the Mahogany-1 well, which was Kosmos' first exploration well within its WCTP block discovered oil in large commercial quantities. Two months later, in August, the Hyedua-1 well, drilled just across the block in Tullow Oil's Deepwater Tano block also struck oil in sizeable quantities. The two fields were unitized in 2008 for joint development as the Jubilee Field, after successful appraisals.(business Analyst, 2012)
The contract for the construction of the floating production, storage and offloading vessel Kwame Nkrumah MV 21 for the Jubilee Field was awarded in 2008 and arrived in June 2010. Technical Production commenced from the field started on November 28, 2010 and the Jubilee Field was officially commissioned for First Oil on December 15 of the same year.(The business Analyst, Accra - January 18,2012)
Operation of the West African Gas Pipeline Company
The West African Gas Pipeline (WAGPCo) is a 681 kilometer onshore and offshore pipeline with a diameter of 20inches and it's designed to carry natural gas from Nigeria's Escravos region of the Niger Delta area to Benin, Togo and Ghana. It is the first regional natural gas transmission system in sub-Saharan Africa.
The company has its headquarters in Accra, Ghana, with an office in Badagry, Nigeria, and field offices in Cotonou - Benin, Lome - Togo, Tema and Takoradi, both in Ghana. The West African Gas Pipeline Company (WAPCo) is in charge of both construction and operation of the pipeline. WAPCo is a limited liability company owned by Chevron West African Gas Pipeline Limited (36.9%); Nigerian National Petroleum Corporation (24.9%); Shell Overseas Holdings Limited (17.9%); and Takoradi Power Company Limited (16.3%), Societe Togolaise de Gaz (2%) and Societe BenGaz S.A. (2%).
In the year 1982, the Economic Community of West African States (ECOWAS) proposed the development of a natural gas pipeline throughout West Africa. In 1991, a feasibility report conducted by the World Bank on supplying Nigerian gas on West African markets deemed that the project was commercially viable. In September 1995, the governments of Nigeria, Benin, Togo and Ghana signed a Heads of State Agreement.
The feasibility study was carried out in 1999. On 11 August 1999, a Memorandum of Understanding was signed by participating countries in Cotonou. In February 2000, an Inter-Governmental Agreement was signed. The WAGP implementation agreement was signed in 2003.
Groundbreaking ceremony for the project was held at Sekondi-Takoradi, Ghana, on 3 December 2004. The construction started in 2005. The offshore pipeline was completed in December 2006. It was scheduled to start operating on 23 December 2007 but was delayed after leaks were detected in supply pipelines in Nigeria. The WAGP is expected to make a supply of 100 million standard cubic feet of natural gas per day upon completion of the project but currently its supply capacity is 40MSCF/day.
Fig. 5 Diagram showing the connection of the West African Gas Pipeline from Nigeria to Ghana, Benin and Togo (www.wagpa.org)
The operation of the WAPCo consist of a 35-mile onshore segment (where the gas exploration take place) of the pipeline in Nigeria provides a connection between the existing Escravos-Lagos Pipeline (EPL) and the newly built Lagos Beach Compression Station. The 354-mile offshore segment of the pipeline runs west from there, through the waters of Benin and Togo before ending at Takoradi in Ghana.
The gas from the main line (onshore) is delivered to the three countries through gas delivery laterals provided at Cotonou (Benin), Lome (Togo) and Tema (Ghana), with a diameter of the onshore pipeline is 0.76m and that of the offshore pipeline is 0.5m.(http://www.hydrocarbons-technology.com/projects/west-african-gas-pipeline)
Challenges that the company has been facing
Every company faces major challenges, even companies that are as successful as Tallow, Kosmos, WAPCo etc . Although they have an outstanding reputation, have won many awards, and even give back to their community, they are still facing challenges like any other companies. The most obvious challenge that WAPCo is dealing with is the current vandalisation of the sub-regional pipeline within the Togo waters remains unrepaired within the next four month may course the company a loss of $2.4 billion.
This was disclosed by the Managing Director of the company, Charles Adeniji, who told journalists during a media briefing on the damaged pipeline, that the incident had resulted in a daily loss of between $500,000 to $600,000 to the company.WAPCo's gas pipeline was breached in August, truncating supplies to Ghana's power plants, a development in which the company is uncertain when it would resume flow of gas from Nigeria to neigbouring African countries.(Clara,2013)
The pipeline suffered a set-back in October when it experienced a fatal accident during the re-commissioning of the Takoradi Regulating and Metering Station in Ghana.The pipeline was shut down in August last year after experiencing a loss of pressure around the Lome segment of the facility.(Clara,2013)
However, some of the setbacks that delayed the project were the compressor (mean the right sizes were not meet) at the Lagos Beach Compression in Nigeria. Also military, civil society activities and sabotages on the pipeline activities all contribute to the major challenges of WAPCo.