<a href="http://youngpetro.org/2013/03/06/how-is-it-possible-to-produce-oil-from-sand/"><b>How is it possible to produce oil from sand?</b></a> <a href="http://youngpetro.org/2011/10/09/people-engineers-and-spe-members/"><b>People, Engineers and SPE Members</b></a> <a href="http://youngpetro.org/2012/12/19/if-i-were-a-prime-minister/"><b>If I Were a Prime Minister…</b></a> <a href="http://youngpetro.org/2012/12/26/polish-shales-delayed/"><b>Polish shales delayed?</b></a> <a href="http://youngpetro.org/2013/01/11/russia-continues-the-policy-of-states-companies-monopoly/"><b>Russia continues the policy of state companies’ monopoly</b></a>
 

New risky investment possibilities after OPEC deal.

18 December, 2016 News No comments
New risky investment possibilities after OPEC deal.

Two years of constant falls in oil industry were the main factor why OPEC members decided to cut production rate. After big spending cuts in 2015 and 2016 price per barrel is now above $50 and in economic forecast it should rise. Time has come for unaffiliated countries to think about making new investments until oil is still climbing up the ladder.

Although oil price is still low, Patric Pouyanne – chief executive officer of Total SA has warned that constant investments cuts can end up with oil-supply shortfall in next few years. Referring to this, they will consider whether to start developing expensive new projects.

Many influential people say, there’s no looming supply gap, and this is why companies remain conservative, cutting spending in order to boost cash flow. In the last two years many companies have focused on expanding existing facilities, not creating new ones. Now because industry is so hard to sound out, it’s just like skating on thin ice – no one knows how long will OPEC deal be respected. All investors know it and after two difficult years they don’t want to risk any more. Although who will risk now can be really successful in the end.

Just before crisis in oil industry Total made major investments in new projects which had caused huge headache for this company in 2015 and 2016. Now Total is preparing to plan their capital spending in 2017, including development of the Libra deep-water field off Brazil, an onshore project in Uganda and second phase of the Zinia offshore field in Angola. Pouyanne said, that Libra and Zinia phase two could be extremely profitable with oil at $50.

Analytics claim that actual oil price increase would be short term rise, rather than long term one. This however does not change companies investment directions. Total is reducing capital expenditure to a range of $15 billion to $17 billion a year from 2017 to 2020, compared with $18 billion this year and a peak of $28 billion in 2013. Investing at this time in oil industry seems to be really hard thing to do wisely. As Guillaume Chaloin said: “Exploration at $40 per barrel is more complicated than at $100”.

Read more:
https://www.bloomberg.com/news/articles/2016-12-16/opec-deal-tests-oil-majors-appetite-for-risk-and-reward-iwr14hrb

LNG Croatia – to be or not to be?

15 December, 2016 News No comments
LNG Croatia – to be or not to be?

According to the latest Annual report (World Energy Outlook 2016) published by International Energy Agency few days ago, rise in global energy demand for 30% is expected to happen up to 2040. However, it seems that gradual changes are about to happen in the share of a modern fuels in global energy mix. Although fossil fuels demand is expected to decline in a coming decades, slope of its’ increase in global energy mix is somewhat smaller than that from renewable and nuclear energy sources. Among all fossil fuels, natural gas is by far the best option when it comes to meeting the goals from Paris Agreement. In comparison to oil and coal, natural gas emits significantly lower amounts of CO2 when burning, therefore being more ecologically acceptable. Therefore, only natural gas sees an increase in consumption relative to today’s needs.

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Figure 1: Position of planned LNG regasification unit on Island of Krk (www.google.hr)

Implications stated in a previous paragraph show free space for development of new projects related to natural gas. One of them is a broader development of worldwide LNG (Liquefied Natural Gas) projects. LNG terminals, either liquefaction or regasification, unlock the access to more remote sources of natural gas, being independent on existing pipeline grid and geopolitical issues associated

to it. Although European energy demand is expected to decline due to energy efficiency measures, the level of gas demand is likely to remain coupled to the economic activity. To ensure future security of gas supply, the European Union should definitely improve infrastructure, include new supply routes and LNG terminals to diversify dependence on a few suppliers.

Construction of LNG terminal, specifically regasification unit, in Croatia is not a new story. What is more, it has been a subject of many debates for a few decades. Position of the planned on-shore LNG terminal was Cape Zaglav on the Island of Krk in the Adriatic Sea with 6 bcm/y capacity. Geographical position of the planned terminal is promising because of specific position of Croatia on the European map, allowing supply for both south-eastern and central Europe. Sea depths at the location of the terminal allow docking of all LNG transportation vessels. One specific feature of the Adriatic Sea is that it penetrates in the hearth of Europe, therefore positioning itself among the fast and secure supply hub of goods for European countries (Figure 1).

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Figure 2: Animated view on planned on-shore LNG regasification unit in Croatia (www.zavod.pgz.hr)

After the property and legal issues, without clear defining of financial model and strategic partners, Croatian government made a decision on construction of the on-shore terminal. In the same time, debate on much cheaper, faster and adoptable solution came up, as to be floating regasification terminal for LNG (Floating Storage Regasification Unit). The time of construction was reported to be much smaller, less time consuming, option to be cheaper and adoptable to market needs in terms of additional capacity installation. Another problem was to convince investors in profitability of the project since the gas consumption was continuously declining, both in Europe and Croatia, due to new technical advancements and energy efficiency measures. Today, new tender on preparing project documentation and special license issuing has finished, all of that for FSRU unit.

The importance of the construction of the LNG terminal in Croatia is in security of supply of Croatia and Europe, diversification of European supply corridors, connection with LNG terminal in Swinoujscie in Poland forming energy corridor north-south and strengthening Croatian energy position in the European natural gas market.

Direction of project development is known. Government brought a decision on construction of off-shore storage and regasification unit with the primary stage capacity of approximately 2 bcm/y which would satisfy Croatian gas demand and possible export capacities. Remaining questions rise up as who will be investors in the project, which markets will be supplied with this gas and from which locations and under which contracts. Croatia and Europe would definitely benefit from the construction of LNG terminal in Croatia but it is now the question of time when it will be realized since major number of regasification units in Europe are currently operating significantly under capacity. Hopefully, project will not only be actualized in situations of gas crisis in Europe as it was the case so far.

References:

1) World Energy Outlook 2016: Executive Summary; International Energy Agency, 2016

2) Adria LNG, 2008: Liquefied Natural Gas, Informative Brochure, Zagreb, Croatia

3) Gas Infrastructure Europe (www.gie.eu), April 2015

4) Long Term Outlook for Gas to 2035, Eurogas Brochure (www.eurogas.org)

5) D. Pavlovic, M. Jovicic: Projekt koji će učvrstiti geoenergetski položaj Hrvatske, EGE 1/2016, Energetika Marketing d.o.o. Zagreb, Croatia

by Ivan Bosnjak

Weather impact on natural gas and LNG industry.

11 December, 2016 News No comments
Weather impact on natural gas and LNG industry.

There are several factors which can impact the LNG industry, however, there is one which is completely independent from human actions. The nature of liquefied natural gas extraction and transport make weather conditions a serious factor which could affect the seasonality of LNG supply and largely affect the prices.

Due to the nature of LNG liquefaction process it is largely dependent on temperature variations. Output is much higher at cooler temperatures because the procedure requires the gas to be cooled down to approximately −260 °F. All the complexity of this process results in strong dependency of the LNG output on ambient temperature variations. Even as little as 1 ºC change can potentially impact the output – we read form Wood Mackenzie’s report. (Wood Mackenzie, 2016)

Most of the liquefaction plants were built in hot and stable temperature areas, hence, the LNG output has been consistent as well. However, recent projects show that there will be a significant shift towards more temperature unstable regions. “Around 200 mmtpa of capacity is currently under construction or proposed in areas with more than 10°C annual temperature variation, including the US Gulf Coast and Australia.” – says Lucy Cullen, Wood Mackenzie’s Senior Research Analyst.

The chart provided by Wood Mackenzie, perfectly shows how the LNG plants are distributed per temperature variations:

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Moreover, weather conditions may affect the LNG pricing in other ways. It is worth mentioning a case study from years 2005 and 2006 when hurricanes were responsible of a 4% plunge in US natural gas production. Such events should not be a significant problem during summer periods when the demand for natural gas is usually low. Problem may arise when increased demand during winter periods clashes with severe weather conditions. This may result in a situation when supply cannot meet demand on time, therefore a price increase is most likely. The difficulty of predicting the consequences of weather change means storage gas supplies may not always cushion the unexpected turbulences.

It is worth to point out that extremely cold conditions can affect the machinery that is used at drilling and extraction sites. Below certain temperatures additional heating equipment is required to protect hydraulics from freezing. Snowfall may slow down most of the machine movements making the production less effective and more expensive than under normal conditions. Therefore, it may lead to decreased supply and higher gas prices.

On the other hand, as natural gas has significant share in electricity production, it can be affected by abnormalities during summer season as well. If warmer than normal temperatures occur, then electricity demand for air cooling increases. This may lead to natural gas and LNG prices increase as well.

To sum up, natural gas and LNG industry must be considered as largely dependent on weather conditions, therefore, increased seasonality of gas supply is most likely imminent.

by Alex Zakrzewski

References:

https://www.woodmac.com/analysis/lng-seasonality

http://www.eia.gov/energyexplained/index.cfm?page=natural_gas_factors_affecting_prices

BP Mad Dog Phase 2 approval

BP Mad Dog Phase 2 approval

Recently BP has sanctioned the Mad Dog Phase 2. The project is intended to extend the capacity of production from Mad Dog Oil Field in Gulf of Mexico by adding a second floating production platform.

The new platform will have the capacity to produce up to 140,000 gross barrels of crude oil per day from up to 14 production wells. The existing, spar type, Mad Dog platform has capacity to produce 80,000 gross barrels of crude oil operated at a water depth of 4,500 ft, located about 190 miles south of New Orleans. It started production from that field in 2005.

The Mad Dog Oil Field was discovered by BP in 1998. In 2011 the appraisal drilling proved that the reservoir contains more than 4 billion barrels of oil equivalent. Another platform was needed on the field.

In 2013 the design of new platform was too expensive and complex to be realized, the cost of the project amounted to $21 billion. Since then, the BP with co-owners (BHP Billiton and Chevron) has worked on simplification and standardization of the previous platform design. Due to this action the final cost of project is reduced by 60% to $9 billion.
“This announcement shows that big deepwater projects can still be economic in a low price environment in the U.S. if they are designed in a smart and cost-effective way,” said Bob Dudley, BP Group Chief Executive.

Production of the new floating production platform is scheduled to begin in 2021. The new platform will be similar to BP’s Atlantis Platform, said BP spokesperson Jason Ryan.

Read more:
http://www.bp.com/en/global/corporate/press/press-releases/bp-approves-mad-dog-phase-2-project-in-the-deepwater-gulf-of-mexico.html

OPEC Agrees to Cut Production

OPEC Agrees to Cut Production

After eight years of unregulated production amount and two years of oil prices crisis OPEC shows it is not dead and finally will reduce output by about 1.2 million barrels a day by January. Consensus reached on Wednesday in Vienna may reverse the situation of the industry.

Read more

Underground Gas Storage

Underground Gas Storage

   Natural gas is a seasonal fuel – demand for it is usually higher during the winter. The process of exploitation, production, and transportation of natural gas takes time, and it is not always needed right away. The solution for this issues is underground gas storage. It is also used for:

– balancing the flow in pipeline systems,

– insuring against any unforeseen accidents,

– market speculation – producers and marketers use gas storage as a speculative tool, storing gas when they believe that prices will increase in the future and then selling it when it does reach those levels,

– maintaining contractual balance – shippers use stored gas to maintain the volume they deliver to the pipeline system and the volume they withdraw,

and other secondary purposes.

   Natural gas is most commonly held in inventory underground under pressure in three types of facilities. These underground facilities are depleted reservoirs in oil or natural gas fields, aquifers, and salt cavern formations. Natural gas is also stored in liquid or gaseous form in above–ground tanks.  This is the most expensive of all storage options, but this solution is applicable when it is impossible to build other storage facilities near large consumers. Two important characteristics of an underground storage reservoir are its capacity to hold natural gas for future use and the rate at which gas inventory can be withdrawn – called its deliverability rate.

bez-tytulu

Depleted gas reservoir

They are the reservoir formations of natural gas fields that have produced all their economically recoverable gas. The depleted reservoir formation is readily capable of holding injected natural gas. Using such a facility is economically attractive because it allows the re-use, with suitable modification, of the extraction and distribution infrastructure remaining from the productive life of the gas field which reduces the start-up costs. Depleted reservoirs are also attractive because their geological and physical characteristics have already been studied by geologists and petroleum engineers and are usually well known. Consequently, they are the cheapest and easiest to develop, operate, and maintain of the three types of underground storage.

Aquifer reservoir

An aquifer is suitable for gas storage if the water-bearing sedimentary rock formation is overlaid with an impermeable cap rock. Although the geology of aquifers is similar to depleted production fields, their use for natural gas storage usually requires more base (cushion) gas and allows less flexibility in injecting and withdrawing. These types of storage facilities are usually used only in areas where there are no nearby depleted reservoirs. They are the least desirable and most expensive type of natural gas storage facility.

Salt formation

Underground salt formations are well suited to natural gas storage. Once formed, they allow little injected natural gas to escape from the formation unless specifically extracted. The walls of a salt cavern also have the structural strength of steel, which makes it very resilient against reservoir degradation over the life of the storage facility. Salt caverns provide very high withdrawal and injection rates relative to their working gas capacity.

How it works

Pumping gas is about injecting it in an artificial gas field using the parameters, specified by the process design. Gas is routed from a trunk gas pipeline to a site for removing solids, then to a gas metering station, and then to a compressor shop, where it is compressed and supplied to gas distribution stations (GDS) via headers. At a GDS, the general gas flow is divided in process lines, to which well loops are connected. Hook-up of process lines allows to measure productivity, temperature, and pressure of gas during an injection for each well.

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Back into the pipe

Extraction of gas from an underground storage facility is almost the same technological process as extraction from gas fields, but there is an essential difference: all active (commercial) gas is extracted within the period from 60 to 180 days. Flowing through the loops, it is received at gas-collecting stations, where it is gathered in a gas-collecting header. From there, gas is supplied to a separation site for the separation of produced water and solids, and then it is routed to a cleaning and drying site. Cleaned and dried gas is routed to the trunk gas pipelines.

gazprominfo.com/articles/gas-storage/

naturalgas.org/naturalgas/storage/

en.wikipedia.org/wiki/Natural_gas_storage

eia.gov/naturalgas/storage/basics/

Oil Prices are above 50$ a barrel after OPEC deal

Oil Prices are above 50$ a barrel after OPEC deal

Agreement to cut production between OPEC members was a suprise in oil sector. It caused price rise of black gold, but will it last for long?
Enthusiasm for the proposed deal finally cooled down and after a while and turned into wary skepticism. Lack of faith in this deal is quiet understandable. Deal is full of exemptions and conditional allowances. Ground of agreement rests on good will of Saudi Arabia. OPEC leader wants to pull the other members behind it in a fight to rescue prices from further stagnation. The cut is also evidence of the changing conditions within Saudi Arabia itself, which after a two-year strategy of maximized production is at a cross-roads, financial stress and general instability.

The goal of the cut is to bring the OPEC production level from 33.24 mln bpd (level at the time of the meeting) to a level between 32.5/33 mln bpd. This agreement is an important sign of changing priorities within Saudi government. There are some politicians in UAE that hope to see their country in other field than oil sector and begin more diversified economy.

The Saudi commitment to cut production is shared by only ten other members of the organization: there are several important exceptions that will, in effect, render the cuts largely symbolic, at least as far as the supply-demand balance is concerned.

Nigeria has been allowed to continue pumping, as it deals with violence in the Niger River Delta. Libya is also exempt, as its oil industry slowly finds its feet amidst civil war. Questions linger over how Iraq, which has enjoyed freedom to pump what it wants since 1991, will be brought back into an OPEC system of production management. Iraq’s energy minister has acted defiantly, arguing that OPEC figures under-estimate Iraq’s current production levels. This indicates that Iraq, in the middle of its on-going struggle with ISIS, will fight tooth and nail for its existing market share, as well as the freedom to continue pumping what it wants. Russia also will not participate in any cuts and there is huge chance that production cut but OPEC members will be replaced by non-OPEC countries.

To sum up these cuts are about moving the market and sending a message of unity and puropse. Even slight cut of 240,000 barrels per day will show us that OPEC is prepared to influence prices. They lead us to political strategy of Saudi Arabia and changing balance of strength in structures of OPEC. After the first rise in Oil price let’s wait for the further effects of this deal.

opec-logo

 

Baker Hughes Rig Counts

11 September, 2016 News No comments
Baker Hughes Rig Counts

   You may didn’t know that there is something like Baker Hughes Rig Counts. They are counts of the number of drilling rigs actively exploring for or developing oil or natural gas in the U.S., Canada and international markets. They tend to correlate with oil and gas prices. It is an important business indicator for the drilling industry as well as its suppliers. Active drilling rigs consume products and services provided by the oil service industry. This count is helpful in establishing the demand for products used in drilling, completing, producing and processing hydrocarbons.

When oil and gas prices decline, the rig count declines, although the pace of the decline depends on credit conditions and circumstances in the energy market. However, the rig count’s responsiveness to changes in oil prices is a key factor in forecasting the price of oil and gas. The rig count is a tool to understand future supply trends. For example, if oil and gas prices drop and rig counts drop as well, it is more likely oil and gas prices will bounce back as supply decreases. If oil and gas prices drop and rig counts do not drop, it is more likely the price of oil and gas remains low, until it is low enough to cause production to decrease.

Baker Hughes has issued the rotary rig counts as a service to the petroleum industry since 1944, when Hughes Tool Company began weekly counts of the U.S. and Canadian drilling activity. In 1975 the monthly international rig count was initiated by Baker Hughes. What’s interesting, the North American rig count is scheduled to be released at noon Central time on the last working day of each week. The international rig count is scheduled to be released on the fifth working day of the month at 5:00 a.m. Central time.

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click to enlarge

Baker Hughes Incorporated announced today that the international rig count for August 2016 was 937 down 1 from the 938 counted in July 2016, and down 200 from the 1,137 counted in August 2015. The international offshore rig count for August 2016 was 228, up 2 from the 226 counted in July 2016, and down 42 from the 270 counted in August 2015.

The average U.S. rig count for August 2016 was 481, up 32 from the 449 counted in July 2016, and down 402 from the 883 counted in August 2015. The average Canadian rig count for August 2016 was 129, up 35 from the 94 counted in July 2016, and down 77 from the 206 counted in August 2015.

The worldwide rig count for August 2016 was 1,547, up 66 from the 1,481 counted in July 2016, and down 679 from the 2,226 counted in August 2015.

bez-tytulu

This is the weekly comparison of counted rigs in U.S. now and in 2015. As you can see, it really gives clear overview on whole situation. There was a constant decrease until June 2016, and there is slightly growth from it till now.

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click to enlarge

sources:

phx.corporate-ir.net

bakerhughes.com

aogr.com

investopedia.com

infomine.com

 

PGNIG opens LNG trading office

PGNIG opens LNG trading office

Energy independence is a key factor for every country to thrive. Those countries which are not energy independent face many issues. Naturally, this kind of situation is not beneficial for many. It stops economy growth and makes country unstable. Sadly, even pretty well developed countries and nations may face this fact. Poland is one of them and as an example one could describe such unconvenient matter.

Poland has been contracting gas deliveries from Russia for many, many years. Price Poles pay for gas are far away from desirable. Concerns about gas deliveries regularity and negotiating good deals for gas deliveries with Russians have happened repeatedley. Necessarily, this pressure from the East encountered polish reluctance. Both LNG Terminal in Swinoujscie and Baltic Pipe form a vital defence and reaction to Nord Stream 2.

Although gas price for LNG from Qatar to Poland are not particularly cheap it is still good part of energy diversification. To become a real player on the market Poland needs to find the best solutions and contract gas deliveries. Another step in this situation is opening LNG trading office. As PGNIG (Polish Oil and Gas Company) has planned a new trading office is about to be open in London (precisely in January 2017).

“The President of PGNiG SA, Piotr Wozniak, said: “We are upholding our decision to open an LNG trading office in London. Currently, we have reserved 65% of the capacity of the LNG terminal in Swinoujscie [Poland]. Thus, PGNiG SA has become a player of the global LNG market. We want to fully leverage the resulting opportunities.”

The London office will focus its efforts on short-term and medium-term LNG trading. To start with, it will consist of both a number of specialists from the PGNiG Group, as well as external experts. Any strategic decisions regarding the management of long-term contracts and the LNG portfolio will be made by PGNiG SA. “

Hopefully, LNG trading office will become an important place with experts negotiating good deals for Poland and will ease connections with many potential suppliers.

Source:

lngindustry.com

Enhanced Oil Recovery (EOR)

Enhanced Oil Recovery (EOR)

What will happen if world’s oil and gas reserves ends? Either world can survive without fuel or not because there were not enough technologies which could extract all of the oil buried underground. These were the questions which were asked 50 years ago, but with the advancement of Petroleum Industry new techniques are introduced and used around the world frequently. Enhanced oil recovery is one of the most and pioneering field of petroleum industry. It is defined as “Use of different techniques and methods to increase oil and gas production”. We all know that the hydrocarbons produced from primary recovery are only 10 – 20 % of a total reservoir, which is due to natural energy of the reservoir, while this percentage increases up to 40 % when secondary recovery is used, which includes water flooding and gas flooding in reservoir. There is a third term which is called tertiary recovery. According to the Department of Energy U.S.A, the amount of oil produced worldwide is only one third of the total oil available. With the decline in oil discoveries during the last decades it is believed that EOR technologies will play a key role to meet the energy demand in coming years. So by using tertiary recovery we will be able to produce more oil as the demand increase while we have a shortage in the supply. To get last drop of hydrocarbon from a reservoir, tertiary recovery is used. There are many techniques that are used in tertiary recovery and are collectively labelled as “Enhanced Oil Recovery”. Using Enhanced Oil Recovery the production can be increased up to 60%. Enhanced oil recovery is most demanding technique now a days because it is used to recover the Residual oil which cannot be recovered by primary as well as secondary recovery. Enhanced Oil Recovery includes:
1. Thermal Injection
2. Chemical Injection
3. Gas Injection

One thing should be kept in mind that water injection is not included in Enhanced Oil Recovery, it is used in secondary recovery. These three techniques are discussed as below:
1.Thermal Injection
In this technique, steam is injected in well to lower the viscosity. This steam increases the movement of hydrocarbons towards the reservoir. Steam flooding or fire flooding may be used. In steam flooding the steam condenses to hot water, in the steam zone the oil evaporates and in the hot water zone the oil expands. As a result, the oil expands the viscosity drops and the permeability increases. In fire flooding the gases with the oxygen is pumped down and it generate fire. This fire eventually decreases viscosity of oil and hence production is carried out.
2. Chemical Injection
The chemical injection refers to those processes in which different chemicals are added to the fluids in order to stimulate the mobility between both the displacing and displaced fluid. These are water based EOR methods. Chemical flooding processes can be divided into three main categories:
a. Polymer flooding
b. Surfactant flooding

The most common polymer used are:

  • Partially Hydrolyzed Polyacrylamide (HPAM) or ionic
  • Sodium polyacrylate (SPA)
  • Polystyrene sulfonate
  • Carboxy methyl cellulose
  • Xanthan Gum (corn sugar gum)
  • Guar Gum or detergent -like surfactants are used to help lower the surface tension that often prevents oil
    droplets from moving through a reservoir. The surfactants used are:
  • Carboxylates such as Potassium oleate, Sodium laurate, Potassium stearate, Potassium
    caprolate
  • Alkali metal Alkylbenzene sulfonates such as Sodium nonylbenzene sulfonate and Potassium dodecylbenzene sulfonate
  • Salts of resin acids such as Abietic acid and Dihydroabietic acid.

3. Gas Injection
The concept of injecting gases into reservoirs to improve oil recovery is an old theory. The simple working mechanism is that gases are injected in the productive zone which decrease the viscosity of oil and increase the flow. The gases used are:

  • Carbon Dioxide (CO2)
  • Nitrogen (N2)
  • Air Water Alternating Gas (WAG) injection is an EOR process that was developed to mitigate the technical and economic disadvantages of gas injection. It is the most widely applied and most successful traditional EOR process.
    It involves the injection of slugs of water alternately with gas although sometimes the two fluids are injected simultaneously.

Which EOR is Best:

When we talk about that which EOR is technique is the best one, then CO2 injection gets the number one keeping in view of previous production record of all methods used in EOR. Carbon dioxide injection accounts for nearly 60 percent of EOR production in the United States. Thermal injection accounts for 40 percent of EOR production in the United States. Chemical injection accounts for about one percent of EOR production in the United States. When we talk about the cost effectiveness of techniques mentioned above, then CO2 injection is the best method because CO2 is:

  • Naturally occurring gas
  • Can be used as a bi-product from some industry

On the other hand, if we use Thermal Injection then we have to install a separate plant for the steam injection while using Chemical Flooding we have to prepare or buy costly chemical which ultimately increase the cost of recovery which is not an appreciable process. So leeping in view of all these aspects, we have a conclusion that CO2 injection is the best EOR Technique.

References:
http://energy.gov/fe/science-innovation/oil-gas-research/enhanced-oil-recovery
http://www.rigzone.com/training/insight.asp?insight_id=313&c_id=4
http://www.ijastnet.com/journals/Vol_1_No_5_September_2011/18.pdf