<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>

Black Sea, Romania’s path to energy independence

Black Sea, Romania’s path to energy independence

The history of oil and gas operations in the Romanian waters of the Black Sea starts in 1969. Below are presented the most important stages in the development of the offshore production activities:oana

Romania has the capacity to become one of the great European powers in the energy sector due to oil and gas deposits in the Black Sea, much of it in deepwater where several companies have begun to explore. The big players like Total, OMV, Repsol, Turkish Petroleum Company (TPAO), Shell and ExxonMobil are all interested in what lies under the Black Sea. TPAO estimates there are up to ten billion barrels of oil in the region, and the various companies are working on several projects in different sections which are divided into „blocks”.

Romania currently imports 20% of energy needs, the other 80% are satisfied from own production of natural gas, oil, coal and nuclear power. It is estimated that Romania holds 1,400 billion cubic meters of shale gas, which ranks it on the third place in Europe and starting with 2019 will begin extraction of natural gas reserves located in the Black Sea, considered globally significant.

The gas resources discovered by Exxon Mobil and Lukoil are in amount to a maximum of 130 billion cubic meters. If this amount is fully exploited, which is unlikely, and to operate it profitable requires a production of 6 billion cubic meters per year, specialists said that will get a production which will be exhausted in 20 years. This production in the Black Sea overlaps with current production of on shore fields, 6 billion cubic meters per year, which has a constant decrease.

The exploration of the Black Sea will start when gas and oil prices will increase and if gas transportation system will be connected to international markets. One of the main reason is that demand in the country has decreased significantly and the investors which will extract the sea deposits need a market for the transportation of gas from maritime perimeters, which are quite far, from 150-200 kilometers from shore. According to these statements, in the medium and long term, energy future of Romania depends on the interconnection of gas and electricity, but also diversification. Experts believe that Romania will become independent in terms of energy by 2020, but the results could be seen over the decades due to the long process of exploitation and lack of infrastructure.

Will Romania become independent until 2020, as was expected?

by Oana Alexandra






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.



Norway wants to become a major natural gas deliverer in Europe

Norway wants to become a major natural gas deliverer in Europe

Norway has got a chance to become a major natural gas deliverer in Central Europe. Now the most important thing is positive reaction of European Commission. Tord Lien, norwegian Minister of Petroleum and Energy is cofident that his country is ready to become essential natural gas supplier to Europe for many decades.
In European Union many people see this move as a plan to reduce dependence on russian natural gas. Many countries in Europe are tired of games with Russia. They are looking for a strong, safe and certain ally to leave their main gas supplier. In that case Norway is a very attractive and trustworthy associate. Nevertheless nothing is official and Norway waits to see specific decisions from Europe.
These days European countries are looking for a way out from russian authority in gas sector. New polish government is interested in diversification of gas suppliers to Poland and analyzes project about collaboration with Norway, which was rejected years ago. Many things changed in last few years and now norge gas is much more eye-catching than earlier. What’s interesting is that for the first time in lithuanian history Russia will not be primary gas supplier for this country. Rokas Masiulis, Energy minister in Lithania during an interview with Reuters says that in 2016 Gazprom lost their gas monopoly to Statoil.
Without clear decisions from european and norwegian side we can only debate about these ideas. We see that Norway has got a lot of friends in European Union and this move might be attractive for both groups. Now we have to wait for more informations in that important case.




Half of US shale drillers may go bankrupt

Half of US shale drillers may go bankrupt

Before the crude market reaches equilibrium Half of U.S. shale oil producers could go bankrupt. The senior oil and gas analyst at Oppenheimer & Co., Fadel Gheit, said this Monday that it could be more than two years before crude prices ultimately will stabilize, and its price will oscillate near $60.

Many secondary U.S. drillers must drill into and break up shale rock to get the oil and gas released through a process called hydraulic fracturing. It is a well-stimulation technique in which rock is fractured by a pressurized liquid. The process involves the high-pressure injection of ‘fracking fluid’  into a wellbore to create cracks in the deep-rock formations through which natural gas, petroleum, and brine will flow more freely. It causes that fracking is significantly more expensive than extracting oil from conventional wells. This drillers cannot wait for prices to stabilize so long, also they need at least $70 oil to survive. At current oil prices, companies both large and small – including ExxonMobil and Chevron — will have to think twice about their dividend.

On Tuesday, U.S. crude fell to $29.93, which was last seen in December 2003. Such a drop would be brief because supply and demand are beginning to come into balance. But a number of producers would enter bankruptcy even with crude near $30 per barrel. U.S. drillers are now spending more than they are making from operations, a situation that Gheit said is unsustainable and will eventually force prices higher.

Summing up, the oil industry needs a minimum amount of investment to keep oil supply in line with demand. The current investment right now would not be sufficient enough to bring additional production to meet global demand. It’s not a good information that crude price fell, but we have to remember that this industry is very unstable, so let’s hope it get better within upcoming days.

sources: www.cnbc.comen.wikipedia.org

Unlocking the potential for Underground Coal Gasification in the UK

Unlocking the potential for Underground Coal Gasification in the UK

With the need to diversify the UK energy market becoming increasingly pressing, new technologies are continually developing and evolving the market. One such technology which is gaining increased attention across the energy industry is Underground Coal Gasification (UCG).

UCG uses stranded coal seams, which cannot be accessed by conventional mining techniques due to geology, safety or depth constraints, and converts this in-situ coal into a mixture of gasses known as syngas, which can then be used for power generation. UCG is not a new concept; trials have taken place across the course of the last century. However, technological advancements have prompted a resurgence in the industry, with the UK tipped to be a key area to watch. The UK is ideally suited to the development of UCG due to its large indigenous coal resources. UCG also provides opportunities for developing much-needed cost effective cleaner coal technologies, diversity of supply and energy security for the UK.

UCG also holds a wealth of advantages over other forms of energy generation. UCG does not use chemicals or fracking, the depth at which UCG operations are undertaken are situated far below fresh water aquifers and thus avoid water contamination, and UCG holds substantial environmental benefits over conventional coal fired power generation. UCG is also ideally suited for use in conjunction with Carbon Capture and Storage (CCS), technology that the UK government is very eager to utilise. Combining these two technologies provides an incredibly promising opportunity for low carbon power generation, and one of a very small number of methods that will enable the ongoing use of fossil fuels without the current environmental damage they cause.

UCG technology is also incredibly flexible. Rather than being restricted to simply providing gas directly into the grid, UCG also has the potential to play a significant role in providing feedstock for the petrochemical industry and a cost effective fuel source for energy intensive industry. UCG also has possibilities for generating hydrogen for vehicles and fuel cells, and supporting primary electricity generation.

One organisation pioneering the development of the UCG industry in the UK is Cluff Natural Resources (CLNR). Founded in 2012 by veteran North Sea entrepreneur Algy Cluff, CLNR has committed to the development of the UK’s first UCG operations since the 1950’s, and already has a growing portfolio of UK assets including 8 UCG licences. CLNR’s current UCG licences cover the North Wales/Merseyside border, Durham South, Maryport, North Cumbria, Largo Bay Durham North, Carmarthenshire and the Dee Estuary, The Firth of Forth near Kincardine, Scotland.

The UCG industry in the UK is still in the early stages of development, however it has the potential to become a key element of the UK energy industry. Andrew Nunn, Chief Operating Officer for CLNR has commented that ‘the industry, quite rightly, is taking a very measured approach to the development of UCG.  In line with the comprehensive body of evidence published by DECC, and its predecessors, the next step for UCG in the UK is a small number of production tests to confirm commercial and environmental performance in a local context, before rolling out a larger commercial UCG development’.

CLNR recently entered into a joint venture with Halliburton to accelerate the development of the Kincardine UCG project. On the recent partnership, Andrew has commented that ‘Halliburton’s commitment is a great endorsement of both the technical and commercial viability of UCG on a local and global scale. They are one of the world’s leading providers of subsurface engineering and services to the energy industry and this relationship gives us access to experience and technologies from across Halliburton’s global product lines. This includes their high temperature geothermal products, SAGD/TAGD experience and a vast array of monitoring and instrumentation technologies which are all directly applicable to UCG operations. This technically lead collaboration will ensure the approach to designing and operating the UCG production test will be subject to the same rigorous processes as other major energy projects’.

As with other energy initiatives, such as the shale gas industry, the success of the UCG industry will be determined by public opinion. Andrew has noted that in order to develop a thriving UCG industry in the UK, ‘key regulators must be technically capable, politically empowered and sufficiently funded to take a very hands role during the developmental phase of the UCG industry’, in order to assure local communities that UCG operations are being conducted ‘in a safe and responsible manner’. The difference between UCG and many other energy industries is the foundation that it will be built upon. Andrew has highlighted that ‘one of the key differentiator’s for UCG is that the industry is being built on a strong scientific evidence base which was compiled by the UK Government over a period of 10 years in the absence of any external commercial influence, so the basis for progressive government policy is in place’.

The next five years will be key to the development of the UK UCG industry and CLNR already have plans in place for the development of the industry. Andrew has outlined as follows; ‘We are currently preparing the Environmental Statement and Planning Application documentation for our proposed UCG production test in the Firth of Forth which we plan to submit towards the end of the year.  Following approval the focus will be on drilling and construction of the production facilities to support approximately 200 days of gasification operations, followed by decommissioning of the surface equipment and validation of environmental performance. All the data gathered will be used to book reserves and underpin a full bankable feasibility study for a fully optimised commercial development within the Firth of Forth’.

Despite the promise that the UCG industry holds it is likely to be 2020 at the earliest before we see commercial development of the industry. However, with Cluff Natural Resources continually working to develop the industry and a target production test date of early 2017, the UCG industry is undoubtedly a key area to watch within the UK energy industry. Industry leaders from across the energy sector will meet to discuss the promising UCG industry at the Third European Shale Gas & Oil Summit, taking place 15th-16th October, in a conference dedicated to this developing technology.

For more information regarding the summit visit the website at http://www.esgos.eu/

By Megan.Roden@charlesmaxwell.co.uk

Managed Pressure Drilling- A Food For Thought

Managed Pressure Drilling- A Food For Thought

Managed Pressure Drilling (MPD) is a new technology that uses tools similar to those of underbalanced drilling to better control pressure variations while drilling a well. The aim of MPD is to improve the drillability of a well by alleviating drilling issues that can arise.

IADC defines MPD as “An adaptive drilling process used to precisely control the annular pressure profile throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the annular hydraulic pressure profile accordingly.”

MPD is further divided into two categories -“reactive” (the well is designed for conventional drilling, but equipment is rigged up to quickly react to unexpected pressure changes) and “proactive” (equipment is rigged up to actively alter the annular pressure profile, potentially extending or eliminating casing points). This category of MPD can offer the greatest benefit to the offshore drilling industry as it can deal with unforeseen problems before they occur.


            The primary objectives of MPD are to mitigate drilling hazards and increase operational drilling efficiencies by diminishing the non-productive time (NPT). The operational drilling problems most associated with NPT include:

  • Lost Circulation
  • Stuck Pipe
  • Wellbore instability
  • Well control incidents

            MPD process uses a collection of tools and techniques to mitigate the risks and costs associated with drilling wells that have narrow downhole environment limits, by proactively managing the pressure profile.

MPD may include control of back pressure, fluid density, fluid rheology, annular fluid level, circulating friction, hole geometry and combinations thereof.

MPD may allow fast corrective action to deal with observed pressure variations. The ability to control annular pressures dynamically facilitates drilling of what might otherwise be economically unattainable prospects.

MPD technique may be used to avoid formation influx. Any flow incidental to the operation will be safely contained using an appropriate process.

The centerpiece of the definition is “precise control”. The technology allows drillers to control bottom hole pressure from the surface within a range of 30-50 psi. One method does not address all the problems and MPD is application specific. The vast majority of MPD while drilling in a closed vessel, using an RCD with at least one drill string, non-return valve and a DCM.


MPD is similar to underbalanced drilling (UBD). It uses many of the same tools that were designed for UBD

operations. The difference between the methods is that UBD is used to prevent

damage to the reservoir while the purpose of MPD is to solve drilling problems. UBD allows influx of formation fluids by drilling with the pressure of the fluid in the wellbore lower than the pore pressure. MPD manages the pressure to remain between the pore pressure and the fracture pressure of the reservoir. It is set up to handle the influx of fluids that may occur while drilling but does not encourage influx. UBD is reservoir-issue related while MPD is drilling-issue related.


As a well is drilled, drilling fluid is circulated in the hole to obtain a specific bottom hole pressure. The density of the fluid is determined by the formation and pore pressure gradients and the wellbore stability.1

Fig. 1shows a pressure gradient profile of a well. This profile shows the change in pressure as the depth increases. The pressure window is the area between the pore pressure and the fracture pressure. The goal when drilling a well is to keep the pressure inside this pressure window. In a static well, the pressure is determined by the hydrostatic pressure of the mud. In conventional drilling, the only way to adjust the pressure during static conditions is to vary mud weight in the well.

Fig. 2shows the problem that can occur when dealing with tight pressure gradient windows. When the well is static, the pressure in the well is less than the pore pressure and the well takes a kick; that is, hydrocarbons flow into the well. Before drilling can begin again, the kick has to be circulated out. After a connection, the pumps restart, the BHP (Bottom Hole Pressure) increases, and the pressure goes above the fracture-pressure, resulting in lost circulation, or fluid flowing into the formation. The goal of managed pressure drilling is to walk the line of the pressure gradients. Managing the pressure and remaining inside this pressure gradient window can avoid many drilling problems.


CONTINUOUS CIRCULATION SYSTEM The continuous circulation system (CCS) is a new technology that enables a driller to make connections without stopping fluid circulation. A CCS enables a driller to maintain a constant ECD when making connections. In normal drilling operations, a driller must turn the pumps off when making a connection. Numerous problems can occur as pumps start and stop in a drilling operation. (Fig. 3)


In a narrow drilling window, where the pore pressure and fracture pressure gradients are close, continuous circulation can prevent many problems from occurring.

Benefits of using the CCS include

• Reducing nonrotation time by eliminating the need to circulate the cuttings out of the bottom hole assembly.

• Reducing the possibility of a stuck drillstring by keeping the cuttings from dropping to the bottom.

• Constant ECD can be maintained.


The ECD reduction tool is designed to reduce the bottomhole pressure increase caused by friction in the annulus by providing a pressure boost up annulus.

            Equivalent circulating density (ECD) is a function of mud density, mud rheology, cuttings loading, annular geometry and flow rate. Drilling-fluid density is required for pressure control and wellbore stability. Viscosity and flow rate are needed for hole cleaning and barite-sag mitigation. Gel strengths are required to suspend drill cuttings. The goal of ECD management is to find balance between these parameters to successfully drill a well.

Reducing ECD in a well can result in many benefits. These benefits can include:

• Reducing the number of casing strings.

• Improving hole cleaning by using higher flow rates.

• Being able to remain in the pressure window for complex wells.

• Reducing lost circulation and differential sticking.

• Reducing formation damage.


The challenge for the future of MPD is to convince the industry of its benefits.

The main problem in instituting MPD is that companies think that their way works well enough and do not want to take the risk of trying a newer method.

This is similar to situations that occurred when underbalanced drilling and horizontal drilling were first introduced. It is just going to take time for MPD to become an accepted method and be used in regular drilling operation.

The benefits that should be shown to companies to convince them to try MPD include the possibility of improving the drill-ability of depleted formations. Drilling through these depleted zones often result in narrow pressure windows and lost circulation issues. Drilling in these areas require a more constant bottomhole pressure to remain in the narrow pressure window. MPD would help reduce costs and improve current assets held by companies. Companies realizing these benefits and seeing them work would lead to more common use by these companies.

Historical Background of exploration in Pakistan

Historical Background of exploration in Pakistan

If we talk about first exploratory well which was drilled in the region of undivided sub-continent (now Pakistan) then facts highlighted that it was drilled in1866 by Punjab Oriental State, right after seven years of World’s 1st well drilled in USA to a depth of 65ft.
With the passage of time, discovery of oil in province of Balochistan was the main success where thirteen shallow wells produced 25,000 barrels of oil between 1885 and 1892. Here one fact should be made clear that during this early phase all the drilling activities were controlled by The Government of Indio-Pak.
Unfortunately, they were unable to find such a reserve which exhibit commercial storage until 1910. Later on Attock Oil Company (AOC) made a first commercial oil discovery (4.31 MMbo) in 1915, in Punjab province. This achievement leads to attract many exploration companies to utilize their investment in region of sub-continent. As consequences three oil fields were established consecutively in 1936, 1944 and 1946 by joint venture of Attock Oil company (AOC) and Burmah Oil Company (BOC).
After the independence of Pakistan in 1947, the Government of Pakistan issued Regulation of Mines and Oilfields and Mineral Development Act 1948 and classified rules under this Act in 1949. The main objective of this Act was to provide regulatory authority to encourage and accelerate petroleum exploration and production activities in the country.
BOC and AOC transferred its exploration activities to local companies, by establishing Pakistan Petroleum Limited (PPL) and Pakistan Oilfields Limited (POL) respectively.
After establishment of PPL & POL, a well drilled on the Sui structure (located in Balochistan Province), made the inaugural discovery of one of the largest reserves of natural gas and recoverable reserves were estimated to be over 10 trillion cubic feet (TCF) which is equivalent to about 1 billion barrels of oil. This discovery was a milestone towards the development & prosperity of petroleum industry in Pakistan which made numerous E&P companies attentive towards this part of globe.
In order to drill more exploratory wells in prospective areas, permits were issued to Standard Vacuum Oil Company (1954), Hunt International Oil Company (1955), Shell Oil Company (1956), Sun Oil Company (1957) and Tidewater (1958) respectively by the Government of Pakistan which led to further discoveries of natural gas reserves.
In spite of new gas discoveries during this time frame, the exploration activities towards the oil discoveries exhibit negative trend.
By keeping this trend in focus Government of Pakistan decided to establish the state oil exploration company and in 1961 a joint stock company under the name of Oil and Gas Development Company Limited (OGDCL) was established which expands moving scheme of prosperous profile with the small gas discovery at Sindh province in 1965, followed by discovery of oil reserve at Potwar region of Punjab in 1968.
Later on gas reserve at Sindh in 1970, Punjab in 1972, then Sindh in 1973 and gas/ condensate at Punjab in 1975 were discovered by the same company.
Meanwhile POL discovered oil at Punjab province in 1968 and American Oil Company (AMOCO) discovered a small gas accumulation at Balochistan province in 1975.
After the modification of petroleum regulations in 1976, British Petroleum a USA Company came to Pakistan and started its activities and has drilled 65 discovery wells in Pakistan.
This opened a new oil province and broke the tradition in the north region. After Sui (Balochistan), the discovery of oil in the Southern Basin was the second milestone in search for hydrocarbons in Pakistan and this area has attained the distinction of contributing 59% of the total oil production of the country.
Following journey of success OGDCL discovered a large gas storage in Eocene Carbonates of Middle Indus Basin in 1989 and fortunately in the same year, Eni made a gas discovery in Sandstone (Cretaceous) in south region lead to discover number of significant gas reserves in 1993 and then in 1998 by OMV of Austria followed by Mari Gas Company Ltd (MGCL) in 1999, in 2002 Petronas of Malaysia provide its services to reveal hydrocarbon bearing zones.
North Frontier Province of Pakistan (NWFP) deviates attention of industrial progress when MOL of Hungry in 2002 and as well as in 2005 made discovery of reserves which has reinforced the belief of many Geologist that this region can host large hydrocarbon reserves and recently nine blocks have been awarded in this province.
Offshore exploration which had started in 1961 remained limited to the drilling of only eleven exploratory wells due to lack of success and high drilling cost.
Current statistics reveals that only four blocks in the offshore region are held under license, two by Total, one by Shell and the fourth one is by British Gas.


Image: Courtesy naturalgasasia.com

Ophir sells 20% interest in offshore blocks,Tanzania to Pavilion Energy.

Ophir sells 20% interest in offshore blocks,Tanzania to Pavilion Energy.

Ophir Energy announced on Monday that the transaction reported on 14 November 2013 to sell a 20% interest in Blocks 1, 3 and 4, Tanzania to Pavilion Energy has now completed.

The company has received cash of US$1,255million reflecting the purchase price consideration of US$1,250million plus a completion adjustment of US$5million to reflect interest and working capital movements since the effective date of the transaction of 1 January 2014. A further US$38 million is payable following the final investment decision of the development of Blocks 1, 3 and 4, expected in 2016.

A tax liability will be incurred on the transaction in Tanzania. The timing of the payment will be finalised after discussion with the relevant tax authorities. Net proceeds after tax from the transaction are expected to be ca. US$1.0bn based on Management estimates. This estimate will be subject to finalisation of the 2013 and 2014 corporate tax returns which impact the basis of the calculation with respect to allowable losses arising from brought forward and current year expenditure.

The proceeds from this transaction will support our forward plans which includes investing in a number of new opportunities that are under consideration and have transformational growth potential. This is in addition to having the flexibility to rapidly capitalise on any exploration success from the forward drilling programme which is well funded from our existing cash resources.

Management remain committed to maximising and delivering returns to shareholders and the Board continues to monitor closely the capital needs of the business and the appropriate level of cash liquidity.

Nick Cooper, CEO, commented:

“We are delighted to welcome Pavilion Energy into the Tanzanian LNG development across Blocks 1, 3 and 4. The partial monetisation of our interests is in keeping with Ophir’s strategy of minimising exposure to development capex and realising the value created from exploration success at the appropriate time”

Photos: Ophir Energy

Read more: ophir-energy.com