Change of direction

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THERE'S some irony in the fact that Keith Spence, a former top Woodside and Shell executive, did his first-class honours degree in geophysics in Tasmania, a state not overly blessed with oil or gas resources.

"At the time, in the early 1970s, it was a university famous for its hard-rock geology," Spence says. "And I studied under Professor Sam Carey, who was a truly inspirational figure in the industry, and he would frequently perform magic tricks during lectures."

After completing his undergraduate degree, Spence began a PhD using seismic events to map the earth's deep crust under Tasmania. But, after receiving job offers from his first two applications, he joined Woodside as a geophysicist in 1978.

"I was always more interested in oil and gas and a lot of my peers at university ended up working in the West Australian oil and gas sector, like me."

It was a good time to have that interest, with the North West Shelf starting to reveal its promise as the largest producer of gas in WA, the result of aggressive exploration by Woodside. "I spent three years at Woodside before joining Shell, where I led a production geology team in The Netherlands before returning to Melbourne as head of operations."

In 1994, Shell posted Spence back to WA and Woodside. "I started as the exploration manager for the North West Shelf Venture on April Fool's Day. The company was in a bit of strife at the time and was bringing in secondees like me to help out."

Woodside had decided against doing further exploration, but Spence had different ideas. "We persuaded the company and the North West Shelf joint venturers to allow us to continue exploring with the new technology available to us, and made seven discoveries in a row - an unheard-of hit rate. To put that in perspective, it's usually more like one in 20 that bears fruit in Australia."

The momentum, he says, swung from merely "milking the cow" [i.e. the North West Shelf] to adding more discoveries - effectively reinvigorating Woodside's exploration policy and growth outlook.

One find was especially exciting. "The Perseus discovery was about the same size as the North Rankin field. It underpinned the development of [liquefied natural gas] trains 4 and 5 on the North West Shelf, more than doubling LNG production.

"Perseus was such an unusual setting. Gas is usually found in structural highs, like an upturned tea-cup setting. But Perseus was in a structurally low setting, a place you wouldn't normally look."

The North Rankin A platform now produces gas and condensate from the Perseus and North Rankin fields, with a daily capacity of up to 1815 million standard cubic feet of gas.

He credits this amazing record of exploration success to the team he led at the time. "They were a pretty switched-on unit, with access to technology that had been tried and tested around the world."

Spence left Shell and joined Woodside in 1998. He moved away from hands-on exploration and became director of the company's northern business unit and then its oil business unit, before standing in as acting CEO between John Akehurst's departure in 2003 and Don Voelte's arrival in 2004.

"It was a job I loved. There was a real sense of community and team at Woodside, and we did well, too, raising the share price from about $12 to $18."

It was in 2005, however, that Spence recorded his proudest achievement to date - approval of the Enfield oil development, off the coast of Exmouth in WA and, more importantly, just 50 kilometres from Ningaloo Reef. "I remember sitting on the beach at Turquoise Bay, near Exmouth, with my wife and seeing a drilling rig in the distance. We had made a couple of discoveries and were nervous due to its proximity to the reef. But I felt confident because we had done 460 community consultations to get the development approved."

Spence went to great lengths to ensure the Enfield development would proceed with as little risk to the environment as possible. "I still go up there every year, to make sure that we've followed up on our commitments to the community."

After Voelte joined, Spence became the chief operating officer and began to develop a retirement plan. "I had always planned to retire from full-time work at 53 and I left Woodside in 2008, aged 54."

But Spence's version of retirement is a long way from the pipe-and-slippers approach. A member of 11 organisations, including the National Carbon Capture and Storage Council, he chairs the National Offshore Petroleum Safety Authority advisory board and is a board member of Skills Australia.

"My areas of interest are energy, training and education," says Spence, who is a keen chorister in his spare time, as well as a member of the Western Australian Academy of Performing Arts board. "The economics of carbon capture and storage are quite challenging. But we have identified the best places in Australia to inject carbon dioxide into rocks for storage and by 2020 we will have several large-scale demonstrations of the technology for carbon dioxide capture, transport and storage at work."

Woodside Petroleum Limited

Woodside Petroleum Limited,Woodside Petroleum Limited,Woodside Petroleum Limited

Woodside Petroleum Limited is planning to drill 17 exploration wells in Libya, 13 offshore and 4 onshore, over the next 18 months after recently completing its seismic work commitments.

Woodside Exploration and New Ventures Director, Agu Kantsler, said two drill rigs will be used in its onshore areas, sometimes working simultaneously. “Our onshore targets are generally in the range of 20-50 MMbbl, but smaller accumulations can be economic dependent on the vicinity of existing infrastructure”, Kantsler said.

“Our drilling campaign commenced in early March with the A1-NC209 well in the Sirte Basin. It is located 1,000 km east of Tripoli and 30 km north of the producing Bu Attifel oil field, and reached a total depth of 4219 m. Analysis of the mud log and wireline log data indicated that the well had encountered two separate hydrocarbon bearing zones. A production test confirmed the presence of an oil column.”

He said Woodside will evaluate all the geological, drilling and DST (Drill Stem Test) data that have been gathered before determining what work is required to further assess the accumulation. A second exploration well in the Sirte Basin (A1-NC205) started drilling in July.

Drilling in the Murzuq Basin commenced at the end of May with the A1-NC210 exploration well. “The well is located 1000 km SSW of Tripoli and 150 km south of the producing Al Wafa oil/gas field. After reaching a total depth of 1042 m, wireline logs were acquired which indicated that the well had encountered several separate hydrocarbon bearing zones.”

Kantsler said a production test of the deepest zone confirmed the presence of a gas column and flowed 5.5 MMscfd through a 52/64 inch choke. “The Absolute Open Flow is calculated to be 19.9 MMscfd. The hydrocarbon intersections and flows in our first two onshore Libyan wells are very encouraging of themselves and for the rest of the drill programme.”

The first of our four offshore wells is planned to be drilled in late 2006 or early 2007, depending on drill rig schedules. “Target sizes for our offshore wells are in the 100s of MMbbl range”, Kantsler said. “It is likely that at various stages of our sizeable Libyan drilling campaign we will have three rigs working at the same time in onshore and offshore areas.”

An offshore seismic programme involving 7,740 km of 2D and 1,690 km2 of 3D data has been completed and identified several large structures in the preliminary stages of interpretation, Kantsler said. “Our onshore seismic acquisition programme, which was the largest in north Africa, was completed in early June 2006, with a total of 8,400 km of 2D and 2,800 km2 of 3D data acquired across the six onshore blocks. We continue to interpret the surveys acquired over the past 20 months.”

Kantsler said Woodside has been encouraged by its progress in Libya. “Of all the companies involved in that country, Woodside holds the third largest exploration acreage position with nearly 60,000 km2”, he said. “In the onshore areas, Woodside picked up five blocks in the Sirte Basin and one block plus one study area in the Murzuq Basin. These blocks were awarded under the Exploration Production Sharing Agreement III (known as EPSA III) in 2003, with Woodside (as operator) holding 45%, Repsol 35% and Hellenic 20%.”

“In the offshore areas, Woodside was awarded four blocks under the first bidding round of EPSA IV in 2005. The offshore joint venture consists of Woodside (operator) with 55%, Occidental with 35% and Liwa Energy of Abu Dhabi with 10%.”

Kantsler said Libya has a rich oil and gas history that spans more than 50 years. “The first concessions were taken up in the mid-1950s by major international oil companies such as Exxon, BP, Marathon and Conoco, with the first significant discovery being made in 1958.”

Production began in the early 1960s and Libya joined OPEC in 1962. By 1970, Libya was producing more than 3 MMbopd, a target the current government would like to again reach by the end of this decade, given that production now is down to about 1.5 MMbopd.

He said Libya became one of the world’s first LNG producers through its Marsa el Brega plant in the early 1970s. The plant remains in production at about 500,000 t a year with most exports historically and currently going to Spain. In the past couple of years, Libya has begun exporting gas to Europe through a major pipeline across the Mediterranean to Italy. The first exploration and production sharing agreements, known as EPSAs, were introduced in 1974.

“Since then they have had EPSA II in 1980, EPSA III in 1988 and EPSA IV in 2004. Each EPSA can have several bid rounds, of course, and take several years to conclude. In 1986, the US imposed sanctions and US companies withdrew from Libya. In 2002 Libya re-entered the global community when the UN lifted sanctions. The US lifted sanctions in 2004.

“At last count, Libya had about 21 international oil companies active in its oil and gas industry. Woodside was awarded its onshore Libyan exploration blocks in late 2003, just ahead of this latest wave of renewed interest.

“Libya has discovered to date about 40 Bbbbl oil and 40 Tcf gas, with an expected similar volume of hydrocarbons yet to be found. In summary, Woodside is attracted to Libya as it is considered to be highly prospective with reasonable fiscal terms managed by an experienced host government that is keen to strengthen its oil and gas industry in order to increase production.”

Kantsler said the Libyan oil industry started in 1955, over 50 years ago. “The country has much experience in exploration and production and has well-established infrastructure”, he said. “Given the maturity of the industry and the existence of proven processes within the oil industry, the business environment in Libya is conducive to business growth.

CLICK ON IMAGES TO ENLARGE

Onshore drilling rig, Sahara Desert, Libya
Two drill rigs will be used in Woodside’s onshore areas, sometimes working simultaneously, over the next 18 months.

Seismic survey vehicles, Sahara Desert, Libya
Woodside’s onshore seismic acquisition programme, which was the largest in north Africa, was completed in early June 2006, with a total of 8,400 km of 2D and 2,800 km2 of 3D data acquired across six onshore blocks.

Seismic survey team, Sahara Desert, Libya

Land Drilling Rig

Land Drilling Rig,Land Drilling Rig,Land Drilling Rig,Land Drilling Rig

When people talk about acquiring drilling rig jobs, it brings to mind hard forcible labour in a rugged environment. Many rig jobs are exactly like this but there ar many other aspects of rig work that do non involve drilling for oil or gas. A few examples would be catering staff, engineers and of course radio operators. You can get jobs in all these fields outside of the oil and gas industry but there is definitely a financial incentive to working on a rig. Whether the rig is seaward or onshore, the salaries ar great. 

Let’s take a look astatine the drilling rig jobs that ar available for catering stave on an oil rig. At the top of the heap you’ll find the position of camp boss. What this position entails is the full responsibility for catering requirements on the rig. If you hold this position you’ll earn an average salary of $55 000. All the catering stave being the chef, stewards and night baker will report to you directly. 
 

The position of chef will earn you an average salary of $39 000.The chef’s responsibility is the daily cookery on the rig. He reports directly to the camp boss who will, when needed, help with preparation duties. The chef will have stewards who help him out. As a steward you’d earn an average salary of between $20 000 and $30 000 and would be responsible, non only for portion the chefs, you’d also have to clean the suite and manage the laundry.

  
Finally we get to the position of night baker. This position will earn you an average salary of $45 000, it seems like a lot, right? Well the reason is that the night baker is solely responsible for baking the bread for the rig for the next day. To put it mildly, no camp boss wants to explain to a hungry roughneck or deckhand why there is no bread available! Hence the great salary… it comes with a great responsibility. It is also a position that is strictly late night to early morning shift.

Another of the drilling rig jobs you may find suits you on an offshore rig, is that of radio operator. The average salary offered for this job is about $42 000. You’d need a radio operator’s licence and your responsibilities would admit keeping personnel lists for the rig. The role of radio operator is best suited to a people’s person, mainly because you’d be the centre of all communicating on the rig. You’d need to get on with everyone. A cool and calm personality is essential for this role as it involves all the logistics for emergency procedures.

So before you rush off to become a roustabout or better still a roughneck, take the time to examine your skill set. You don’t have to actually drill for oil and be permanently outdoors in all weather to get one of the drilling rig jobs. Many of the positions are purely indoors and pretty much the same as working in an average off-rig job. The only difference is the amount of money you can earn. Why earn a pittance doing an off-rig job, when you can earn loads of money doing the same job on a rig?

Company Overview

Company Overview,Company Overview,Company Overview,Company Overview,Company Overview,Company Overview,Company Overview,Company Overview

McLeay Geological

McLeay Geological is a wellsite geological consulting company founded and registered in 1976 by Mr. Robert McLeay in Calgary, Alberta. Since then and under new ownership today, our company has been providing professional geological services to the highest standards for the domestic and international Petroleum Industry.

McLeay Geological is a wellsite geological consulting company founded and registered in 1976 by Mr. Robert McLeay in Calgary, Alberta. Since then and under new ownership today, our company has been providing professional geological services to the highest standards for the domestic and international Petroleum Industry.

Saipem !!Saipem!!

Saipem,Saipem,Saipem,Saipem

Saipem is now a world leader in the oil & gas contracting services sector, both onshore and 


offshore.
The Company began operations in the ’50s. During the ’50s and ’60s it accumulated competencies in onshore pipelaying, plant construction and drilling, operating initially as a 


division of Eni and then on a stand-alone basis, becoming definitively autonomous in 1969. 


Offshore operations commenced in the Mediterranean in the early '60s and expanded to the 


North Sea in 1972.

The Company started offering its services to customers outside the Eni group in the early ‘60s and progressively widened its customer base to include almost all the supermajors, majors, major nationals and independent oil & gas companies worldwide. At the end of the ‘90s  with the migration of the business towards deepwater and developing countries, Saipem has carried out an investment plan in order to adjust the capacity of its own naval assets to the ever challenging market conditions. The primary areas of investment include deepwater drilling, deep water field development, pipelay, leased floating production storage and offloading (fpso), and subsea robotics. Saipem has led the trend in boosting local content by developing impressive facilities in West Africa and the FSU and in the Middle East by employing a large number of local workers with no equal in the industry. While developing the fleet and the local content, the Company started to reinforce its engineering & project management capabilities to cope with the other important market trend towards large integrated EPCI and EPC projects at first in the offshore activities and later on in  the onshore activities. Onshore this was achieved principally through a number of acquisitions, culminating in the acquisition of Bouygues Offshore in 2002.
This was the largest cross-border acquisition in Europe in the oil services sector. Subsequently responding to the recent industry trend towards large onshore EPC projects, including those related to gas monetization, exploitation of difficult oil (heavy oil, tar sands, etc.), and in order to strengthen its position in the Middle East and its national oil company client base, in 2006 Saipem acquired Snamprogetti, one of the major engineering and construction companies active in the international market in the design and execution of large onshore projects for the production and treatment of hydrocarbons and natural gas monetization.

Company Profile Company Profile Company Profile Company Profile 

Company Profile

Saipem is a large, international and one of the best balanced turnkey contractors in the oil & gas industry.

Saipem has a strong bias towards oil and gas related activities in remote areas and deepwater and is a leader in the provision of engineering, procurement, project management and construction services with distinctive capabilities in the design and the execution of large-scale offshore and onshore projects, and technological competencies such as gas monetization and heavy oil exploitation.

Saipem is organised into two Business Units: Engineering & Construction and Drilling. The Company enjoys a superior competitive position for the provision of EPC/EPCI services to the oil industry both onshore and offshore; with a particular focus on the toughest and most technologically challenging projects - activities in remote areas, deepwater, gas, “difficult” oil. Its drilling services continue to be distinctive, operating in many of the oil and gas industry’s ‘hotspots’, frequently in synergy with its onshore and offshore activities. Saipem is a global contractor, with strong local presence in strategic and emerging areas such as West Africa, North Africa, FSU, Central Asia, Middle East, and South East Asia. Saipem is a truly international company. Along with its strong European content, the major part of its human resource base comes from developing Countries. Saipem employs over 40,000 people comprising more than 110 nationalities. In addition to the strong local content of its people, it employs large numbers of people from the most cost-effective developing countries on its vessels and sites, and has sizeable service bases in India, Croatia, Romania and Indonesia. Its clients and people - in particular their health and safety - are the primary focus of all Saipem activity. Saipem has a distinctive Health & Safety Environment Management System and its Quality Management System has been granted ISO 9001:2000 certification by Lloyd's Register Certification.

Mission and Value

Mission and Value Mission and Value Mission and Value Mission and Value 

Mission and Value

Mission
"Pursuing satisfaction of our clients in the energy industry, we tackle each challenge with safe, reliable and innovative solutions.
We entrust our competent and multi-local teams to provide sustainable development for our company and for the communities where we operate".

Values
Commitment to Health & Safety, Openness, Flexibility, Integration, Innovation, Quality, Competitiveness, Teamwork, Humility, Internationalisation, Responsibility, Integrity.

Saipem Drilling Track Record

Saipem Drilling Track Record Saipem Drilling Track Record Saipem Drilling Track Record 

Saipem awarded new onshore drilling contracts worth an estimated USD 280 million

San Donato Milanese, 19 September 2006 – Saipem has been awarded 13 new contracts for the
charter of onshore drilling rigs worth an estimated total of USD 280 million.

Drilling will take place in Saudi Arabia, Kazakhstan, Algeria, Egypt, Peru and Venezuela, for
periods ranging between 4 months and 5 years, depending on the terms of each contract.

Saipem currently operates a fleet of more than 40 onshore drilling and workover 1 rigs in Saudi
Arabia, North Africa, Caspian, Latin America and Italy. An estimated half of these have the
capability to drill to a depth of more than 6,000 metres.

These contracts allow Saipem to further consolidate its position in those areas where it has a longstanding
presence in its onshore and offshore construction business, taking advantage of synergies
and leveraging local content.

---

Saipem, 43% owned by Eni, is organised in three Business Units: Offshore, Onshore and Drilling, with a strong bias towards oil & gas related activities in remote areas and deepwater. Saipem is a leader in the provision of engineering, procurement, project management and construction services with distinctive capabilities in the design and the execution of large scale offshore and onshore projects, and technological competences such as gas monetisation and heavy oil exploitation. 

Oil Discovery In Republic

Oil Discovery In Republic ,Oil Discovery In Republic ,Oil Discovery In Republic ,Oil Discovery In Republic ,Oil Discovery In Republic Oil Discovery In Republic ,Oil Discovery In Republic Oil Discovery In Republic 


Total announces an oil discovery in the Mer Tr?s Profonde Sud (MTPS) block, located around 180 kilometres southwest of Pointe Noire in the Republic of the Congo. 


Drilled in 1,970 metres of water to a total depth of 3,370 metres, the Aurige Nord Marine 1 exploration well tested at 4,970 barrels of oil per day. The potential of the well is currently being assessed.


Awarded in May 1997, the MTPS block extends over more than 5,000 square kilometres, with water depths ranging from 1,300 to 3,000 metres. Total, through its subsidiary Total E&P Congo, is the operator with a 40% interest, alongside partners Eni (30%) and Esso Exploration and Production Congo (Mer Tr?s Profonde Sud) Limited (30%).


Aurige Nord Marine 1 is the third oil find in the block, following Androm?de Marine 1 in 2000 and P?gase Nord Marine 1 in 2004. These three discoveries may form the basis for a future development.


Total has a solid position in the Republic of the Congo, where it is the leading oil producer and biggest foreign investor. In 2005, the Group's equity production in the country averaged 95,000 barrels per day.


About: Total is a leading multinational energy company with 111, 401 employees* and operations in more than 130 countries. Together with its subsidiaries and affiliates, Total is the fourth largest publicly-traded oil and gas integrated company in the world. Its businesses cover the entire oil and gas chain, from crude oil and natural gas exploration and production to the gas downstream (including power generation), transportation, refining, petroleum product marketing, and international crude oil and product trading. Total is also a world-class chemicals manufacturer.


In other oil and energy news, Neste Oil is to sell its 10% holding in the Saudi European Petrochemical Company Ibn Zahr to Saudi Basic Industries Corporation (SABIC) for USD 120 million. Neste Oil will book a capital gain on the sale of approximately EUR 85 million. The companies expect to close the deal during the second quarter of 2006. 


Following the transaction, SABIC will own 80% of Ibn Zahr shares and the remaining shareholders, Apicorp and Ecofuel SpA, 10% each. Neste Oil has been a shareholder in Ibn Zahr since its foundation in December 1984. The company, which produces the gasoline component, MTBE, and polypropylene, is located in Al Jubail on the eastern coast of Saudi Arabia. 


"Ibn Zahr is a well-run and highly profitable company, and Neste Oil has been happy to be a long-term owner. More recently, however, Ibn Zahr's strategy has moved the company more and more towards petrochemicals, whereas Neste Oil's strategy is to concentrate on producing and marketing high-quality fuels for cleaner traffic. This has caused us to re-evaluate our position, and led eventually to the transaction announced today," says Neste Oil's President & CEO, Risto Rinne.


About: Neste Oil Corporation is an independent Northern European oil refining and marketing company, with a focus on advanced fuels for cleaner traffic. Neste Oil's refineries are located in Porvoo and Naantali in Finland, and have a total refining capacity of approx. 250,000 bbl/d. The company employs around 4,500 people. Neste Oil is listed on the Helsinki Stock Exchange (symbol: NES1V).

TECHNICAL DISCUSSIONS ON PETROLEUM SYSTEM MODELING.

Is Timing of Hydrocarbon Generation Really Important ?
Haven't posted for a while now. Here I would like to challenge another good old petroleum system concept. We have been told that if a trap forms after oil generation is finished, it will not be able to receive charge, or it will receive only gas charge. It is one of the responsibilities of the basin modeler to demonstrate the timing of oil and gas generation, relative to timing of trap formation, perhaps using what is called a petroleum system event chart like this one.

Many of us now realize this is not necessarily true. Actually, if we believed this concept, we might have missed a lot of big important petroleum discoveries.   Below are some examples that contradict the theory:

1) Perhaps a good example is the Bohai Bay, where Phillips Petroleum made a big discovery in 1999 at only about 5000 ft in the Minghuazhen/Guantao formation ( check out the story here). What is interesting to me is that the reservoir was merely deposited about 5 million years ago. This would mean that the oil has to have been generated in the last couple of millions years if we allow the reservoir to be deep enough to have a seal. Right? Well, no, geo-history modeling shows that the Shahejie 3 source rock in the kitchen went through the oil window about 23 million years ago, currently at about 8 km deep and > 300 °C, and the reservoir contains low maturity oil!      

2) In deep water Gulf of Mexico, the Jurassic source rock is currently 35,000 to 45,000 ft deep near many big fields and models show oil generation occurred about 15-10 million years ago and the source is currently in the "gas window" under these fields. The Miocene reservoirs are deposited about 9 million years ago, yet they contains very low maturity oil.

3) The Foinaven and Schiehallion fields in the West Shetlands basin contain under saturated oil in the Paleocene reservoirs. Again, the basin model shows that oil generation happened late Cretaceous, prior to the reservoir deposition. A "Motel model" (oil had to migrate to a parking lot and wait for trap formation) was used to explain the apparent timing mismatch (Lamers and Carmichael, 1999). Interesting, isn't it.

I can list more examples, but suffice to say, this seems to become a norm rather than exception. Perhaps we should rethink about how important timing of generation is ? I actually argue that these fields are probably still receiving charge today.

Perhaps the companies which discovered the fields in these examples did not listen to their basin modelers ? How could they have predicted oil in the reservoirs based on the so called petroleum system event chart ? I think at least in the deep water of Gulf of Mexico, certain large oil company may have listened to their modelers and missed most of the action that lead to the discovery of many multi-billion barrel fields there.  


POSTED BY THE BETA FACTOR AT 9:32 PM 4 COMMENTS
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SATURDAY, MARCH 6, 2010

Transient Effects Revisited
Today I had a chance to check out the book "Fundamentals of basin and petroleum systems modeling" by Thomas Hantschel and Armin Kauerauf (Springer-Verlag, 2009). It seems that the transient effects may be still fundamentally misunderstood (and underestimated). Their fig. 3.4a on page 109 (shown below) shows a 1D model going through the deposition, hiatus, and erosion stages. With the assumption that the heat flow at the base of the sediment stays constant at 60 mW/m2, the model predicts small  (±5 mW/m2) changes in heat flow in the sediment column. The authors conclude that the transient effect is smaller than that caused by radioactivity within the sediments. You may click on the image to see a version with better resolution.

When evaluating transient effects, it may not be appropriate to assume constant heat flow at base sediments.  You can see from the figure that the forced base boundary is limiting the extent of the transient effects. With a deeper boundary, the heat flow change should be more significant. More importantly, by setting the boundary at base of sediments,  it considers only the process of heating the sediments, but misses the problem that the deposition of the new layer also puts the entire lithosphere out of equilibrium by moving the surface boundary.

The figure below shows this concept. After adding the new sediments, to establish steady state thermal equilibrium again (green curve), temperature, therefore heat flow must change through out the entire lithosphere, not just within the new sediments. Secondly, since the entire lithosphere needs to be heated (not just the sediments) to reach the new equilibrium, it may take much, much longer (lithosphere is typically 10-20 times thicker than the sediments) than heating the sediments alone (see my previous post on this below).


Below is a model with same conditions as the Hantschel and Kauerauf's model, except that it does not assume a constant heat flow at the base of sediments. Rather the temperature at base of the lithosphere at 120 km is fixed at 1330 °C. The transient effects are much stronger compared to the figure at the top.


The following figure shows the predicted heat flow at the base of the sediment column  through time. You see that it is far from constant. From an initial 60 mW/m2, basal heat flow decreases to 48 mW/m2 at the end of the deposition period, and increases gradually during the hiatus. Then it increases to 72 mW/m2 at the end of the erosion period.

This indicates a ±12 mW/m2 change over 10 million years with deposition and erosion rates of 250 meters/my, a bit higher than the average deposition rate. However, the deep water of the Gulf of Mexico has deposition rates several times as high, and the heat flow at the base of sediment today is around 35 mW/m2, while a steady state heat flow would have been about 50 mW/m2.

In recently uplifted parts of North Africa, we see higher heat flows today. Follwing this analysis, it may be concluded that the heat flow prior to the uplift could be 10 mW/m2 lower depending on erosion rates. See this post for details.

The basin modeling literature is littered with papers making assumptions of heat flow at the base of sediments independent of deposition/erosion rates. Where sedimentation rates are high, or vary significantly over time, the application of such thermal models can cause significant errors in estimating the maturity and timing of petroleum generation. To be fair to the authors, this was how I used to do it in the 90s. But I have learned my lessons from those who learned before me.
POSTED BY THE BETA FACTOR AT 12:26 PM 31 COMMENTS
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WEDNESDAY, JANUARY 13, 2010

How Long Does a Sedimentation Induced Thermal Disequilibrium Last?
This figure shows how sedimentation rate affects heat flow. It is based on a simple 1D basin model, with a steady-state initial thermal condition. A shale (with typical shale properties assumed by basin modelers) layer is deposited between 100 and 99 million years ago followed by a hiatus till present day.



a fixed temperature of 1300 °C at 120 km below the basement and a fixed 10 °C at the sediment surface provide the boundary condition. In a typical basin with continued and varying deposition rate over 10's of million years, the temperature in the sediment column may be always in disequilibrium.
POSTED BY THE BETA FACTOR AT 2:36 PM 10 COMMENTS
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WEDNESDAY, JANUARY 6, 2010

Two Types of Shale Gas?
Happy New Year!

It seems there are two types of shale gas:

Type 1: Shallow depth (few hundred to 2000m), sorption dominated, TOC critical (7 scf/ton for each 1% of TOC). Maturity important only to improve sorption capacity. May be biogenic origin or mixed origin. Mechanism and therefore estimation methods are similar to CBM.

Type 2: Deep depth (>2000 m), compression (free) gas dominated, porosity critical (20 scf/t for each 1% porosity unit) TOC less important. High maturity very important not only to improve sorption capacity, generate the gas but to reduce liquid volume which reduces sorption and lowers relative permeability. Higher pressure improves scf/ton value for the same porosity.

Shale gas evaluation requires a comprehensive model that takes into account the following: (a) a burial and thermal history model to predict maturity and porosity; (b) the Langmuir sorption model to calculate the amount of sorption gas in the organic matter; and (c) a pvt model to calculate in situ free/compression gas and dissolved gas in the residual oil. In general, the behavior of such a model looks like the following:


These curves are shale gas capacity based on 5% TOC and 1.8% VRo. The curves will also vary with pressure gradient, thermal gradient.
POSTED BY THE BETA FACTOR AT 6:25 PM 5 COMMENTS
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TUESDAY, DECEMBER 1, 2009

Why you should not use heat flow as input in your basin model
It is still common practice to use heat flow as input to basin models. It is really a bad practice, especially when the heat flow is supplied at the base of the sediment column.  Modelers usually fit a heat flow to match temperature data and then use the same heat flow in the kitchen or even over geological time. The problem is heat flow is a function of deposition rate (so called transient effects) , which changes laterally (the kitchen area usually has higher sedimentation rates), as well as in time. Yes I am talking about basement heat flow. We recommend using 1330 °C at base of lithosphere as the boundary condition. This will automatically determine the heat flow in the kitchen and its variation in time. Here are a couple of examples:


This figure shows heat flow (at base of sediment column) vs time for the Gulf of Mexico deep water areas. The rapid drop in heat flow in Miocene is caused by rapid deposition. By assuming 1330 °C at base of lithosphere, basin models will automatically determine heat flow based on sedimentation rate as well as the conductivity of the rocks being deposited. Faster deposition rates with a lower conductivity rock will depress heat flow more. Heat flow will slowly equilibrate to steady state if there has been no deposition for about 40 million years.


The second example here is from North Africa, which has undergone significant uplift and erosion during the Tertiary. Heat flow calculated based on 1330 °C at base lithosphere shows how heat flow increases during periods of erosion.
You may check out this earlier post to see how this approach can help determine heat flow in the kitchen area without wells. In most situations, vitrinite reflectance data (and other thermal indicators) are not sensitive enough in determining the paleo-heat flow as deeper burial at present day overprints any impact of cooler temperatures in the past.
POSTED BY THE BETA FACTOR AT 9:30 AM 8 COMMENTS
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WEDNESDAY, NOVEMBER 18, 2009

A caveat of looking at Rock-Eval data from cuttings
I would like to share a recent experience I had working with a Jurassic source rock.

We had hundreds of rock-eval data of the source rock all telling us it is a pretty gas prone source (HI ranging 50 to 250 mg/gTOC). However, in the sub-basin all we have found so far are low GOR oil accumulations. The problem turns out to be due to the way the source rock is typically sampled - from cuttings. Cuttings are usually a mixed bag of samples from over 30 ft or more. In this case (or is it more prevelent?), it does not capture the actual source rock, which are coal seams much less than 2 meter thick each. These coals actually have 50% TOC and HI up to 500 mg/gTOC! Over the 200 meter source interval there may be only 10 meters of net coal. But it is equivalent to a 100 meter thick good type II oil prone source rock!

I can imagine that as long as the source rock is not unitform (how many of them are?), Rock-Eval data from cuttings may tend to downgrade the source rock to some degree, making it less oil prone.

I hope this story may help remind other petroleum system modelers to use some caution when working with "real data". Happy Holidays!

POSTED BY THE BETA FACTOR AT 10:58 AM 1 COMMENTS
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SUNDAY, SEPTEMBER 27, 2009

A Look at Shell's Genex model
The recent paper by John Stainforth (Marine and Petroleum Geology 26, 2009, pp. 552–572) gave us a hint of how Shell models hydrocarbon generation and expulsion. I can't help but to comment a bit here. The paper begins by explaining the problems of other models, quote:

"Models for petroleum generation used by the industry are often limited by (a) sub-optimal laboratory pyrolysis methods for studying hydrocarbon generation, (b) over-simple models of petroleum generation, (c) inappropriate mathematical methods to derive kinetic parameters by fitting laboratory data, (d) primitive models of primary migration/expulsion and its coupling with petroleum generation, and (e) insufficient use of subsurface data to constrain the models. Problems (a), (b) and (c) lead to forced compensation effects between the activation energies and frequency factors of reaction kinetics that are wholly artificial, and which yield poor extrapolations to geological conditions. Simple switch or adsorption models of expulsion are insufficient to describe the residence time of species in source rocks. Yet, the residence time controls the thermal stresses to which the species are subjected for cracking to lighter species."

Kinetics: the paper shows the calibration of kinetic models to some "natural data" (his fig. 9) from an unspecified location (calculating a transformation ratio from rock eval data is a tricky business, and we understand big oil companies need to keep secrets). Below are comparisons of the Shell models with some previously published models. Keep in mind that there is always a range of kinetics for each type and natural data tend to have a lot of scatters.




For type I source, oil conversion only, there does not seem to be a big difference between the Shell model, BP model the IFP model. The Bohai model is derived from subsurface data fitted with the Pepper and Corvi (1995) scheme. The Green River model is from Lawrence Livermore labs.


Here is comparison of the type II sources. For oil only conversion (** denotes oil only), the Shell model requires a higher maturity, but it is almost the same as the BP class DE (a more gas prone type II) facies. When I threw in some sub-surface data points I have available, all of the models are reasonable within the variability of data. Note the oil only and the bulk (oil + gas) curves for the BP facies bracket the data set.

Now, lets look at type III source rocks. This is interesting! The IFP kinetics published more than 20 years ago does a better job fitting the Shell data than Shell's own model. Again, if I throw in some of my own real data for a type III source, you can imagine what they look like. Gee, why are my data always more scattered?

Expulsion model: Shell's expulsion model assumes hydrocarbon expulsion is a diffusion process. I like the behavior of the model in terms of the implications on composition of the expelled fluids and the time lag it predicts. I am not sure that we need to compare that with the simple expulsion models some commercial software uses. For expulsion volumes, the choice of a simple threshold model in the commercial software is advantageous that it provides quick answers (volumes and GOR) well within the uncertainty of the data and allows scenario testing and even probabilistic modeling of charge volumes. The Shell model may predict a different position the residual oil may peak in the source, but if you plot some real data, the scatter is a lot bigger than the theoretical differences.




This figure shows retained S1/TOC over an interval in oil window (VRo=1.0-1.2, type II source). We can not really see evidence of any of the expulsion flow mechanisms - Darcy flow or diffusion. The retained oil is probably mostly adsorbed in the organic, as it shows S1 plotted by itself is more scattered. The average 100-120 mg/g TOC is what the simple expulsion model defaults to, which is a good practical approach without dwelling on the exact mechanism. There has to be some free hydrocarbons in the pores as well that may allow Darcy flow.

Some recent data set has cast a serious doubt in all the expulsion models, including diffusion. In the gas producing Barnett shale (an oil source), the total current retained gas is in excess of 100 mg/g TOC. This is several times more than any of the models predict. The shale has been uplifted and no active generation is occurring.

This paper is good research, and may give us some insights into the processes, but I am not sure I see anything that will change the way we rank prospects which I assume is our job as a petroleum system analyst. The paper lists several theoretical advantages of the Shell model, for example, expulsion during uplifting, the predicted composition, GOR profiles etc. But it seems to me non of these will make the any difference when we apply the models in exploration. His figure 13b predicts type I source rock expelling 1000+ scf/bbl GOR oils at very low maturity (VR<0.7%). Even if it is true, are we really going to try to find some of these oil fields (if it is not clear to you, the volumes expelled before VR<7% is almost nil)? The typical situation is that we may have some Rock eval data from wells drilled on highs we assume are the equivalent source rock in the kitchen. But the uncertainty due to this assumption can be huge. In the Dampier sub-basin of NW shelf Australia, plenty of oil has been found, while all available source rock data show a type III gas prone type. The actual source rock is rarely penetrated. Even if it was, it would be too mature to derive kinetics or even original HI from it. Seismic data will have roughly a 100 m resolution at the depth of the source, so we do not even have a good estimates of its thickness. What is the point of worrying about minor differences in kinetics?

As for expulsion during uplifting, I am not sure we can prove it with geological data. Since there is definitely expulsion before uplifting, additional volumes expelled may be trivial compared to the volumes expelled before cooling, or to the uncertainty in calculating the volumes in an uplifted basin. In addition, the other models actually do still expel some volume because the typical kinetic models do not shut off right away.

The paper's criticism of Pepper and Corvi (1995b) in that they did not show gas expulsion during oil window may not be accurate. As far as I am aware, the Pepper and Corvi source facies are all tuned to give appropriate GOR ranges during oil window, even if it may not be obvious on the mass fraction graphs in the original paper.