Keys to Heavy Oil: Characterizing Fluids and the Reservoir

By Shawn Taylor - Success with heavy oil depends as much on understanding the fluid properties of the reservoir as it does on knowing the geology of the reservoir itself.

The reason is that the chemical differences between heavy oil and conventional oil ultimately affect their viscosity. Viscosity, in turn, influences every other aspect of a heavy oil development. Technology that was developed for conventional plays does not address the issues of producing heavy oil. Viscosity is the key.
Every new heavy oil development eventually requires some form of enhanced oil recovery (EOR), which generally means steam, solvents or a combination of both. Without EOR, the recovery factor from what the industry calls “cold” production might be as little as one percent and no more than 10 percent. With thermal recovery, typical rates run from 30 to 70 percent. In thermal processes, however, the cost of generating the steam is typically the single greatest operating expense.  
Thermal recovery options in some reservoirs include the use of cyclical steam (“huff 'n' puff”), downhole heaters, or a relatively new commercial process called Steam Assisted Gravity Drainage (SAGD). Other techniques, such as injecting slugs of water alternating with gas (WAG) are less efficient than thermal recovery, but also less expensive. 

Sampling fluid properties

The mobility of reservoir fluids influences recovery rates, but the enhanced oil recovery and artificial lift methods needed to produce them changes the already complex fluid characteristics of heavy oil.
To properly specify the field’s surface and downhole equipment, it is important to understand those fluid properties and how they might change throughout the system. In Alaska’s West Sak and Schrader Bluff formations, for example, heavy oil viscosities range from about 30 to 3,000 centipoise.
Determining the true viscosity of heavy oil is a complex process involving both in situ testing with wireline tools, and the laboratory analysis of fluid and core samples taken from the well. These are common procedures in reservoirs with lighter crude, but with heavy oil, even the physical task of drawing the viscous fluid into a sample container can be difficult. 
Getting a representative open-hole fluid sample can take more than a full day of rig time because the first fluids to come up will be thick with drilling mud, sand, water and other contaminants. The fluid properties of new wells may continue to change over weeks or months. 
Foaming oil
Foaming complicates the process even more. When heavy oil contains associated gas, foaming may occur at any point in the reservoir, wellbore, flowlines or production equipment at the surface. It happens when gas reaches its bubble point and comes out of suspension as the pressure and temperature of the fluids change. 
Gas separates from lighter crudes much faster and more predictably than it does from heavy oil. The ability of the oil to foam depends on its viscosity, so higher viscosity oil is more likely to foam, and the foam it makes will be longer lasting.  
While foaming can be a problem, it can also work in the operator’s favor. Since any foam that forms in the reservoir increases pressure, it can serve as a temporary gas drive, pushing oil toward the wellbore. 
The trick, of course, is to understand enough about the fluid properties to know where and when the foaming is likely to occur. It won’t help you much if the foaming does not begin until fluids reach the production separator. 
Fluid samples that contain oil-based drilling mud (OBM) can alter a fluid’s bubble point and viscosity. If the true bubble point is 2,000 psi, for example, OBM in the fluid sample might drop the measured bubble point to 1,000 psi. If surface equipment is then designed based on the 1000 psi value, however, operators could be surprised by gas coming out of suspension much sooner than than expected, and their facilities would not have enough capacity to handle it. 
Testing also shows how the well fluids will react when mixed with other fluids, such as gas, solvents or lighter crude. The emulsions formed in heavy oil are harder to break than they are with less viscous fluids.   
The danger of not doing enough fluid testing is that the design of the field’s surface production equipment will not be adequate to handle the flow. 
Understanding the full picture 
When the time comes to make key decisions such as well placement or completion design, operators with the most accurate picture of their reservoir will make the best choices for their wells and surface facilities. 
Detailed reservoir characterizations are also the foundation for future decisions, such as selecting the right time and follow-up production method to enhance overall recovery. 
That improved ability to predict how a reservoir will behave benefits every decision maker on the project team, from the geologist and production engineers to the asset manager. The time and money operators spend in the beginning to learn about their reservoir will pay off many times in the end.

How is Heavy Oil Produced?

Recovery
Some heavy oil production can be accomplished via conventional methods, such as vertical wells, pumps, and pressure maintenance, but these methods are considered highly inefficient. Other technologies being used to recover heavy oil include, but are not limited to: cold heavy oil production with sand (CHOPS), vapor extraction (VAPEX), and thermal in situ methods. The main oil-related challenges involved in production are gravity and the viscosity of heavy oil.
The CHOPS method allows sand into the wellbore with the oil to improve well productivity. Wells that formerly produced only 20 barrels/day have been observed to produce more than 200 barrels/day, according to Canada's Centre for Energy, with free movement of sand into the wellbore. This technology was pioneered in Canada.
A non-thermal recovery method that involves injecting vaporized solvents into heavy oil, VAPEX creates a vapor-chamber that oil flows through due to gravity drainage. It has the potential to lower greenhouse gas emissions and significantly reduce water consumption, compared to other technologies currently in use, and can be used to recover bitumen from zones too thin for traditional thermal recovery.
Steam-assisted gravity drainage (SAGD) is a thermal in situ recovery method that involves drilling two horizontal wells, one above the other. Steam is continuously injected through the upper wellbore, softening bitumen so that it drains into the lower wellbore and is pumped to the surface. Pairs of parallel horizontal wells, one for steam and one for production, make it possible to recover bitumen continuously from oil sands.
Cyclic steam stimulation, also a thermal in situ recovery method, is a three-stage process involving several weeks of steam injection, followed by several weeks of "soaking," followed by a production phase where the oil is produced by the same wells in which the steam was injected. As production declines, the injection phase is restarted. The high-pressure steam not only makes the oil more mobile, but also creates cracks and channels through which the oil can flow to the wellbore.
Processing
Heavy oil and bitumen consist of large hydrocarbon molecules, which contain proportionately more carbon atoms than hydrogen atoms. Upgrading processes add hydrogen atoms and/or remove carbon atoms to convert bitumen into a product similar to conventional light crude oil.
Upgrading is usually a two-part process, as explained by Canada's Centre for Energy. In the first stage, bitumen is heated and hydrogen added under high pressure to break the large hydrocarbon molecules into simpler, smaller compounds. This process is known as "hydrocracking." Some upgraders also use a "coking" process to remove carbon from the bitumen to produce lighter hydrocarbons and coke (a carbon material that resembles finely ground asphalt). During the second stage, hydrogen is added to the hydrocarbon compounds to stabilize them and remove impurities such as sulfur. This process is called "hydrotreating."
Upgrading results in three main products: naphtha, kerosene, and gas oil (a fuel oil somewhat heavier than kerosene). These can be sold separately or blended to produce synthetic crude oil for sale to refineries.

Keys to heavy oil: The importance of planning ahead

Until recently, many producers thought commercial quantities of heayv oil were unique to a handful of large fields in Canada, Venezuela and the United States.

Now that market conditions have changed, prospects are quickly opening up in Brazil, Mexico, China, the Middle East, Russia and elsewhere. The fact is, most of the world’s remaining oil has an API gravity of 22 or below, which is one way the industry defines heavy oil.   
Producing heavy oil is quite different from conventional reserves. The first challenge is selecting the right production method from a range of alternatives. Many operators use some form of steam injection to heat the reservoir, but not all reservoirs are suitable candidates.

Planning a heavy oil development is like designing a house; the foundation must be right, because it will affect everything you do in the future. The design is influenced by factors such as geology, permeability, viscosity, gravity, miscibility, and the location of the field. 
Transporting heavy oil also raises questions. To flow through pipelines, heavy oil must either be kept warm, mixed with solvents, or blended with lighter crudes. Flow assurance is particularly challenging in subsea developments and colder climates. If a more viscous oil is to be blended, asset managers may have to proceed with heavy oil developments while they still have ample supplies of lighter crude.
Not only is heavy oil more expensive to produce and harder to transport than lighter crude, there are other challenges, including new technologies beyond the experience of most operators. While it is certainly possible to turn a profit with heavy oil, new developments require plenty of upfront planning.  
Refining is a good example. Although the technology exists to process nearly 100 percent of a barrel of heavy crude into useful products, it takes equipment that relatively few refiners have. Those that do, benefit from heavy oil’s 15 to 20 percent price differential, so the economics of any new heavy oil development depend in part on the proximity of refiners who can handle it. Industry journals suggest that 45 percent of all refineries could be upgraded to handle heavy crude, but only about 25 percent are equipped to do so today, and most of those are in the United States.

Production methods
Heavy oil may be light as honey or thick as peanut butter, even within the same reservoir. Heavy oil exists in many environments and there are a variety ways to produce it, but methods for recovering conventional crudes work poorly or not at all with heavy oil. 
Heavy oil developments often have more wells than other fields. The reservoirs, which tend to be widespread and relatively shallow, also produce much longer than conventional plays. Primary and cold production, however, yield very low recovery factors. Heavy oil operators using one of several thermal processes to heat the reservoir can expect more than a decade of steady production from a good well, and recovery factors ranging from 30 to 70 percent. 
Although thermal recovery increases the lifting costs new technology is being developed to reduce the steam-to-oil ratio.
Steam-Assisted Gravity Drainage (SAGD), for example, is a thermal process that employs pairs of horizontal wells with lateral sections one above the other. The upper well is the steam injector and the lower well is the producer. Simulations on some of the first SAGD wells predict that operators can expect them to produce at commercial rates for at least 15 years. Other promising heavy oil technologies may employ solvents alone, or a combination of solvents and steam.

Modeling for the life of the field

Most successful heavy oil operators drill pilot wells to learn as much as possible about their reservoirs before selecting a recovery system, and some continue drilling test wells throughout the life of the field. The immediate goal of pilot testing is to create an accurate model for the full-field development.
Once production begins, simulations run on the model allow engineers to select and optimize the recovery process and to remain flexible in the full-field development. Adequate simulations are paramount for informed decisions and these depend on reliable inputs of reservoir and fluid characteristics. When fluid flow properties are introduced into this 'static' model it becomes 'dynamic'. The dynamic model solves a set of flow and heat equations which describe the mechanisms of the heavy oil recovery process in order to predict the recovery performance.
It is important to know key reservoir properties such as fluid pressure, volume and temperature (PVT). Special Core Analysis (SCAL) tests the formation rock for capillary pressure and relative permeability. 
Additional fluid sampling could include a suite of solubility tests for saturates, aromatics, resins and asphaltenes (SARA). Operators should consider CO2 phase compatibility tests and thin-bed analysis. Other geologic interpretations can help define the depositional environment, stratigraphy and petrophysical framework of the reservoir. 
Logging (with NMR) and testing reveals not only the fluid composition and viscosity, but how it differs throughout the reservoir and how it might change over time. Understanding those changes makes it possible to design drainage systems that work in the operator’s favor. By constantly updating the model as new data come in, the model also becomes a reliable guide for the life of the field, which can easily be more than 50 years.   
That longevity is one of the key reasons that heavy oil is attractive to asset managers and it brings home the importance of good planning. After all, what operators do to their fields in the beginning is what they will likely have to live with for a very long time. 

Expert Viewpoint - Flow Control

Michel Bouchard considers flow control issues relating to heavy oil.

Bouchard graduated with a degree in Economics in 1980 and started training as a wireline logging engineer in 1981. In the late 1990s he cofounded a company focused on multilateral well junctions. He joined Reslink in 2004, representing the company in North and South America. Reslink, a supplier of robust wire-wrapped sand screens for sandface completions and inflow control devices (ICDs), was acquired by Schlumberger in December 2006. Presently based in Calgary, Michel is currently focused on applying ICD technology to heavy oil.

 A great number of heavy oil wells rely on horizontal completions and are thus prone to the flow control challenges inherent to this type of completion such as the “heel-to-toe” effect from friction loss along the wellbore, as well as pressure, fluid mobility and permeability contrasts in the producing section. There is a natural tendency to have much higher production at the heel (near the vertical part of well) than the toe (at the end of the well). In the presence of a gas cap or water table, water or gas coning is likely to occur much sooner near the heel, greatly impairing overall well production. Where water and/or gas are creating drive, or steam is being injected, breakthrough will lead to loss of pressure, resulting in a loss of reserves and making intervention necessary.

Variable permeability, reservoir pressure and fluid mobility along the well can cause a similar effect. Flow will be greater in sections with high permeability, rendering them more prone to coning, pressure reduction, and, ultimately causing issues for production stability. Addressing the challenges related to irregular flow is the basis for developing ICDs, most of which are deployed in long horizontal wells.

Steam-assisted gravity drainage (SAGD) wells present among the greatest flow control challenges of all heavy oil applications. The SAGD process usually involves the drilling from a single vertical bore of two parallel horizontal wells, one on top of each other. The upper well is dedicated to steam injection and the bottom one to production. The heel-to-toe effect will normally result in greater injectivity (upper well) and productivity (bottom well) at the heel. Combined with the fact that the heels are directly on top of each other and sometime as close as 5 meters apart, this situation is very likely to lead to premature steam breakthrough. This is one of the most undesirable events in a SAGD operation as it effectively shuts down production.  The problem can be exacerbated by variable injection temperature, because steam temperature is likely to be higher at the heel than at the toe.

Typically, 75% of the total cost of SAGD operations is related to generating steam, so there is an enormous upside to minimizing cumulative steam-oil ratio (CSOR). One way to improve the CSOR is to ensure an even distribution of the steam chamber along the entire horizontal wellbore. The introduction of ICDs in both the injector and producer can help equalize the injection and production flow along both wellbores, reducing the risk of premature steam breakthrough and/or water production from formations beneath the oil producer. Another substantial benefit of inflow control is the increased recovery coming from parts of the well closer to the toe and from lower permeability streaks, which might otherwise not be contributing. The overall end result is improved recovery at reduced cost.

The low cost of slotted liners has made them, to date, the completion of choice for SAGD wells. Many operators consider that the relatively shallow depth and short horizontal section of most SAGD wells does not justify the higher cost associated with stronger and more accurate sand control screens such as those offered by Reslink.  Higher quality screens provide better sand control, higher mechanical strength and longer life, but many SAGD operators have so far been reluctant to make the additional capital investment, which can be more than three times as much as slotted liners. However, the improved recovery enabled by ICDs can make longer horizontal sections more economical and justify the benefits of better screens. Furthermore, the CSOR and recovery improvements attributable to ICDs can easily recover the incremental cost of higher quality screens—possibly within months—and decrease the risk of a premature steam breakthrough or coning. Better sand control also provides additional savings by reducing wear, and thus extending the life of downhole equipment such as electric submersible pumps (ESPs) and upper equipment.

Some benefit can be gained through varying the density of slots in the slotted liner—less slots at the heel, and more at the toe. However, this crude system has generally been found to be inadequate for regulating flow. It is not as effective as ICDs at equalizing the reservoir inflow along the entire length of the wellbore.

ResInject

Schlumberger combines its Resflow* ICDs with wire-wrap sand screens to create a production management system that intelligently integrates sand control and flow control in a versatile, simple and robust solution. Screens are wrapped on unperforated base pipe. Each screen joint is equipped with a ResFlow ICD housing. Fluids enter the screen, and flow between the screen jacket and base pipe into the ICD housing and through ceramic nozzles into the screen base pipe. A pressure drop is achieved across the nozzles. This pressure drop, based on the Bernoulli principle, is independent of fluid viscosity, and so no adjustments are required when water cut (or GOR) increases. The “sister” tool—the ResInject* device—does the opposite in injection wells; distributing injection fluids along the entire well section. Injection and production systems have slightly different configurations: to avoid erosion, the nozzles in an injection control device are placed in a ring around the base pipe directing the fluid flow longitudinally to the base pipe. 

Schlumberger has built considerable experience using the ResFlow system in conventional oil production and water injection wells and is currently performing an extensive research program to evaluate nozzle performance with steam. This includes theoretical fluid dynamic simulations and testing, using production information from several operators who are interested in the potential of the technology for heavy oil applications.

ICDs are being incorporated into the ECLIPSE thermal simulation tool to model the effects of adding ICDs into a reservoir over time. The NETool simulator is used to compute multiphase fluid inflow and outflow between the wellbore and the reservoir. This enables a quick qualitative “snapshot” of how the reservoir will behave with and without ICDs in a variety of scenarios. It can also be coupled with ECLIPSE software to extend the predictions over time.

Schlumberger is also investigating how to configure the ICD nozzles to provide the most efficient warm-up and circulation for SAGD operations. For the first few months of a SAGD operation, steam is circulated at relatively low volumes, typically 50 m³/day, to heat the formation. Once the heavy oil or bitumen becomes less viscous, steam circulation progresses to become steam injection, and as the steam chamber expands, the amount of steam is gradually increased to rates around 1,000 m³/day after about 1 year. Dynamic control systems are being developed to enable the ICDs to effectively manage these variable flow rates. Engineering activities are also ongoing for optimizing ICD nozzle injection configurations for vapor extraction (VAPEX), a non-thermal recovery method that involves injecting vaporized solvents.

Report Concludes PTTEP, Regulator at Fault for Montara Spill

Rigzone Staff

PTTEP Australasia (PTTEP AA), a subsidiary of Thailand-based operator PTT Exploration and Production (PTTEP), and the Northern Territory Designated Authority are both at fault for the Montara oil spill, the largest spill to occur offshore Australia in over 20 years, the Australian government concluded in its Report of the Montara Commission of Inquiry and a draft Government response released Nov. 24.
The Inquiry was set up to investigate the likely causes of the uncontrolled release of oil and gas from the Montara Wellhead Platform in the Timor Sea on Aug. 21, 2009 and make recommendations to the Government on how to prevent future incidents. The inquiry found that the blowout was likely caused by defective installation of a cemented shoe in the casing of the H1 well in March 2009, which was intended to serve as a primary barrier against a blowout.
The pumping of displacement fluid beneath the float collar, which resulted in over-displacement from the casing shoe track and the area outside the casing shoe, also contributed to the blowout by weakening the cemented shoe's integrity as a barrier. PTTEP workers and Atlas workers both onshore and offshore failed to recognize that a wet shoe had been created from cementing operations and to test the cemented casing shoe. Deficiencies in PTTEP's management system for communications and failure to assess risk also were noted as contributing factors.
A test would likely have confirmed the unreliability of the cemented casing shoe as a barrier, allowing for remedial action that would have prevented the blowout. Other factors that may have contributed to the blowout include using an incorrect volume of tail cement in cementing operations. PTTEP also failed to install a casing pressure containing anti-corrosion caps (PCCC) on the 13-3/8 casing string on the H1 well and removed a 9-5/8 inch PCCC and failure to reinstall another PCCC on the 9-5/8 casing string in August 2009. These actions left the well without a secondary barrier against a blowout.
According to the report, the designated authority, the Northern Territory Department of Resources, should not have approved the Phase 1B drilling program for the Montara field in July 2009, and also adopted a "minimalist approach" to its regulatory responsibilities. The way the regulatory conducted its responsibilities gave little chance of discovering PTTEP AA's poor practices. "In this case, the regulatory dog did not bark," the report said.
The Report contains 100 findings and 105 recommendations, which have implications for governments, regulators, and the offshore petroleum industry. The Government proposes accepting 92, noting 10, and not accepting three of the Report's recommendations.
Outlining the Government's draft response, Minister for Resources and Energy Martin Ferguson noted that it provides a comprehensive plan to tackle head on the tough policy challenges posed by the Montara incident.
"The fact is that we were lucky with Montara – no lives were lost, there were no serious injuries and the quick, coordinated response from governments, regulators and industry meant that the impact on the marine environment was minimal," Minister Ferguson said.
"We can't just turn our backs on this industry – it is too important to Australia's economic and energy security. What we can do – working together – is make Australia's offshore safety regime the best and safest in the world."
Ferguson said the report recognizes that while there is room for some improvements, the nation's regulatory regime is effective. "At the heart of this matter is the failure of the operator and the failure of the regulator to adhere to this regime. If either - or preferably both – PTTEP AA or the Northern Territory Designated Authority had done their jobs properly and complied with requirements, the Montara Blowout would never have happened.
The minister said the government would next consult with industry and other stakeholders to form the Government's final response. "A key aspect of this will be the Government's intention to move toward a single national offshore regulator – consistent with the Report's recommendations."
The Government will also move to legislate the polluter pays principle and the requirements for environmental monitoring, further strengthening environmental safeguards.
"I am confident that by working methodically and diligently through the implementation of the remaining recommendations we will achieve a result that benefits all and maintains the industry's social license to operate."
In a statement released today, PTTEP said its subsidiary PTTEP AA has been working on an Action Plan over the past 12 months to prove PPTEP AA's capability to be an operator in Australia. The key elements of the Action Plan covers the improvement of the SSHE management system; development of a drilling and a competency management system; and the interfaces between PTTEP Headquarter in Bangkok and PTTEP AA in Perth.
Some elements of this Action Plan have been accomplished or are in progress. PTTEP noted that the clarification of well integrity barriers of the Montara Wells has already been certified by the Australian authorities, and the review of PTTEP AA Drilling organization to improve efficiency and safety is almost complete.
Anon Sirisaengtaksin, President and CEO of PTTEP said, "PTTEP is confident that PTTEP AA will continue its development of Montara since we have developed the Action Plan and implemented it for 12 months. We regularly updated its progress to the Australian Government. We therefore reaffirm our confidence that this extensive implementation can regain the Australian Government trust in PTTEP AA capability as a prudent Operator with International best practice. We also commit to continue our investment in Australia in long term."

Australia rebukes Thailand's PTTEP to tighten oil regulation after massive oil spill

Thai state oil company announced Tuesday it will buy 40% of Statoil’s Canadian oilsands project for $2.3B US

 

 

 

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A handout photograph shows the West Atlas oil rig and Montara well head platform on fire before the relief operation to pump heavy mud into the well was completed, off the northwest coast of Australia, in the morning of Tuesday, Nov. 3, 2009.

CANBERRA - Australia plans to tighten regulation of offshore oil exploration and review projects run by Thailand's PTT Exploration and Production after the nation's worst offshore oil spill last year.
An oil rig operated by the Thai company's Australian subsidiary caught fire off northwest Australia in August 2009 and spewed oil and condensate from the Montara wellhead for 74 days before it was stopped.
"Widespread and systemic shortcomings in PTTEP Australasia's procedures were a direct cause of the loss of well control," Resources Minister Martin Ferguson said on Wednesday as he released a report into the spill.
Ferguson's comments sent PTTEP shares 3.6 lower to a more than three week low against a slightly lower broader market.
On Tuesday, the Thai state oil company announced it is buying a minority stake in Statoil's Kai Kos Dehseh oilsands project near Fort McMurray.
The environmental impact of the spill and a leak in the Gulf of Mexico of a well operated by BP Plc have thrown a spotlight on drilling off Australia's coast, with environmentalists calling for a suspension of new projects.
The report blamed PTTEP Australasia for failing to follow safe practices, including having effective fail-safe mechanisms that would have prevented a blowout and fire on the platform.
Only one of two planned secondary well-control barriers was installed, the inquiry found. But it also blamed a minimalist approach by the Northern Territory area regulator, which meant authorities had little chance of discovering poor practices.
The incident caused no deaths, but Ferguson said he had ordered a review of PTTEP's Australian operations which could lead to cancellation of its exploration and development licence.
The review would be completed this year.
"The outcome of this process will assist me in forming a view as to whether the deficiencies in PTTEP Australasia's procedures as identified by the commissioner relate only to the Montara oilfield, or PTTEP's general performance," Ferguson said.
COMPANY SAYS FOLLOWED PLAN
The company operates seven exploration permits, five production licences, seven retention leases and has interests in other permits which it does not operate.
"We're confident that we did everything according to plan," PTTEP chief executive Anon Sirisaengtaksin told Reuters, adding the company was now awaiting the government's assessment of its Australian projects.
Ferguson said he had also accepted an inquiry recommendation that Australia establish a single national offshore exploration regulator, with new legislation setting it up by January 2012.
"Montara was the first major loss of well control in 25 years of safe offshore petroleum operations," he said. "We can't just turn our backs on this industry. It is too important to Australia's economic and energy security."
Environmental group WWF said the oil slick had killed sea life and damaged the fishing industry in neighbouring Indonesia and East Timor.
PTTEP, which on Tuesday announced a $2.3 billion deal to buy into a Canadian oilsands project, is being pursued by Indonesia's government for $2.4 billion in compensation over the spill. The company recorded about $319 million in expenses for the Montara cleanup and rig-damage costs during the second half of last year.
Australia was working closely with the United States in the wake of Montara and the catastrophic blowout on the Deepwater Horizon project in the Gulf of Mexico, Ferguson said, and would hold a conference next year to talk about industry changes.

Read more: http://www.calgaryherald.com/business/Australia+rebukes+Thailand+PTTEP+tighten+regulation+after+massive+spill/3878907/story.html#ixzz16HBCZSXH

Report blames rig operator for Australian spill

By ROD McGUIRK

CANBERRA, Australia
A Thai-owned oil rig operator could be banned from Australian waters after a government report on Wednesday blamed it and a lax regulator for Australia's worst ever oil spill that stained the coasts of Indonesia and East Timor last year.
Australia also plans to tighten regulations on its rapidly growing offshore oil and gas industry in response to the 11-week Montara oil field spill that began on Aug. 21 last year and the more disastrous explosion and spill at BP's Deepwater Horizon rig in the Gulf of Mexico that killed 11 workers on April 20.
Resources Minister Martin Ferguson told Parliament he is investigating whether deficiencies in procedures at the Montara oil field that was operated by a unit of Thailand's PTT Exploration & Production Plc. reflected the company's "general performance as an operator."
The investigation, to be completed this year, will help determine what action should be taken against the company which could include cancellation of its oil and gas production rights, Ferguson said.
The Thai company's Australian unit, PTTEP Australasia, holds five production licenses in Australia's waters including Montara but is not currently producing oil or gas from any of them.
The company would require new regulatory approval before it could resume production at Montara and has not yet made such an application.
PTTEP Australasia issued a statement Wednesday acknowledging the "deficiencies" identified by the report and said all managers and supervisors involved in the Montara drilling have been "removed from their positions."
It said it was implementing reforms that address the technical and governance problems identified in the report to "ensure the incident which occurred at Montara is never repeated."
Ferguson said the company could yet be charged over failure to comply with regulations and for endangering the 69 workers at Montara.
Australia's burgeoning offshore oil and gas industry oil earned energy companies 35.6 billion Australian dollars ($35 billion) in oil and gas revenue last year.
More than 400 barrels of oil a day flowed from the Montara well in the Timor Sea and stained the coasts of Indonesia and East Timor before mud pumped through a relief well shut off the deepwater spigot 11 weeks later.
Ferguson said there were similarities with the Gulf of Mexico disaster in that "you ... find, to a large extent, the same human failures."
Australia had worked closely with the U.S. government in formulating its response to both disasters, he said.
Halliburton, a Texas-based global oil field services provider, was the contractor that provided cement seals for both the Gulf of Mexico and Montara wells.
The Montara spill occurred because the underwater cement barrier designed to prevent oil blowouts failed.
But the government report found it would not be appropriate to criticize Halliburton.
Halliburton reported to PTTEP Australasia "a major ongoing problem" with the cement barrier, yet the rig operator's senior supervisor signed off on that report with the annotation: "good job well done," the government investigation found.
A U.S. national commission will report on Jan. 12 next year on the causes of the Gulf of Mexico disaster.
PTTEP paid $319 million for the clean up. Ferguson said the government planned to change the law to remove any doubt that companies responsible for any future leaks would be made to pay.
Indonesians were still seeking compensation, Ferguson said.
Environmental group WWF Australia reported that thousands of dead fish and clumps of oil had been found drifting near Indonesia's coastline more than two months after the well began leaking.
"PTTEP Australasia did not observe sensible oil field practice at the Montara field," Ferguson said.
"Other findings include that the widespread and systematic shortcomings of PTTEP Australasia procedures were a direct cause of the loss of well control," he said.
Ferguson said the field's regulator, the Northern Territory Department of Resource, was "not a diligent regulator and its minimalist approach to its regulatory responsibility gave it little chance of discovering these poor practices."
"Well control practices approved by the regulator would have been sufficient to prevent the loss of well control," he said. "However PTTEP Australasia did not adhere to these practices or its own well construction standards."
Ferguson said the government planned to replace state regulators with a national regulator of the offshore energy industry by January, 2012.
Ferguson said the industry did not have a "cowboy culture," with Montara the first major leak in Australian waters in 25 years during which more than 3,000 wells had been drilled.

Australia blames Thai oil rig firm for Timor Sea spill

Engineers tried to stop the leak for 10 weeks before succeeding

An Australian government inquiry has blamed the country's worst offshore oil leak on the rig's Thai owner.

The report said PTTEP Australasia, a unit of Thailand's PTT Exploration and Production, had failed to observe "sensible" practice.
The Australian Resources Minister told parliament the Thai firm should have its operating licence reviewed.
More than 400 barrels of oil a day spewed into the pristine Timor Sea off Australia's north coast for 10 weeks.
The oil hit the coast of Indonesia and East Timor.
Oil began leaking from the West Atlas rig and Montara wellhead platform north of Australia last August.
It was plugged on a fifth attempt in November 2009, after a slick had spread an estimated 90,000 sq km (35,000 sq miles).
Loss of control "The widespread and systematic shortcomings of PTTEP Australasia's procedures were a direct cause of the loss of well-control," Mr Ferguson said.
"Well-control practices approved by the regulator would have been sufficient to prevent the loss of well-control, however PTTEP Australasia did not adhere to these practices or its own well-construction standards," he said.
The company paid $390m (£245m) for the clean-up but the minister said he thought relevant laws needed to be strengthened to make absolutely clear that companies would be held responsible for any future leaks.
He also criticised the Australian government regulator which had pursued a "minimalist" approach in handling the emergency, saying the entire incident had been avoidable.
There was no immediate response from PTTEP.
The government ordered the inquiry while environmentalists have expressed concerns about the waters off Australia's north-west coast, which are home to whales and dolphins.