Components of Production Sharing Contract in Kenya

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Licensing of petroleum exploration blocks, is governed by the
Petroleum (Exploration and Production) Act Chapter 308 of the Laws of
Kenya. All contracts are based on a Model Production Sharing Contract
(PSC) issued as a schedule to the Regulations issued under Section 6 of
the Act.
The signed Production Sharing Contracts have the following key component:
a) Signature Bonus: This is a one-off fee payable to
the Government by the Company upon signing of an oil exploration
contract. It depends on the area of the Block and previous data acquired
on the Block. Signature Bonus negotiation came into effect in 2009. In
block 12B for example the signature bonus paid was $300,000 according to
JV partner Australian Swala Energy. In block L27 operated by CAMAC
Energy the signature bonus paid was $310,000 according to the PSC available on this website.
A surface fee is also payable and is calculated on
the basis of the surface area of the Contract Area on the date those
payments are due. In Block L27 the amount set is $5 per square kilometre
per annum during the Initial Exploration Period, $10 per square
kilometre per annum during the first Exploration Period, $15 per square
kilometre per annum during the second Exploration Period and $100.00 per
square kilometre per annum during the Development and Production
Periods
b) Work programme and expenditure: The contractor
guarantees the agreed work programme and minimum expenditure. Initially
this was pegged at 15% bank guarantee and 85% parent company guarantee.
However, the Ministry has improved this and now the newly licensed
companies are required to provide a 50% bank guarantee and 50% parent
company guarantee.
This is to make sure that the companies proceed with their work
progamme expeditiously as agreed with the Government and that incase of
non-performance, the Government can liquidate the guarantees more
easily. For small companies (based on their annual turnover criteria),
they are required to post 100% bank guarantee. It is important to note
that upstream petroleum operations are capital intensive and the
Government entirely relies on the oil companies to invest their risk
capital in the operations.
In addition, this risk capital is raised through equity. This is
contrary to investment in mid stream and downstream petroleum segments
which can be funded by debt
c) Cost oil: This is usually the negotiated
percentage of total crude produced for recouping of investment costs
incurred by the contractor in exploration and production of oil in a
given field. It is normally up to 60% of all the oil produced in a field
for about five years.
d) Profit oil: This is the remaining oil after
deducting cost oil and is shared between the Government and the
contractor. For example, when a field is small the Government take is
50%. As the production increases, the Government take can increase up to
78% of the total profit oil.
e) Windfall profit: Where oil prices are higher than
the negotiated threshold, the Government creams off contractors take
above the threshold crude oil prices by 26%.
f) Exploration phases – there are three exploration
phases of two years each, the initial period, first additional period
and second additional period. For ultra deep offshore blocks, the
initial period is extended to three years due to extra logistical
challenges in the deep water acreage.
g) Relinquishment – is 25% of the area of the block for each period
The PSC also has the license rental fee and training fee included. In
Block 12B for example the license rental fee is set at $40,000 during
the first year (2012-2013) and $80,000 during the second year, training
fee is $100,000 per annum. During the first production phase the
training fee is set at a minimum of $200,000 in Block 1 PSC with Lion
Petroleum.
Check out PSC’s for the various East African countries namely Kenya, Uganda, Tanzania, Mozambique available on our website.
Additional Source: Ministry of Energy & Petroleum Website

Oil prices ‘could fall further’

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Oil prices may have further to fall despite stabilising in
recent months – and even beginning to rise modestly – because of a
massive oversupply the International Energy Agency (IEA) has said.
The IEA said lower oil prices were likely to last well into 2016.
The agency added the world oil market was unable to absorb the huge volumes of oil now being produced.
It follows the massive drop in prices which started last summer.
The price of Brent crude fell sharply last year from $115 a barrel in June to $45 a barrel in January.
The current price of Brent crude is $59 a barrel.
The fall in prices has led oil firms to cut back investment in
exploration, while North Sea oil has come under significant pressure.
All seven major global oil firms have also reported a year-on-year declines as a result of lower oil prices.
‘Oversupply’
Only last month the Office for Budget Responsibility
(OBR) forecast North Sea oil and gas revenues would fall to below 0.1%
of GDP over the coming decades.
It said the tax take from North Sea oil and gas had already fallen by 80% in the last three years.
“The oil market was massively oversupplied in the second quarter of
2015, and remains so today,” the IEA said in its monthly report.
“It
is equally clear that the market’s ability to absorb that oversupply is
unlikely to last. Onshore storage space is limited,” it said, adding:
“Something has to give.”
“The bottom of the market may still be ahead.”
Core members of the Organisation of Petroleum Exporting Countries
(Opec) have continued to produce the same level of oil in the past year
despite falling oil prices in an attempt to regain market share.
US
oil production has also soared in recent years, as fracking – or the
process of extracting oil from shale rock by injecting fluids into the
ground – has revolutionised oil production in the country.
Opec’s response to the fall in prices was to refuse to cut
production. Many Opec nations are able to tolerate a lower oil price
despite losing money.
Record
For other nations such as Russia the lower oil price is doing substantial harm to economic growth
Last
month, official figures showed the impact of international sanctions
over Russia’s continued involvement in east Ukraine and the lower oil
prices had led to a 4.9% contraction in the Russian economy in the 12
months to May.
The IEA said Opec crude oil production rose 340,000 barrels per day
(BPD) in June to 31.7 million barrel as day, a three-year high, led by
record output from Iraq, Saudi Arabia and the United Arab Emirates.
It said Saudi Arabian crude oil supply rose 50,000 barrels per day to
a record high of 10.35 million BPD in June, while Iraq crude oil output
surged 270,000 BPD in June to its highest-ever rate of 4.12 million
BPD.
However, increases in production have come just as demand for
oil in economies across the world from Europe to China – the world’s
second-largest consumer of oil – has slowed.
The IEA trimmed its forecast for global oil demand growth this year
slightly to 1.39 million BPD and said it expected global demand growth
to slow to 1.2 million BPD in 2016.
The agency added non-Opec supply growth was expected to grind to a
halt in 2016 as lower oil prices and spending cuts take their toll. It
forecast zero growth in non-Opec oil supply in 2016 after an increase of
1 million bpd in 2015.
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The Ministry of Energy & Mineral Development has announced that
the “Uganda International Oil & Gas Summit” (UIOGS) will be held in
Kampala on 16-17 September 2015.

With a first-class conference programme led by Government, Public
Sector and Private Sector industry leaders; the Summit marks an
important point on the global calendar.

UIOGS is held under the Patronage of Eng. Irene Muloni,Minister of
Energy and Mineral Development; and will be used by the Ministry as its
official platform for meeting international companies and presentation
of the multitude of energy projects presently ongoing or planned for in
Uganda.

Uganda has much to offer the global oil and gas community and 2015 is
an exciting year as the country moves towards commercial production.
Uganda is blessed with its natural resources and now has an estimated
6.5 billion barrels of oil in place, a high drilling success rate of
85%, advanced refinery plans, vast acreage of underexplored areas rich
in hydrocarbons and much to look forward to with the new licensing
rounds.

The UOGS programme will provide an invaluable insight into all the major issues, challenges and opportunities including:

  • Focus on the licensing rounds and new opportunities
  • Update on existing fields and exploration success
  • Financial and regulatory frameworks
  • Uganda’s Refinery Project – 60,000 bpd by 2020
  • Move to commercial production
  • Supporting the oil and gas industry through a skilled workforce and local content
  • Infrastructure developments to support oil & gas
  • How can a successful oil industry support our drive towards rural electrification

The Ministry of Energy & Mineral Development will be using the
UIOGS platform to actively engage with allits partners and suppliers
from around the world. The services of the renowned market leaders for
oil & gas conferences; Global Event Partners have been engaged to
work alongside domestic experts Image Care to ensure that UIOGS is a
first-class event that puts Uganda firmly on the global map.

UIOGS is a two day conference that will be held at the Kampala Serena
Hotel on 16-17 September 2015. The programme will be opened by Hon. Eng
Irene Muloni and will feature more than 30 Government officials,
Company leaders and Industry experts gathered from Uganda, the region
and throughout the world to give Uganda a truly global platform.

New petroleum producers survey policy options in wake of oil price slump

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Countries seeking to develop newly-discovered petroleum resources are
facing a fall in global oil prices, with competition from the ‘shale
gas revolution’ in the United States, as well as renewable energy
sources.
At a New Petroleum Producers Discussion Group in Tanzania, organised
by Chatham House and co-sponsored by the Commonwealth Secretariat,
authorities from more than 20 countries met this week to find solutions
to these and other shared challenges.
The four-day forum from 30 June to 2 July, at which a set of Guidelines on Good Governance for Emerging Oil and Gas Producers was
released, was attended by government ministries and national oil
companies from Belize, Guyana, Kenya, Mauritius, Mozambique, Jamaica,
Seychelles, Trinidad and Tobago, Tanzania, and Uganda, among other
nations.
“In the midst of the oil crisis there is less capital available for
investment,” commented Michael Mwanda, Chairman of the Tanzania
Petroleum Development Corporation, which hosted the meeting in Dar es
Salaam. “Some projects which were pegged on a high oil price are now
becoming uneconomic and difficult to operate.
“We need to learn from each other and share experiences on how to
reduce costs, operate efficiently and become more competitive,” Mr
Mwanda said.
Addressing the forum, Ekpen Omonbude, Natural Resources Adviser at
the Commonwealth Secretariat, remarked: “This price decline has
necessitated a critical look at strategies to manage petroleum
resources, from development programmes to responsible wealth management,
to ensure benefits for future generations.”
Dr Omonbude stressed that while the slump in the price of oil – from
over US$100 a barrel in 2014 to around US$60 today – presents immediate
challenges, these can be mitigated through the adoption of flexible
fiscal regimes, increased economic diversification, the development of
good governance regimes and revenue transparency.
“Our mission is clear – to help position our member countries to
realise the potential of their resource wealth as a driver of
sustainable development and economic prosperity,” the Commonwealth
representative said.
The New Petroleum Producers Discussion Group was
established in 2012 to help countries think critically about policy
options available either during the first steps of exploration and
development or when restructuring governance arrangements. Options
include setting up regulatory institutions and drafting regulations and
laws that encourage investment, while balancing the needs of society and
environmental protections.
This week marked the first time the discussion group has met outside
London and included a final-day national seminar for representatives of
Tanzania’s oil and gas sector. Co-sponsors of the initiative include the
Natural Resource Governance Institute and the Africa Governance
Initiative.
The Guidelines for Good Governance in Emerging Oil and Gas Producers,
a synthesis of proposals put forward at each discussion group, seek to
guide national authorities to pursue policies which follow good
practices, but which also respond to national contexts.
Dr Valérie Marcel, Associate Fellow at Chatham House, principal
author of the guidelines, said: “The emergence of shale oil and new
renewable technologies offer opportunities and challenges. How the
emerging producer is affected and will respond is what we have been
debating. One of the main issues is how to adjust to a low price
environment, asking what impact is this going to have on licensing terms
and the ambitions of national oil companies.”
She added: “Emerging producers are thirsty to learn from their peers
about what has worked elsewhere and what advice to give. More
established producers want to know whether they are doing things right
and what pitfalls they should avoid. This is a really important learning
process.”
During the forum, participants exchanged experiences on how to
attract investment while preserving long-term national interests,
managing expenditure plans as well as ways to guard against abuses and
fraud in contracts and licensing. Training sessions focused on involving
local suppliers in supply chains, the design of fiscal systems and new
information tools.

Eddy Belle, Chief Executive of PetroSeychelles, the national oil
company of Seychelles, said: “[Petroleum] is a very dynamic business –
there is new technology coming in and new ways of doing things. What
Chatham House is doing with the help of the Commonwealth Secretariat is
getting people together so you have the chance to learn from the
mistakes as well as the successes of others.”
Bashir Hangi, Communications Officer for Uganda’s Petroleum
Exploration and Production Department, commented: “Such a forum helps us
a lot as emerging producers. We peer review ourselves, and our people
go home with a lot of advice. One piece of advice I would share is that
you cannot ignore your stakeholders – civil society, academia and
communities where there are operations. They should not be taken for
granted; they should be brought on board and be involved in the
management of the resource.”
Anthony Paul, Managing Director of the Association of Caribbean
Energy Specialists, said: “Oil and gas resources give opportunities to
deepen industrialisaton, providing power and access to better lighting,
heating and cooking facilities as well as petrochemicals and
fertilisers. There are also benefits from developing the services
industry. What strikes me most is that all countries want the same
thing: they want the resource to benefit their citizens.”

See How Oil and Gas Industry Works

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Today, we can learn
that even though you may be buying Chevron Gas, Chevron may not have much to do
with it. Welcome to our overview of the oil and gas vertical. You know most
people think they know the oil and gas industry, but they really don’t. So
we’re going to see if we can give you some useful information and clear up some
common misconceptions. So most people think of companies like ExxonMobil and
just assumed they get oil in the ground somewhere in the world, ship that crude
in ExxonMobil pipelines to an ExxonMobil refinery, sell it in ExxonMobil gas
station. But guess what? That is absolutely wrong, that is not how this
industry works. This is how it works. 
The industry is composed of four main segments;
upstream, midstream, downstream, and service. Upstream is actually getting the
crude out of the ground. You often hear it called E&P or Exploration and
Production. This is upstream, this is upstream, this is upstream, this is
actually and FPSO. The next segment is midstream. Midstream is basically moving
that crude oil in natural gas. So midstream stuff such as pipelines,
supertankers, rail cars. Then, we move to downstream. Downstream is actually
the refinery, the refining manufacturing and selling of the products from crude
oil and natural gas. So downstream things such a refineries, retail loop
stations, fertilizer which is big product of petrochemical refining,
lubricants, motor oils, retail gas stations, and plastic which is another large
product of crude oil. Then, we move to the service companies. Service are
companies that actually provide manpower and help in services the oil and gas
industry, but they don’t produce any petroleum or petroleum products
themselves. So you have everything from the guys that out there designing the
rigs to the crew boats that move men and equipment back and forth to the actual
roughnecks that do the drilling, to the manufacturer of drill stem, and things
like subsea installations. Every bit of this is service. 
Then, you also hear
the word Super Majors or Combined. What is that? That are companies that do
everything; upstream, midstream, downstream, and some service. And right now in
2013, there’s only five of them. This is it. These are the five Super Majors.
So what does that mean? We’re going to talk you through literally from cradle
to grave a drop the crude oil to the point where it gets into the gas tank of
your car. So, the US government auctions off a block of land the highest
bidder. After checking my last auction facts in the Gulf of Mexico, $2 billion
somebody paid for rights to drill on a piece of land for ten years. That’s it.
Think about that for a second. You write a check for $2 billion to have ten
years to make that money back and hopefully some profit, but there’s no
guarantees. So this case it was BP who spent that $2 billion for a deep Gulf of
Mexico lease.
 BP then needs to drill, right? BP does not have its own drill
rigs. BP contracts a drill rig basically rents it from companies such as
Transocean. That drill rigs needs to be staffed by people, so you have
companies such as Halliburton and Baker Hughes to actually help them operate
that drill rig. The crude that gets produced on the drill rig needs to be
transported. Guess what? BP puts out to open bid to all the different
industries all the different companies in the world who will move this crude
oil at the bets price. In this case, it was a supertanker and the win was won
by Chevron. So Chevron has the crude oil in supertanker and it’s in transport
to refinery, but halfway there, ConocoPhilips on their trading floor buys that
crude and it turns around and sells it for few cents profit per barrel. And it
was sold to Shell refinery who then refines that fuel at a profit, ships it in
Kinder Morgan pipeline to a 76 gas station as owned by who? No, not 76. It’s
owned by one of your neighbors which is called the Jobber. So there you go.
There it is from literally getting out of the ground into being burning your
gas tank as a fuel. And you look at how many different people are involved and
how many different layers of profits are involved and this is a very complex
industry. So hopefully this helps you understand at least at a high level what
goes on in the oil and gas industry.

This is How To Drill Oil and Gas Well

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          Now, during this lesson, we will see how to drill them.
1. First of all, let’s see how to describe the subsurface characteristics, in order to plan the design of the future well and to define the phases of the drilling job.
2. Then, we’ll describe the drilling system, and how the driller can manage the drilling process safely.
During the exploration phase a well is needed to confirm the presence of oil or gas in the reservoir.
Some appraisal wells are needed for the delineation process.
Moreover, at the end of the reservoir strategy study, a reservoir model defines how to develop the field, and, more particularly, where to drill the wells and the contribution of each of them to the production plateau.
The role of the driller is to build these wells required for the field development.
A well is an expensive item. It must be carefully studied and planned before being drilled. The well preparation phase involves coordinated work between geoscience engineers and drilling/completion engineers.
How to design a well?
In order to set up the drilling program, the driller needs to know the location of the rig, where the well has to enter the reservoir, the trajectory of the well in the reservoir for a good connection between the well and the reservoir, and the formations to be drilled. Let’s detail the description of the subsurface.
For each formation to be drilled, there are 2 characteristics that need to be known accurately:
1. the pore pressure
2. and the fracture pressure.
The pore pressure is the pressure of the fluid within the grains of the rock. It depends on the depth of the formation and on its nature (sandstone, shale, …).
The fracture pressure corresponds to the minimum pressure to be applied on the rock to generate a fracture.
When the formation is drilled, the well is full of a fluid: the drilling mud, which is directly in contact with the rock, and applies a pressure on it: Pmud.
The mud pressure depends on the depth. One of the roles of the mud is to maintain the interstitial fluid within the rock, in order to avoid a kick.

During the drilling process, the mud is in contact with the rock, which contains a fluid within the grains.
A fluid always flows from high pressure to a lower pressure. If the mud pressure is higher than the pore pressure, the formation fluid cannot enter the well. It remains in the formation and there is no risk of blowout.
During the drilling process, the mud is in contact with the rock, which contains a fluid within the grains.
The mud pressure has to be lower than the frac pressure, in order to avoid the rock being fractured. To conclude, keep in mind that the mud has to be designed so that the mud pressure belongs to the interval between the pore pressure and the frac pressure. This interval is called the mud window.
Both Ppore, in red, and Pfrac, in blue, can be plotted on a (pressure/depth) graph.
The mud pressure has to be in the yellow zone, which is called the mud window. For each lithology to be drilled, the mud has to be well adapted to its characteristics. The well is therefore drilled in different phases, each phase corresponding to a new mud to be used.
At the end of a phase, a casing is installed and cemented to protect the well from the formation already drilled and to finalize the well walls.

The definition of each of these phases is called the well design.
A typical well design is as follows:
1. The first tubular is the conductor pipe installed by the civil engineer before the rig
arrives on site.
2. The next phases are drilled using the rotary drilling technique.
3. The surface casing maintains the unconsolidated surface formations and protects the groundwater.
4. The intermediate casing protects the well from the formations or fluid which could prevent the drilling process from continuing.
5. The last casing is the production casing which allows the reservoir to be isolated.
6. During the last phase the well enters the reservoir.
When a well is an exploration well, designing is much more difficult , due to a lack of measurements and information to describe the subsurface. The mud window is not accurately known. Such uncertainties have to be taken into consideration in the drilling process.
When a well has to be drilled in a new region, there are many uncertainties about the data, including that related to the pore and frac pressure profiles. On the contrary, when a development well is planned, it benefits from data from the surrounding wells already drilled. In this case, the pressure profiles are well known, and the uncertainties are lower.
Let’s mention that the trajectory of a well can be vertical, deviated, or horizontal. The choice of the trajectory depends on the location of the rig, the location of the target of the well when it enters the reservoir, and the trajectory of the drain in the reservoir itself. These two last data are defined and given by the reservoir engineer to the driller.

How a well is drilled in practice? Mechanically, a vertical force applied on the drilling bit (the weight on bit), together with a movement of rotation, generates down to the bit the power necessary to destroy the rock. A hook hangs up the drill string, which is composed of several tubulars screwed together, and, at the bottom, there is a drilling bit.
Both the weight on bit and the rotation per minute, which is given by the rotary table located at the rig floor, are controlled by the driller to maximize the rate of penetration of the bit.
Their optimization depends on several parameters, including the kind of rock to be drilled: the regulation of the hook height controls the part of the total weight of the drillstring applied on the bit, the rotation is often given by a rotary table located at the rig floor.
The mud circuit is combined to the mechanical part of the system.
Firstly, the pump sends the mud at high pressure through the discharge line, the stand pipe, the rotary hose and the top drive, into the pipes.
The mud flows in the drill string down to the bit and catches the small pieces of broken rock, the cuttings, to transport them up to the surface in the space between the drill string and the well walls.

At the surface, the cuttings, the sand and the silt are removed from the mud through shale shakers and other systems.
The mud can be sent to the tanks in order to be re-injected.
In order to control the well in case of blowout, a Blow Out Preventer is installed between the top of the well and the rig floor. This BOP stack is composed of an annular BOP and different rams able to close the well in case of emergency. The size of the BOP is adapted to the maximum pressure that can be encountered during the drilling process.

Wentworth Resources Raises $7.6 Million To Finance Tanzania�s Mnazi Bay Developments

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Wentworth Resources has announced that it has successfully raised
gross proceeds of USD 7.6 million (GBP 4.9 million, NOK 59.7 million)
with institutional investors and certain Directors and members of the
Executive Management through a private placement of 15,412,269 new
shares.
The private placement saw no discount to market price with the new
funds set to provide the Company with sufficient working capital beyond
its projected receipt of first cash flow for gas sales from its Mnazi
Bay concession.
This comes at a time when construction of the Government owned and
operated Mtwara to Dar es Salaam pipeline is complete and the
accompanying processing facilities are nearing completion with
pre-commissioning activities ongoing with delivery of first gas into the
new pipeline continues to be on track to commence in Q3 2015.
According to Wentworth Resources significant progress has been made
in recent weeks on advancing payment guarantee arrangements and the
Company is confident these will be completed prior to the delivery of
first gas to the pipeline.
The company said it had preferred the Private Placement as it
represented a quick and cost-effective method of raising funds necessary
to give the Company sufficient working capital until projected cash
flow from gas sales at Mnazi Bay commences.
FirstEnergy Capital and Stifel have been appointed as Joint Bookrunners in respect of the Placement.
According to Wentworth executive Chairman Bob McBean the Company
expects to start receiving cash flow from gas sales to the new pipeline
in Q4 2015.
“We are very pleased with the successful outcome of this raise which
provides the working capital we need prior to delivery of first gas. We
are confident that, with the support of our Partners and the commitment
shown by the Government, gas will be on stream in the coming months and
will be fully supported by an agreed payment guarantee arrangement. I
and the Board would like to thank our existing shareholders for their
continued support and welcome our new shareholders at an exciting period
ahead for Wentworth,” says McBean.
In March
Wentworth Resources announced that the Company has subsequently drawn
an amount of $5.6 million on an existing $20 million credit facility
with a Tanzania-based bank, TIB Development Bank Limited to finance
Mnazi bay concession developments including drilling of the MB-4 development well.
As per the last evaluation gas reserves within the Mnazi Bay
Concession in Tanzania, carried out by RPS Energy Canada Ltd put the value at $152.9 million after tax.
Marel et Prom is the operator at the Concession with 60.075 percent
interest through exploration and 48.06 percent through production while
the Tanzania Petroleum Development Corporation holds the remaining 20
percent.

Orca contracts shallow-water rig for Songo Songo offshore Tanzania

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DAR ES SALAAM, Tanzania – Orca Exploration Group has started the first phase of the Songo Songo development program offshore Tanzania.

This follows World Bank’s approval for International Finance Corp.’s (IFC) investment.

Orca has entered into a drilling contract with Paragon Offshore for
the use of its M826 mobile drilling workover rig and associated services
for the offshore phase of the Songo Songo gas field program.

The rig can operate in the shallow water operating environment around
Songo Songo Island, which Orca describes as “somewhat unique.” 
However, the company still needs to obtain certain regulatory and
contractual approvals related to certain aspects of the development
program.

Drilling should start between Aug. 1 and Sept. 21. The contract has a minimum 90-day duration.

Operations will likely include workovers (removal and replacement of
production tubing strings) on the existing SS‑5, SS-7 and SS-9 wells,
and drilling of one new well, SS-J. Orca has the option to drill a
further two wells, pending the outcome of the workovers.

Schlumberger Introduces Depth Domain Inversion Services

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Schlumberger petro-technical experts use the services to improve the
reliability and consistency of seismic structural and quantitative
interpretation in complex environments.

“Conventional seismic inversion in the time domain introduces
inconsistency between the seismic images and the rock properties,
especially where there’s a significant overburden, such as subsalt,”
said Maurice Nessim, president, Schlumberger PetroTechnical Services.
“With Depth Domain Inversion Services, customers receive more
information derived from seismic data for reservoir characterization.
This helps reduce uncertainty in complex reservoir environments, improve
the confidence in prospect delineation, reservoir properties and
volumetric calculations.”
Performing seismic inversion in the depth domain fully integrates the
inversion with the imaging products to improve the reliability of
estimating rock properties for reservoir characterization. This is done
by correcting for depth space and dip dependent illumination effects
during seismic amplitude inversion directly in the depth domain.
depth domain inversion services
Depth Domain Inversion Services have been successfully applied in
complex geological environments in North and South America. In the Green
Canyon area of the Gulf of Mexico, Schlumberger petrotechnical experts
used a Depth Domain Inversion workflow in a complex subsalt area that
was poorly illuminated.
Reverse time migration produced seismic amplitudes adversely
imprinted by the illumination effects. Executed in the Petrel E&P
software platform, the workflow improved structural and quantitative
interpretation, corrected illumination effects and provided a much
sharper reflectivity image for better event continuity, more reliable
seismic amplitudes and a higher fidelity acoustic impedance volume

Wentworth Resources Estimates $3.5m in Tanzania Monthly Gas Sales

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Wentworth Resources says it estimates that monthly gas sales in
Tanzania into new government owned pipeline Q3 2015 could reach an
estimated $3.5m monthly.

Initially Mnazi Bay will be the only supplier of gas in Tanzania into
new pipeline from 5 wells which will be producing in the field by Q3
2015 at initial volumes of 80 mmscf/d escalating to 130mmscf/d in 2016

Wentworth adds that the substantial cash flow generation is expected
to commence in Q4 with the plan being to reinvest cash flows into Mnazi
Bay and grow the business by maximizing production from existing
discovered gas fields to meet the growing demand for gas in Tanzania and
examining more drill exploration prospects.

Already the company has identified six exploration targets with 1.5
Tscf (614 Bscf Wentworth’s share) unrisked P50 Prospective Resources
with all costs recoverable against existing and future production within
the Concession

On the way forward Wentworth says it will continue to focus on East
Africa onshore and near shore,  pursue acreage along pipeline route in
Tanzania, evaluate Tembo-1 discovery Onshore Rovuma for potential
appraisal and Expand operations in East Africa.

As per the 17 year term gas sales agreement with the government the
government is responsible for transportation and processing costs and
payment guarantees are nearing finalization.

As per the last independent evaluation
of its gas reserves within the Mnazi Bay Concession in Tanzania,
carried out by RPS Energy Canada Ltd the value of Wentworth Resources at
Mnazi Bay is set at$152.9 million after tax. RPS Energy also placed the
value of the entire field at 443Bscf (2P) equivalent to 73.8MMboe.

Wentworth holds a substantial 31.94 percent withholding interest in production equivalent to 141.5Bscf (2P) gross reserves.

In October 2014
Wentworth Resources estimated its projects in Tanzania would make $20
million for first full year and $140 million over first 5 years of
production net of operating and on-going development costs according to
the October 2014 presentation.

Wentworth holds 31.94% in the production stage down from 39.925%
 while the operator and  Mnazi Bay Partner Maurel et Prom holds 48.06%
down from 60.075% after the Tanzania Petroleum Development Corporation
backed in to take 20% of production interests.