All articles in the Others Section:


Botswana’s Coal To Power Plant Gets Ahead

While other miners and hopefuls find themselves forced into delays and cutbacks because of funding woes and low commodity prices, Toronto-based CIC Energy is pressing ahead with plans to build a coal mine and power station at its Mmamabula project, in Botswana. The firm has now completed a mine plan for the 4.5Million tons a year coal mine and announced the selection of Chinese mechanical and electrical equipment manufacturer Shanghai Electric as the preferred engineering, procurement and construction (EPC) contractor for the initial power plant.

The company aimed to have submitted a mining licence application to the government of Botswana by end of 2008, and should begin the procurement process for the development of the mine and the associated infrastructure in 2009.

A turnkey EPC contract will be awarded for the manufacturing and erection of the wash plant and discussions are “well advanced” with the preferred contractor, the company reported. The coal crushing system and associated coal conveyor system will also be tendered for a turnkey EPC contract, and the procurement process for the equipment required for steady state mining will get under way in early 2009.

T h e M m a m a b u I a coalfield contains an estimated 2.93billion tons of coal in the measured and indicated categories, plus 34-million tons of inferred resources.

Despite a debilitating shortage of electricity supply in the Southern African region, the company had to abandon plans earlier in 2008 to award contracts for a 2,400-MW project, after its off takers, South Africa’s Eskom and the Botswana Power Corporation, were unable to agree on assuming risk for the project in order to meet lender requirements.

However, the firm now expects to sign 30-year off take agreements with both utilities by mid-2009, by which time it should also have a funding agreement in place.

The capital cost to build the mine and power station has been estimated at $3billion, and the company is in talks with development finance institutions, South African commercial banks and a Chinese export credit agency, which is being targeted for a “large segment” of the project funding.

CIC is not concerned by the impact of the financial crisis on the company’s ability to raise funds, because the lenders that it was targeting had not been affected as much as commercial banks.

In the meantime, the firm will fund early infrastructure work on the project from its $89-million treasury.

It has already begun a formal tender process for early work like site clearing, earthworks, roads, water-supply and waste water treatment facilities, and plans td use local contractors in Botswana as much as possible.


Africa Misses Out On The Big M & A Season

By Mohammed Jetutu

Upstream Oil and Gas Asset Acquisitions were flat in Africa and Europe, while they surged in the Americas, helping to create a record global high of $l07Billion.

IHS Energy, the global firm of hydrocarbon industry scouts, reports that deal value for oil and gas assets increased 160 percent above 2009 figures, driven in part by sustained high oil prices and global expansion by national oil companies

But where as Asset transaction value more than doubled to $59 billion in North America in 2010, and more than tripled to $18 billion in Asia-Pacific, there was comparatively far less dealing in Europe, Africa, the Middle East, and the Former Soviet Union. The preliminary results in the IHS Herold 2011 Global Upstream M&A Review, released

IHS Energy, notes that the big asset sale was driven by spending by:

  • National oil companies,
  • Major divestiture programmes by BP (to pay for the Macondo oil spill),
  • ConocoPhillips,
  • Suncor Energy and
  • Devon Energy, as well as
  • Major joint ventures focused on North American unconventional resource plays.

“Total global upstream mergers and acquisition (M&A) transaction value, including corporate mergers, rose by $16 billion $160 billion” the report indicates, “although there were no corporate mergers greater than $10 billion in 2010”. Corporate transaction value retreated to approximately $53 billion in 2010 after spiking on the ExxonMobil – XTO and Suncor Energy – Petro-Canada mergers in 2009.

The report’s executive summary, which was released as of our going to press, didn’t give any comparable value on deals in Africa, nor provide analysis on M&A activity on the continent in any detail. Still, to get a sense of such oil and gas asset transaction in Africa in 2010, consider the example of BP’s $7Billion worth of sale of assets to Apache Corp., the American independent, in three regions of the world. Apache paid $6.35 billion for all the assets it acquired in the US Permian Basin and Canada, with $3.l bilion for Permian Basin portfolio and $3.25billion for the Canadian properties. In contrast, Apache paid $650 million to acquire four development leases and one exploration concession across 394,300 acres in Africa, specifically, Egypt.

Elsewhere on the continent, Shell, TOTAL and ENI collectively sold their equity in four leases in Nigeria for slightly less than $500Million. The biggest asset sale in Africa in 2010 was the acquisition, by Tullow Oil, of Heritage’s 50% stakes in Uganda’s Blocks 1 and 3A for $1.45Billion.

“There were three primary drivers that led to the record asset deal value,” said Christopher Sheehan, director of M&A research at IHS, “sustained strength in oil prices reinforced by growing confidence in the economy, large packages of attractive producing assets on the market, and low natural gas prices in North America. In 2010, many oil and gas companies moved to-restructure, refocus or expand their portfolios as an improving global economy engendered confidence in steady high oil prices. National oil companies seized the opportunity to purchase hard assets in a strategic expansion of their global natural resource holdings. In addition,” he said, “continued low North American natural gas prices provided attractive opportunities for well-financed new entrants to invest in shale and tight sands plays. At the same time, rising equity prices made the pursuit of corporate acquisitions more expensive.”

In spite of the significant rise in Asset transaction value in North America in 2010, the region’s share of total global upstream transaction value slipped to 54 percent in 2010 from 68 percent in 2009, (the 2009 value was inflated by corporate mergers). While North American activity in 2010 was dominated by shale resource investment, including a more than 150 per- CPT cent year-on-year increase on U.S. as- set deal spending, ongoing regulatory uncertainty in the Gulf of Mexico following the deepwater Macondo spill led to only sporadic transaction flow there.

M & A Activity in Latin America Soared

According to IHS, the biggest increase in upstream transaction value was recorded in Latin America, where deal value soared to $29 billion, a milestone fueled by Chinese national oil companies expanding their upstream footprint in the Americas, including gaining access to Brazil’s immense deepwater pre-salt resources. To put this phenomenal growth in perspective, Latin America accounted for 18 percent of the worldwide upstream transaction value in 2010 – skyrocketing six-fold above the 2009 transaction value that represented just three percent of the global total.

Even so, in total, the volume of distressed assets on the market dampened deal pricing gains in 2010 compared with the previous year. Weighted, average oil and gas proved-reserve deal-pricing rose to $10.59! per barrel of oil equivalent (boe) in 2010 from $9.72/bee in 2009. Deal pricing for proved, oil-weighted transactions increased to $9.78/BOE in 2010 from $8.48/BOE in 2009. In the U.S., deal pricing for proved, oil-weighted transactions increased sharply from $12.72/BOE in 2009 to $16.51/BOE in 2010. Despite persistently weak natural gas prices, gas-weighted, proved reserve deal- pricing in the United States (the world’s most liquid upstream M&A market) actually rose slightly from $11.26/BOE in 2009, to $11.79/ BOE in 2010.

Transactions for Unconventionals Remained Robust; National Oil Companies Accounted For More Than 20 Percent of Global Spending Unconventional resources represented more than one-third of total worldwide upstream transaction value, or $57 billion, in 2010. This high figure is steady with 2009 values, which included more than $30 billion attributable to the ExxonMobil – XTO merger. The major trends surrounding unconventional resources in 2010 were a near doubling of assets deals focused on tight gas plays and a more than tripling of transactions focused on the Canadian oil sands.

“The Canadian oil sands assets,” Sheehan noted, “were more attractive to international investors due to the combination of improved project economics boosted by higher crude oil prices, and a welcoming climate for cross-border M&A by the Canadian government.”

NOCs and sovereign wealth funds (SWF) dramatically increased their acquisition of global upstream assets to feed their rapidly growing economies in 2010. Total NOC and SWF transaction value reached $32 billion or 20 percent of the global total in 2010, which was up from 13 percent of worldwide transaction value in 2009. Total global purchases by the Chinese NOCs increased from $14 billion in 2009 to $26 billion in 2010.

For more information on the IHS Herold M&A Database and transaction analysis, please contact sales@herold.com. To speak with IHS analyst Christopher Sheehan regarding the IHS Herold 2011 Global Upstream M&A Review, please contact, melissa.manning@ihs.com, or press@ihs.com.


North Africa’s Crude Output To Fall

 

The mad rush for Libya won’t translate to production increase in the next five years

Crude oil production will decrease in North Africa in the next five years, according to analysis of global capital spend by Wood Mackenzie. An evaluation of projected global capital spend between 2009 and 2014 suggests a mild drop in net production growth in North Africa, although the decrease is nowhere near the sharp reduction in net output in Europe and, well, Latin America The report didn’t single out any specific North African country for assessment of relative increase or decrease in production, so it’s not clear whether a single country is responsible for growth or decrease. This contrasts with its assessment of Latin America, where it predicts a growth in Brazilian output. but explains that this growth is not sufficient to bring about a net increase in the regional crude oil output the time under review. The grim outlook of North African oil production is at odds with the growing presence of Western companies in the country since sanctions were lifted five years age. It also contrasts with the reported increase in discoveries in Egypt. What it means is that new oilfields are not being developed in Algeria. Libya. Egypt. Tunisia and Morocco. In specific detail, investment in exploration in Libya hasn’t delivered the sort of world class discoveries being encountered in the Gulf Of Guinea. notably Ghana and Angola. Egyptian discoveries  may be many, but they are small. Algeria is growing its gas assets, but there are no new, major oilfield discoveries, let alone developments.


Sand Injectites in Deep-Water Depositional Environments, Detection and Interpretation using Borehole Electrical Images

By Peter Schlicht, Schlumberger Technical Services Inc., Angola, with Oskar Yepes and John Crowe, Chevron Angola

Conventional core data from Miocene deep water turbidite channels in Angola show common occurrence of sand injections. Structures formed by these elastic intrusions are called injectites and they can have both negative as well as positive impact on the reservoir performance. They occur as sub-vertical dikes, horizontal and br bedding parallel sills. Early detection and recognition of these features, which can range from millimeter to kilometer scales. can considerably impact the development strategy of for a given reservoir. Borehole electrical images allow to detect injection features and to differentiate from the surrounding geological contexts, so their impact can be quantified. In our case study we examine the resistivity content of the borehole electrical image in combination with the interpreted directional data, the formation dip. Based on user-input contrast cutoffs, conductive and resistive events that do not correlate across the borehole along the bedding direction, and that show high enough contrast with respect to their background, are detected by performing a heterogeneity analysis. Assuming ‘pure’ elastic systems we infer a directly proportional relationship between non- conductive mud invasion to porethroat- and grainsize in order to separate sand, silt and clay proportions. Detecting relative grainsizes combined with evaluation of non- correlating bedding events lead us to the recognition of sand intrusion events and their orientation.


Libya’s Massive Crude Oil Engine

Libya has five major onshore sedimentary basins, they are:

  • Sirt Basin, Murzuq Basin
  • Kufra Basin
  • Ghadamis Basin
  • Cyrenaica Platform
  • Tripolitanian Offshore Basin

The main producing basins of Libya are in order of importance the Sirt, Ghadamis, Murzuq and the offshore Tripolitanian basin. Location of major Sedimentary Basins of Libya (click on hot spots on map to visit pages). Epirogenic movements with vertical nature are limited to uparching and faulting and included Mesozoic-Tertiary basins of Sirt and Cyrenaica (NE Libya). Tectonic movements occurred in northern Libya were responsible for the large sedimentary sequences in Libyan basins. The generation and entrapment of hydrocarbon in Libya was controlled by the tectonic history of each individual basin. According to Energy Intelligence Research, in 2003 Libya was the 11th largest exporter of petroleum in the world. Libya reached the peak of 3.3 million barrels a day in 1970 and currently produces only about 1.7 million barrels of crude a day. According to NOC, only around 30 per cent of Libya has been explored for hydrocarbons, Libya wants to return production to that peak level by 2010. There are about 320 producer field with total reserve exceed 50 billion barrels of oil and 40 trillion cubic feet of gas. Oil field distribution worldwide, notice that 4Q0 the oil reserve is from Middle East and North Africa Libya includes several hydrocarbon provinces of which the most important is Sirt Basin. This Basin contains some sixteen giant oil fields with about *117 Billion barrels of in place proven recoverable oil These form 89°c of all the discovered Libyan petroleum reserves. This basin is considered to be the most prolific oil basin in north Africa with an oil gravity that ranges between 44 and 32 API, and a sulphur content of between 0.15 and 0.66%. The Sirt Basin includes Cretaceous and Paleocene reservoir sequences and Upper Cretaceous Sirt Shale is a major source rock for this basin.

The Ghadamis intracratonic basin consists of up to 6000 metres of dominantly elastic Paleozoic through Mesozoic strata with an estimated three billion barrels of recoverable oil. The Upper Silurian Akakus Formation and the Tadrart – Ouan Kasa formations are the most prolific oil producing horizons.

The Muzurq Basin is filled with Cambrian through Quaternary deposits, with a maximum total thickness of more than 3000 metres in the central part of the basin, In the area to the north, where oil reserves are some 1 billion barrels, the potential reservoirs include the Memouniat, Acacus and Tadrart- Kasa sandstones. The major source rock in this basin is the Silurian Tanezzuft Shale.

To the present time no commercial discoveries have yet been made in the Mesozoic-Tertiary rocks of Cyrenaica and Paleozoic of Al Kufra Basin.

However recent work on stratigraphy and geochemistry of the Cyrenaican Platform suggests the probability of major potential reserves of oil and gas from Cretaceous and early Tertiary Rocks. Similarly the Devonian sandstones have been found to contain some gas shows in central Cyrenaica.

The offshore basins are considered to be highly prospective but has been exposed to only limited exploration to date. The major offshore oil production is in Tripolitania Basin from the El-Bouri oilfield that is producing about 60,000 BOPD, with an estimated two billion barrels proven recoverable crude oil reserves. On December 17, 2008, Hess Corp. reported an exploratory well has encountered a 160 metres gross hydrocarbon section at various intervals in an offshore extension of the Sirt Basin.

This paper is intended as an online introduction to the geology of Libya and its petroleum resources with links to maps and cross sections assembled from a variety of publications and geological sources by Hassan Salem Hassan (Swalem to his family), for his PhD geological studies at the University of South Carolina and his academic advisor Christopher Kendall.

World regions with major oil reserves and projected but undiscovered oil resources. Source: Energy Information Administration The figure on page 15 features a slump structure exposed on the coast of northern Cyrenaica (Al Jabal Al Akhdar). This region has been unstable since the initiation of an inversion of the topography in the Santonian time that uplifted Al Jabal Al Akhdar. This event was undoubtedly responsible for the folding of the Late Cretaceous-Early Tertiary rocks of northern Cyrenaica. The presence of contorted beddings in the figure matches that seen in more than two horizons of Al Athrun Formation. The structures above are characteristic of a gravity induced soft sediment slump, probably in a slope setting, suggesting a continuation of tectonic activity during Campanian time. Hassan Salem Hassan provides the scale.

Hassan S. Hassan, PhD Candidate, Advisor: Dr. Christopher Kendall, University of South Carolina, Department of Geological Sciences, Phone No. (803) 777- 5202, 701 Sumter Street, Room # 61 7 Columbia, SC 29208, hsalems@yahoo.com

Editor’s Note: The figure of 117 billion barrels, as estimated recoverable reserves for Sirte Basin, is at odds with those of the BP Statistic Review, which is widely considered the bible of the industry.


Geosteering in Complex Fields (Angola) Following Girassol/Jasmim field experience, geosteering in Angola’s

By Antoine Massalal, Nigel Williamsi, TOTAL E & P Angola

Block 17, Dalia and Rosa fields, has enabled Total EP Angola to drill long, complex, single and multi- reservoir, horizontal and sub-horizontal wells, with great success. The initial planning of high offset geosteered wells, in the project stage, enabled TEPA to minimise the number of sub-sea manifolds and the number of wells, necessary, in order to bring the two fields into development, and to maximise the number and length of reservoir penetrations.

Real-time geosteering of such complex wells inside a single dynamic flow unit, even though still a challenge, is currently achieved with a high success ratio, also in thin (less than l0m thick) sandbodies. Successful geosteering of these wells has further enabled optimisation of the well pattern. As new information has become available during field development, it appears sometimes possible to substitute 2 wells by a more complex geosteered well, with multi- reservoir targets. The tools enabling successful geosteering of wells in Blockl7 are the excellent seismic image quality, coupled with the availability of ‘At Bit’ logging whilst drilling technology. In addition, Total’s Sismage’ seismic software enables sharing of data between the rig-site and Luanda, thus allowing the tie-in of the well in the seismic image, in real-time.


Finetuning Lithofacies and Reservoir Modeling using Borehole Images and Neural Networks

By Simone Di Santo’, Schlumberger Technical Services Inc., Angola, with Nilton Carvalho Rakesh Dhir Tank Gacem, Sonangol P&P.

The determination and definition of reservoir flow units is critical to developing an accurate and useful model of reservoir behaviour. Given that this model will ultimately guide significant capital expenditures such as interventions and infill drilling, it is crucial that the maximum accuracy be achieved. In this paper we describe how all available petrophysical data, with an emphasis on high resolution micro-image data, is used to delineate geological fades and ultimately define the reservoir flow units.

In our example we look at a deepwater field offshore West Africa with a number of wells, all with a variety of petrophysical data. We show how this data is integrated to first determine the range of fades to be identified and then to assign each metre of reservoir to a particular facies such that the resolution and accuracy of the flow unit determination is maximized.

We finally show how the results of the facies and flow unit identification are included in the reservoir simulation and reservoir modeling software to enhance reservoir understanding in order to optimize interventions and infield drilling.


Application of Outcrop Analogues to Optimize LWD Acquisition for More Confident Formation Evaluation in High Angle and Horizontal Wells, E. Tyurin and M. Benefield’, Baker Hughes, INTEQ

Outcrop analogues are very helpful in generation of the reservoir depositional model but are restricted in their application to formation evaluation. They represent a missed opportunity, in particular in the interpretation of high angle and horizontal (HA/HZ) well log response. In our vision they give us access to the depositional controls on vertical and lateral petrophysical rock properties variations as well as actual geometry of the geological bodies; both matters are critical for confident formation evaluation in HA/HZ well setting. The primary objective of this study is the integration of geological answers and petrophysical information to construct forward models of our high technology LWD datasets. We assign a major significance to the visual comparison of the rock picture and a simulated tool response, supported by a detailed petrophysical analysis. We initially used the Ainsa 1 Pyrenean deepwater turbidite outcrop with the petrophysical properties of analogous offshore West Africa reservoirs. Across- channel geological complexity (thin layering and low NTG in marginal part; pinch-outs, amalgamations and rock property variation in the axial part) is valuable to demonstrate improved strategies of interpretation solutions in channel to lobe turbidite settings. Steps to forward model the LWD data include many of today’s reservoir characterization procedures: sedimentological description, lithofacies to petrofacies associations, core and field scale 3D petrophysical properties simulation, upscaling, true resistivity matrix generation and resistivity anisotropy evaluation. Forward modeling of tool response accounts for different measurement natures, geometries and DOl’s (from meters in resistivity to cm in radioactivity, images and magnetic resonance). The range of the results acquired shows that basic LWD suites often do not provide an accurate result in a heterogeneous environment. For example, in our case water saturation is overestimated by around 30% total through improper use of the classical data. Our study highlights that reservoir parameterization in the presence of all scales of heterogeneities, sand mixtures and thin laminations is enhanced through proper application of gamma ray, resistivity, density, neutron and NMR for the pore volumetrics and imaging for the geobody shaping. Using the approach to a contrasted West Siberian field case with inherent low resistivity contrast and invasion of WBM demonstrates further interpretational challenges. The work ultimately permits a more confident selection of logging suites and subsequent improvement in application of the acquired data to formation evaluation in high angle and horizontal well situations.


Advanced Geosteering with Azimuthal Deep Resistivity Helps in Optimal Well Placement, NOVEMBER 2009, By Roland Chemali

Halliburton, Sperry Drilling Services

Early production, as well as ultimate oil and gas recovery, from a reservoir often depends on the timeliness and the accuracy geosteering decisions. Exiting the reservoir during drilling results in costly non-productive intervals.Even staying within the reservoir but in a non-optimal location eventually leads to early water break-through while leaving behind valuable attic oil. In recent years, azim

Fig 1- Geosteering with deep resistivity images from azimuthal deep resistivity LWD.

uthal deep resistivity measurements have been recognized as beneficial to real-time steering decisions. Because of their deep investigation, they give adequate warning to prevent from exiting the reservoir. Their azimuthal sensitivity clearly points to the direction of preferred evasive actions. Best results are achieved by jointly interpreting several measurements from the azimuthal deep resistivity, corresponding to multiple depths of investigation. In the simplest cases, the up-down resistivity curves exhibit a characteristic behavior that has proven valuable both to petrophysicists and to geosteering engineers. When approaching overlaying shale, for example, the up-curve consistently reads the resistivity of the reservoir while the down-curve exhibits amplified horns beneficial to reservoir navigation. Resistivity images feature bright spots whose progression with increasing depth of investiga

tion facilitates avoidance of unwanted boundaries. 4 new measurement designated as Geosignal features strong lateral sensitivity. The Geosignal from the deepest spacing is best suited to provide an early indication of the approaching boundary, with a near- exponential dependence on the distance to

Fig 2- Geosteering with up-down and with bright spot resistivity images from an azimuthal deep resistivity LWD.

boundary. Examples from around the world are shown in detail to help illustrate the applications.

© 2021 Festac News Press Ltd..