Fracking in Mexico: Challenges and Key Success Factors

Fracking in Mexico Blog PicturePemex plans to increase shale activity in the next few years, budgeting over $575m in 2014, highlighting some 200 shale gas opportunities in five geologic provinces in eastern Mexico, and opening up the bidding process for drilling shale fields. It aims to attract as much as $1t in energy investment to exploit Mexico’s shale oil and gas reserves, on the back of the energy sector reform signed by President Enrique Pena Nieto in August 2014.

Based on similarities with Eagle Ford shale in Texas, Mexico’s Eagle Ford shale this is considered to be the country’s top-ranked prospect for shale exploitation. Other basins in Mexico in which drilling has not yet occurred, and where potential is far less certain than the Burgos Basin, include the Sabinas, Tampico, Tuxpan, and Veracruz basins. Pemex (Petróleos Mexicanos), the state-owned oil company, previously identified Tamaulipas, Coahuila and Nuevo Leon, in addition to Chihuahua, as the states where fracking could be used to obtain new energy sources. The other Mexican states officials identified are Puebla, Oaxaca and Veracruz, and Mexico’s technically recoverable shale gas reserves are heavily influenced by the newly discovered Chicuantepec and Burgos.

Shale drilling in Mexico faces many hurdles. Mexico drilled its first shale gas well as recently as 2011, in the Burgos Basin in the North. Drilling was later abandoned by most operators for gas due to low price and high cost. As of February 2013, there were only six productive shale gas and tight oil wells drilled in Mexico (a seventh was abandoned as non-productive). Most of the challenges have to do with infrastructure and technological constraints, and high costs:

  1. Infrastructure constraints: Fracking activities have its own critical pre-requisites and infrastructure is one.  Mexico will need infrastructure such as new roads, rail lines, and rail terminals, and storage units that can hold large amounts of sand, and pipelines that can carry water so that it doesn’t have to be trucked to each site. Each well will require approximately 100 train cars full of sand and 4-5m gallons of water. This is a very large logistical operation.
  2. Technology constraints: Deep-water wells, especially in the Eagle Ford deposits, cut through multiple pancaked layers of oil-soaked rock, and each layer must be fracked to get the most hydrocarbons out, a task that can take a full day to get to the bottom of the well. Halliburton and other oilfield service companies have figured out a way to save time and money by fracking all those layers in one trip down the well, instead of doing each layer separately. This more intense fracking means larger volumes of water, sand, and equipment are needed for greater production. The volumes of inputs needed, especially for these lower tertiary fracks, are huge and the technology required to drill down the multiple layers also need to get more sophisticated. Drilling will not be fruitful without sufficient knowledge of how much sand, water, and chemicals will be required and what will be the best available technology to undertake complex shale drilling to optimize cost.
  3. High cost: “Efficiency is difficult to achieve, quality control is difficult, and corruption increases costs”, explains Garry Ward, expert on oilfield investing.  Drillers pay more than in the US, but do not receive the same quality of chemicals and equipment, which can make all the difference between a good well (profit) and a bad well (loss).  In such a scenario, careless procurement can lead to high cost, poor quality, and losses.

The bottom line is that E&P companies seeking to exploit shale plays in Mexico need expert supply chain strategies to manage their logistics and the cost of purchased materials and services. Boston Strategies International has been in supply chain management for oil and gas, and has supported the planning of every aspect of drilling, completion, production, and transportation, as well as downstream activities.

Fracking: Where Will Latin America Be Without It?

Lat Am Fracking Blog picLatin America, which holds approximately one-fourth of the world’s recoverable shale oil and gas reserves, is poised to reap the benefits of the North American shale revolution between now and 2025.  Ranked by shale reserves, the five largest countries in Latin America are:

  1. Argentina (802 tcf)
  2. Mexico (681 tcf)
  3. Venezuela (167 tcf)
  4. Colombia (55 tcf)
  5. Bolivia (48 tcf)

Argentina has emerged as a potential shale oil superpower as it now has the second-largest shale gas reserves (behind China with 1.1 tcf) and the fourth-largest oil reserves.  It has the shale oil potential of 27b barrels of oil and 802 tcf of recoverable shale gas. The Vaca Muerta formation (located in the Neuquen basin) holds the majority of Argentina’s shale oil reserves with a recoverable 16.2b barrels and 308 tcf of natural gas. Chevron, in partnership with YPF, has begun to exploit the Vaca Muerta formations shale oil reserves and has already invested $3b in the Loma Campana venture, which YPF has described to be the most important shale oil project outside the US. YPF has signed various agreements that will boost fracking activities in Argentina significantly. YPF and Petronas signed an agreement in 2014 to develop shale oil in Argentina’s massive Vaca Muerta formation with over $500m of initial investment. YPF and Petronas plan to use hydraulic fracturing to drill several dozen wells in a pilot phase and as many as 1,000 wells over the coming decade. YPF’s deal with Chevron could lead to about 1,500 wells drilled. In 2013, another deal was signed between YPF and Chevron, which has already turned that area, Loma Campana, into the second-biggest producer of unconventional oil outside North America. Chevron has invested more than $2b till date and is producing more than 25k barrels of shale oil a day at about 245 wells.

The Mexican government’s new energy reform legislation permits the use of fracking, after a majority of senators rejected a clause that would have prohibited the controversial technique. State-owned oil giant Petróleos Mexicanos (Pemex) estimates that Mexico’s shale formation holds the equivalent of 60m barrels of oil, more than the country has pumped out using conventional* means since the turn of the century. Mexico drilled its first shale gas well in 2011, in the Burgos Basin of northern Mexico, in the equivalent of the Eagle Ford Formation of the US. But as of February 2013, there have been only six productive shale gas and tight oil wells drilled in Mexico (a seventh was abandoned as non-productive), all producing from Eagle Ford equivalent. Mexico’s technically recoverable shale gas resource is 545 tcf., the sixth largest in the world.*

Venezuela has 167 tcf of shale gas and 13.4b barrels of oil reserves.* Much of these reserves are found in the state of Zulia which borders Colombia. The low oil prices have made it very difficult for Venezuela to explore and produce shale oil gas due to the high production costs. Venezuela is planning to begin its first shale gas exploration in western Lake Maracaibo in a joint venture with Brazil’s state-run Petrobras. The joint venture company is called Petrowayu, in which the state run oil company PDVSA has 60% stake, Petrobras has 36% and US based Williams has the remaining 4%.  PDVSA has already run initial tests for shale gas at La Guajira, also in western Zulia state, in the hope of discovering significant reserves of unconventional resources.

In Colombia, shale potential is mainly present in three of its 23 basins: the Middle Magdalena Valley (MMVB), Llanos, and Catatumbo basins, amounting to a total shale gas reserve of 55 tcf. Potential shale formations are also thought to exist in the Caguan-Putamayo, Cesar-Rancheria and Eastern Cordillera basin. So far, shale exploration has been predominantly focused on the MMVB. The primary source rock in the MMVB is the La Luna formation, which is considered to be of high quality, and can be compared to those of the Eagle Ford shale formation in the US. The MMVB is estimated to have 18 tcf TRR shale gas, roughly a quarter of that being wet gas. In addition, it contains significant oil deposits estimated at 4.8b bbl. In the latest round of oil and gas concession auctions carried out by the Colombian government, 19 of the 98 bids went to fracking sites, where foreign and national investors will attempt to exploit the deposits of shale oil and gas, most of which lie somewhere to the north of the centre of the country.

Bolivia is very keen to exploit its 48 tcf of shale gas as it fears running out of its conventional gas reserves by 2026. Back in 2013, the country’s state-owned Yacimientos Petroliferos Fiscales Bolivianos (YPFB) announced it would begin studies to identify shale gas deposits. At this point, however, there is no law that regulates hydraulic fracturing activities in Bolivia, but a hydrocarbons bill is underway which addresses the exploitation of unconventional gas.

In Peru, shale gas was found in the Devonian shale beneath the Santa Rosa 1X well in 2009, which was drilled by Maple Energy. Shale gas has not been previously developed in Peru, and Maple Energy is currently seeking investment partners for development at Santa Rosa.

In other smaller Latin American countries like Ecuador, Cuba, Trinidad and Tobago, and El Salvador fracking potential is meager, almost nil. Even if there is any little reserve, lack of investments and protests from environmental groups make it impossible for shale drilling to commence.

While shale gas prospects seem promising in Latin America, some fundamental challenges exist with respect to its viability. Financial viability of these projects is a question in most parts, especially Mexico and Colombia, where shale gas drilling is a costly affair.  Efficiency and quality control are difficult to achieve as shale drilling is still at a nascent stage, pushing cost up, more so in the absence of economies of scale of operations.  Choice of drilling equipment, stimulation technologies, and well spacing are some of the critical decisions that need to be taken. Large volumes of sand, water, and chemicals need to be transported to the drilling site, which can get logistically complicated. The right procurement, logistic, and supply chain strategies will ensure better quality and cost control. Therefore, E&P companies eying shale gas drilling in Latin America must depend on expert supply chain strategies to manage their logistics and the cost of purchased materials and services.

* According to the US Energy Information Administration (EIA)

Fracking Fever in Colombia

Fracking Potential in Colombia Blog Picture

In Colombia, shale potential is mainly present in three of its 23 basins: the Middle Magdalena Valley (MMVB), Llanos, and Catatumbo basins, amounting to a total shale gas reserve of 55 tcf. Potential shale formations are also believed to exist in the Caguan-Putamayo, Cesar-Rancheria, and Eastern Cordillera basin. So far, shale exploration has been predominantly focused on the MMVB region. The primary source rock in the MMVB is the high quality La Luna formation, which can be compared to those of the Eagle Ford shale formation in the US. This region is estimated to have 18 tcf TRR shale gas, roughly a quarter of that being wet gas. In addition, it contains significant oil deposits estimated at 4.8b bbl.

Colombia jumped onto the fracking bandwagon after its Mining and Energy Ministry gave the green signal to this practice in 2014. The government established a regulatory framework, so as to minimise the risks associated with fracking. In the latest round of oil and gas concession auctions carried out by the Colombian government, 19 of the 98 bids went to fracking sites, where foreign and national investors are now attempting to exploit the deposits of shale oil and gas. Shell, Ecopetrol (Colombia’s state-run oil company), Exxon Mobil, and Nexen Petroleum are a few who have purchased the rights to develop these sights. In this regard, the government specified that the bidders for unconventional blocks must have financial standing of at least $200m (compared with $6m required for onshore conventional blocks). This reflects the high costs of shale exploration in entering Colombian market and suggests that smaller players would need to join bigger companies if they intend to ride high on the wave of shale boom.

The government had initially hoped that commercial production of shale oil and gas could begin sometime in 2015. However, the drop in crude oil prices proved to be a dampener in Colombia’s hopes of developing shale deposits as a way of countering depleting conventional oil reserves. Global drillers including Exxon Mobil are deferring shale exploration plans as crude oil price plummeted. Colombian drillers including Ecopetrol and Pacific Rubiales Energy lowered exploration spending in 2015 as they focused mainly on production. Ecopetrol’s budget for unconventional reserves was $40m this year, compared with $240m in 2014. Royal Dutch Shell and ConocoPhillips have also deferred shale exploration spending in Colombia.

Despite Colombia’s competitive environment, exploration has until recently mainly focused on conventional methods. Concerned with dwindling natural gas reserves (currently 7 tcf of proved reserves) from existing conventional fields and the prospect of becoming a net importer within a few years, Agencia Nacional de Hidrocarburos (ANH), the state regulatory body on hydrocarbons, has introduced several policies in recent years to encourage shale drilling. For example, they introduced a 40% discount on royalties to make the exploration and production of unconventional resources even more attractive. In addition, natural gas producers in Colombia now have the right to export without prior Government approval, as long as total gas reserves meet at least eight years of domestic demand.

ANH conducted Colombia’s first shale block auction in 2012. It had high hopes for the second unconventional auction through Ronda Colombia 2014. However, shale plays auctions raised only about $1.4b, significantly less than the $2.6b expected originally. Despite this, Ecopetrol continues to control the majority of the market, managing about one third of the oil and gas licenses in Colombia. Shale exploration has become a critical component of Ecopetrol’s business plan, and the company plans to drill for unconventional hydrocarbons this year in the Middle Magdalena and Catatumbo areas, including nine stratigraphic wells, three exploratory wells and three productivity and study pilots.

As its current reserves will only last for about six years, the commercialization of Colombia’s proven shale reserve is essential to the country future energy prospects. However, commercial success will depend on the cost of exploitation. Fracking is a relatively expensive proposition if it is done correctly, due to quality, environmental, and efficiency concerns, which is why the major firms like Halliburton, Schlumberger and Baker Hughes are well-positioned to execute it. Choice of drilling equipment, stimulation technologies, and well spacing will determine the productivity of a field. Reservoir response should be carefully monitored over the life of a project to make necessary adjustments to the operational model. The drop in oil prices put on hold the beginning of shale exploration that was planned for the start of this year.  Fracking at $45-50/barrel makes it extremely difficult for smaller, independent and/or local E&P companies to get started. Shell and Exxon’s have already delayed the shale drilling decision due to current price level.

The companies getting into shale gas production in Colombia today will need to streamline their procurement costs and invest in productivity, technological, and operational excellence. Operational efficiency, a skilled workforce, effectiveness in supply chain management and monitoring of costs will be critical.

Boston Strategies Targeting Significant Emission Reduction

b2ap3_thumbnail_BSI-Carbon-FootprintBSI has committed to reduce its carbon footprint per revenue dollar for fiscal year 2015 by 63%. This follows a 21% reduction in absolute carbon emission during 2014.

As a consulting firm we do not emit any carbon through manufacturing or conversion itself, which constitutes ‘Scope 1 emissions’ according to the standard guidelines of GHG Protocol for businesses developed jointly by World Resources Institute (WRI) and the World Business Council for Sustainable Development (WBCSD). We do, however, occupy workspace and travel on airplanes (‘Scope 2 emissions’), and commute to work (‘Scope 3 emissions’).

We are reducing our footprint by increasing local staffing, ramping up the use of videoconferencing, and incentivizing low-carbon commuting and home officing. “Multi-local staffing is an initiative we’ve been pursuing for three years. Not only is it environmentally responsible, but it also helps to meet our clients’ local content goals.” explains David Jacoby, President.

“We’ve been working on videoconferencing since 2010, and after several generations of technology we feel that we have achieved a highly effective work mode,” adds Erik Halbert, Principal.  “Telecommuting is opening up flexible options for job candidates, which helps increase the overall caliber of our talent pool,” adds Alok Gupta, Senior Associate.

Our primary goal behind calculating our carbon footprint was to see how we are performing in our efforts towards mitigating the impacts of global warming. Accordingly, we set stricter targets for ourselves to further lower our footprint. Even though our business operations are growing every year, causing an upward pressure on footprint, we still strive to lower emissions by a greater magnitude than ever before.

Our workplace practices categorically focuses on saving energy. Our employees make sure they switch off the laptops, lights, fans, and air-conditioners when not in use. A major chunk of our emissions comes from air-travels, and we give special attention to make sure that we keep our emissions level as low as possible in this area. For this, we make sure that we optimally plan our travel. For conferences and business meets, we try to send employees located closest to the venue.

Although BSI is under no compliance obligation to track or report its carbon footprint, we are doing so entirely voluntarily. Through our practice, we’d like to encourage other firms to take up the exercise of monitoring and managing their carbon footprint. At the end of the day, every drop will make a difference.

About BSI

Boston Strategies International (BSI) is a consultancy firm that compresses the lead time and reduces the investment in major capital programs for oil, gas, and power operators through value chain cost engineering, targeted strategic sourcing, and supply contract negotiation. BSI operates through its offices at multiple global locations including USA, Turkey, India, and Columbia. BSI serves national and international oil companies, power producers and Gas Utilities, Wind and Solar power providers.

BSI carries out its business activities with utmost sensitivity towards environmental concerns, which forms a principle pillar of our business ethics and work culture. We deeply understand the magnitude and criticality of global warming, and want to do our best to contribute to the mitigation efforts.

Alternative fuel vehicles:Have we passed the tipping point?

b2ap3_thumbnail_Terrafugia-copyTerrafugia’s production of the first U.S. Federal approved flying car, the Transition, suggests that we have taken a huge step closer to accomplishing a Sci-Fi like story. However, the recent global demonstrations on environment served to remind us that the key question we need to be answering is what fuels will various forms of transportation run on in the future?

Research within this arena has revolved on a number of different alternatives. Hydrogen in theory is an ideal fuel since it provides more energy per kilogram than petrol and only produces water as an exhaust.  When NASA scientists really needed a fuel that would go the distance, they used hydrogen to generate power on the Apollo missions. Unfortunately hydrogen does not seem to be the most favorable alternative – for the coming decade at least – because it is very expensive to produce and requires significant amount of space to store. Hydrogen additionally requires significant changes in the current operating infrastructure, such as determining the optimum process for producing hydrogen in the first place and establishing fueling station networks. Another alternative has been electric fuel through batteries, which can be charged using the current grid and produce no exhaust. However, batteries have a limited travel range and long charge times. Solar power is attractive in terms of cleanliness, but has so far required impractically large components to power vehicles.

The closest realistic alternative to fossil fuels in powering various forms of transportation has been bio-fuels. Despite the huge environmental debate related to this energy source, bio-fuels offer a number of advantages such as: no new delivery infrastructure is needed, it is renewable, and it can be considered carbon neutral. Combining this energy source with electricity to produce hybrid vehicles is also becoming a popular choice for auto producers. In fact, BSI’s 2007 report titled “Energy Prices Re-Shaping the Supply Chain: Charting a New Course?”acknowledged the possibility “that combination hybrid-alternative fuel vehicles will become mainstream within ten years,” but given the low baseline (0.2% of all vehicles in 2004), that prospect could take longer.

The alternative energy frontier has advanced more rapidly than expected. Between 2004 and 2014 the percent of new vehicles powered by alternative fuels in the US rose from 8.9% to 10.9%. With increasing attention being given to environmental stewardship and global warming, we can expect continued, even stronger, increases. Boston Strategies International is helping equipment manufacturers configure their partnerships and value chains for that future.

The war against ISIS: Changing the oil landscape in the Middle East

b2ap3_thumbnail_KURDISTAN-copyThe spotlight on recent events in the Middle East, while understandably focused on ISIS and the coalition battling it, has overshadowed the potential emergence of a Kurdish state, which would dramatically change the energy landscape in Iraq, Turkey, and, by extension, Europe.

Some have observed that ISIS may control oil production. In fact, ISIS’s current oil production capacity is only around 25,000-40,000 barrels per day and it would be difficult to foresee that the group would be allowed any future control over any oil production facility.

The more interesting potential outcome of these events is suggested by the image above, in the gray area labeled “Kurdistan,” which outlines the potential area of influence or domination by the Kurds. So far, the Kurdish forces have been the most active among the ground troops in the war waged against ISIS. There is no doubt that their quick and intense involvement is linked with their longstanding dream of establishing an independent state, which they have partially achieved through the current Kurdistan government. A Kurdish state with a geographic spread that currently spans four countries would immediately transform the Kurds into a significant regional energy player, not only because of the oil production capacity that the state would have, but also because of its strategic location.

Kurdish desire for the means to control their own economic destiny and the potential benefits to other countries of stabilizing governmental control in the region lend support to the rise of a Kurdish state. The Kurdistan Regional Government plans to reach a production capacity of 1 million barrels per day (bpd) by 2016. This would generate revenues of around $35 billion per year at current oil prices, but with the developments taking place in the region and should the Kurds take control of the Kirkuk Oil field they will have achieved their target much earlier than their forecast. Furthermore this would immediately pave the way to the Kirkuk-Cayhem pipeline, which could potentially transport 1.6 billion barrels per day to energy-hungry Turkey. While the Turkish Government opposes the creation of an independent Kurdistan, a stronger government in the oil-rich region would support Turkey’s ambition to become an energy corridor to Europe.

Such prospects create new opportunities, and risks, for energy companies, and their effects will be felt by end-users of gas and oil. Boston Strategies International is helping its clients identify new partners and maximize the value of potential opportunities during this window of opportunity.

Is it possible to perpetually extend the fossil fuel frontier?

b2ap3_thumbnail_graph-copy2In their book “Ecological Economics” Daly and Farley wrote: “We almost certainly will never exhaust fossil fuel stocks in physical terms, because there will always remain some stocks that are too energy-intensive or too expensive to recover.”

Technological advances have enabled us  to continuously readjust our fossil fuel reserve forecasts, but they will eventually have their limits. It is a scientific fact that it takes 9.8 joules of energy to lift 1 kg one meter and there is no techonological advance that can change that fact. Additionally, a fossil fuel is recoverable only if the net energy gain from extraction is positive (it needs to take less than a barrel of oil to extract a barrel of oil), and increased energy is being consumed to recover the remaining supplies. Therefore the energy return on investment is declining: in 2012 the top 50 American oil operators invested 20% more than in 2011 to develop new oil fields, and yet their combined production grew only 13% while after-tax profits declined 58%.

While the EIA increased its forecast of global recoverable shale gas by 10% in 2013 to 7,299 trillion cf, another 2013 survey of 35 leading companies in shale exploration revealed that their average capex spending reached $50 per barrel with average revenue per barrel of $51.5. Exploration and Production (E&P) companies will need to identify the sweet spots within this landscape if they are to reap their target ROI on E&P spending.

In addition, the countries with the most years of oil left include many of the less politically stable ones, which will provide incentive for a global political convergence. With extensive experience in the Middle East and Latin America, Boston Strategies International is helping its global client base to establish win-win joint ventures and partnerships to take advantage of this opportunity.

Corruption is Delaying Socioeconomic Benefits of Liberian E&P Investments, but Local Supply Chain Development Can Stimulate Foreign Investment and Economic Growth Indirectly

Corruption Index logoAt first glance Liberia doesn’t seem as corrupt as its West African neighbors – it received 41 out of 100 on Transparency International’s Corruption Perception Index (higher is better; 90 was the best score and 8 was the worst). Many African countries with newfound oil reserves received similarly disturbing scores – Chad scored 19; Angola 22; Cameroon 26; Cote d’Ivoire and Equatorial Guinea 29; Mozambique, Mauritania, and Sierra Leone 31; Niger 33; Tanzania 35; and Gabon 38.

Still, Liberia has spent the past year dealing with scandals related to bribery of government officials by its oil company executives who tried, unsuccessfully, to push through a round of oil concessions with limited public consultation. Governance issues are not a unique story in West Africa.Nigeria delayed a 2012 round of oil concessions as foreign investors looked on skeptically, remembering the previous corrupt rounds (2005-2007) and fields that were acquired but left undeveloped. Also, Ghana issued multiple tenders for development of its refining (downstream) sector, but many projects were not approved, not started, or not completed.

While policy reforms can take years to implement, there is another way to attract investment and stimulate jobs and economic growth in the meanwhile: Liberia can build a strong local oil and gas supply capability. By training and developing local suppliers to be competent and capable, and institutionalizing transparent commercial practices, the government can lure investors and make it easier, quicker, and cheaper for NOCAL (the national oil company of Liberia) to do business honestly with efficient suppliers while increasing the difficulty, cost, and consequences of doing business corruptly with its cronies.

Boston Strategies International benchmarks local supply capability in a number of emerging oil, gas and power supply markets. Ask us how you stack up, and how we can help accelerate strategic and economically impactful local content development.

How West African National Oil Companies Can Raise Their Equity Stake in Upcoming Projects from 15% to 50%

shutterstock_80954569Ghana National Petroleum has 15% ownership of the Deepwater Tano Contract Area. The other 85% of the ownership went to Tullow (47%), Kosmos Energy (17%), Anadarko Petroleum (17%), Sabre Oil & Gas Holdings Ltd, a wholly owned subsidiary of Petro SA (4%) (percentages are approximate).

In contrast, Sonangal holds 41% of the Mafumeira Sul project in Angola (Chevron holds 39%, Total holds 10 percent, and ENI holds 10%), and NNPC holds 40% of the Escravos project in Nigeria (Chevron holds 60%).

How can Chad, Côte d’Ivoire, Liberia, Mauritania, Cameroon, Niger, Gabon, Namibia, Sierra Leone, and Equatorial Guinea get a higher percentage ownership of projects in their own backyard? Low equity figures imply that partners are contributing 85% of the value, and by extension that the locals are only remunerated for their natural resource.

These countries can change the game by increasing their local supply chain competence upward toward a target of 50% of the value of the projects – more than the Nigerian and Angolan equity in the aforementioned deals, and just under the minimum target that Nigeria has set for the ensemble of sub-industries in its oil and gas sector (the minimum local content is 54%, on average).

The key to earning more equity is to accelerate the development of local capabilities that are: 1) critical to project execution; 2) that can be incrementally more profitable than the average oil and gas supply industry; and 3) that can meet oil companies’ qualification criteria within a relatively short investment timeframe.

Generally speaking, they can achieve most of these objectives by developing the following six industries:

  • Pressure vessel fabrication
  • Pipe fabricating and installation
  • Compressor manufacture, assembly, and maintenance
  • Well and drilling services
  • Pump and valve assembly and light manufacturing
  • Water treatment equipment and services

Boston Strategies International offers hands-on capabilities to help establish the needed capabilities in oilfield applications of each of these industries. Click here to ask us for our relevant qualifications in:

  • Formation of alliances with leading technology partners
  • Design and construction of facilities
  • Training and development of  local labor force
  • Management and supervision of operations

Note: Image courtesy of AHFRO.

Bahrain’s LNG Terminal Project: How an Independent Master Supply Chain Plan May Have Saved 29 Months and $138 million

b2ap3_thumbnail_Fast-Track-to-Funding-shutterstock_164841665Bahrain’s National Oil and Gas Authority (NOGA)’s LNG import terminal project seems to be on path for a 7-yearcycle: NOGA initiated partnering steps in 2010, and is forecasting completion for 2017.

  • During a ‘prequalification’ round, NOGA came up with an initial short list of potential EPC firms, then it enlarged the bid list to include a maximum number of responses (21). The bid turned out to be premature, but it did result in two ongoing ‘discussion partners’ (Shell and Vitol).
  • NOGA took several years to iron out governance issues. It had originally considered a joint venture with Independent Terminal Bahrain (ITB), Kuwait’s Independent Petroleum Group (IPG), and Arab Petroleum Investments Corporation (APICORP). In the end, NOGA chose a consultant and engineers to do a pre-FEED and a FEED study. It also decided on issues of ownership between NOGAholding, NOGA, and BAPCO, which it engaged as a technical advisor.
  • It set priorities and interrelationships between related projects, assessing its domestic energy needs (e.g., ALBA), evaluating alternative energy sources and configurations (FLNG, solar, etc.), negotiating the terms of pipelined oil from Saudi Arabia, and tweaking the project’s timing to synchronize anticipated supply and demand.

The introduction and integration of a supply chain ‘master plan’ at the Feasibility Study/Basis of Design stage can shrink the project cycle, improve reliability of the timetable, decrease cost, and synchronize procurement commitments with forecast cash positions, all while meeting target levels of total cost and per-unit cost. A supply chain master plan for an LNG project has three components:

  • Assessment of the cost saving potential of alternative major equipment technologies and choices, such as gas turbines, GT drives, and heat exchanger designs, which on average saves 10-25% on these major items.
  • Determination of the minimal achievable project timeline within inter-related and complex supply chain lead time constraints, especially for major equipment such as compressors. This avoids subsequent project delays and cost overruns. As a proxy, Boston Strategies International sampled 20 major refinery projects between 2005 and 2014 found that 20% of them encountered delays that inflated their schedules by an average of 35% and their cost by an average of 23%. Equivalent factors applied to the roughly $600 million, 7-year terminal project in Bahrain would yield a potential avoidance of 29 months and $138 million.
  • Calibration of the timing of financial and legal/contractual commitment to long lead time equipment, which avoids cash crunches.

Supply chain master plans should be conducted by independent third parties other than the firm that may do or manage the construction. This ensures objectivity of the costs and lead times, which an EPC often has an incentive to misrepresent in order to increase its chances of winning the construction work. By providing a range of cost benchmarks for similar projects, it also dramatically improves the owner/operator’s negotiating position in the bid evaluation phase.

Boston Strategies International developed a supply chain master plan for a major European power producer that helped to save 13% on the baseline cost of a $45 billion project ($5.8 billion).