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TRANSCRIPT
Study on Possible Reductions of Gas Flaring in
Algeria
Final Report
Commissioned by BGR
Prepared by:
01 July 2019
2
Table of Contents
1.0 OVERVIEW OF THE PROJECT............................................................................................ 3
2.0 OBSERVATIONS AND FINDINGS ....................................................................................... 3
3.0 COUNTRY CONTEXT ......................................................................................................... 5
4.0 GAS FLARING IN ALGERIA ................................................................................................ 6
4.1 Magnitude and direction of gas flaring and GHG emissions ................................................................ 6
4.2 Specific Upstream Gas Flare Reduction Projects ................................................................................. 8
5.0 STRUCTURE OF THE ALGERIAN OIL AND GAS SECTOR ................................................... 10
5.1 Principal Actors and Stakeholders ......................................................................................................... 10 The Ministry of Energy and Mines ................................................................................................................... 11 Sonatrach ......................................................................................................................................................... 11 Regulators ........................................................................................................................................................ 12 Private O&G Companies ................................................................................................................................... 13
5.2 The Gas Market ..................................................................................................................................... 14
5.3 Legal and Regulatory Framework for Gas Development and Valorization ............................................. 14
6.0 GEOLOGICAL AND PRODUCTION TECHNICAL ISSUES ..................................................... 16
ANNEX 1: MAP: OIL AND GAS INFRASTRUCTURE IN ALGERIA .................................................. 17
ANNEX 2: NOTES AND ILLUSTRATIONS ..................................................................................... 18
Note 1: Flared Gas vs. Gas Production ........................................................................................................... 18
Note 2: Issues Related to Algerian Gas Production ........................................................................................ 18
Note 3: Key Stakeholders on Flaring in the Algeria’s O&G Sector ................................................................. 19
Note 4: Planned Gas Projects -- 2016 ............................................................................................................ 20
Note 5: Major Sources ................................................................................................................................... 21
3
1.0 Overview of the Project
This report was commissioned by Federal Institute for Geosciences and Natural Resources (BGR) to
assess the potential of German Technical Cooperation (TC) in the area of gas flaring reduction in
Algeria. Specifically, the Terms of Reference requests:
• Research on the legislative and regulatory framework on gas flaring as well as its status of
implementation;
• Analysis of the geological, geographic and economic conditions towards the usage of
associated gas (AG);
• A stakeholder analysis on the subject for Algeria;
• Demonstration of other donor’s engagement in this area.
The preliminary report was submitted to BGR in August 2017, and this was to be followed by a
mission to Algeria. Due to various scheduling difficulties, the mission was not held until October
2018. This document is the final project report that includes the interim findings, additional
research, and the results from the in-country mission.
2.0 Observations and Findings
The principal points established by this project are:
• The legislative and regulatory framework is largely in place. Flaring is prohibited by law, but
exceptions can be, and are, made. The regulatory agency Agence Nationale pour la
Valorisation des Ressources en Hydrocarbures (ALNAFT) has the responsibility for issuing
exceptions. A substantial fee of 20,000 Algerian dinars (approximately 150€) per 1000
meters is payable on flared gas.
As flaring on new fields is prohibited and appears to be strictly enforced, almost all flaring
occurs in older fields directly operated by Société nationale pour la recherche, la production,
le transport, la transformation et la commercialisation des hydrocarbures (SONATRACH), the
state-owned, oil company. Thus, while private oil companies are often operators on newer
fields, flaring of AG occurs almost always from older Sonatrach operations.
As Sonatrach has substantial political and economic influence, it was not possible to
determine if Sonatrach has a de facto or de jure exemption on flaring and if any fine is
assessed on their flaring. Discussions with Sonatrach representatives during the mission
suggest that the company is currently paying at least some fines for flaring. Sonatrach
reports directly to the Ministry of Energy and Mines.
• From a geological standpoint, oil production (and thus AG) primarily comes Paleozoic
(Cambrian-Ordovician and Lower Devonian) and Triassic reservoirs and is dominated by the
Sonatrach operated Hassi Massaoud. AG flaring tends to occur at smaller fields distant from
the principal fields and connecting gas infrastructure which makes the connection costs
relatively high. This is true of all three fields that were identified as potential projects during
the mission.
Wet natural gas production in Algeria is processed to extract NGLs and the bulk of this
processing takes place in the Sonatrach operated Hassi R’Mel field -- the largest gas field and
principal gas hub.
4
Once stripped, the gas is partly re-injected to maintain stable reservoir pressure and avoid
retrograde condensation. The excess dry gas is then supplied to the domestic and export
markets. Some studies suggest that due to the declining trends in both AG production and
the increasing volumes of gas needed for re-injection, the system may be short enough raw
gas to operate at an optimum level. While new non-associated gas (NAG) production covers
the decline in the older fields, the ability to maintain gas production is an ongoing challenge
and the cost per unit of gas produced is increasing.
• The most important player in the O&G sector is the Ministry of Energy & Mines1 to which
Sonatrach directly reports. Sonatrach as the principal O&G source for the state is the major
funder of the Algerian national budget and as such has immense importance. Any major
initiative on gas flaring would require the support of Sonatrach and the tacit consent of the
Ministry of Energy.
• The major donor involved on flaring issues in Algeria has been the World Bank/GGFR, which
sponsored a major flaring project in 2003-2005. In 2018, Sonatrach has endorsed the
WB/GGFR “Zero Routine Flaring by 2030” Initiative (ZRF 2003). The country’s National
Determined Contribution (NDC) under the Paris Accord sets a target of no more than 1%
flaring by 2030.
As regards technical assistance, during the October 2018 mission, the Ministry brought forward
three flaring sites as candidates for technical assistance -- the flared AG at the oil fields; TFT, In
Amenas and Ohanet. These three fields are the same ones which the WB/GGFR provided assistance
on options to reduce flaring in 2003-2005.
The preferred technical option, both then and now, continues to be to capture the AG and take it to
market. Since the WB/GGFR study, the gas infrastructure in the region has expanded substantially,
but this relates to NAG production and the flaring sites have not apparently been affected. The issue
in 2003-2005 was financing the flaring investment and this appears to still be the main barrier.
Importantly since the initial studies, the marginal economics of the flare projects has most likely
declined due to natural decline in the AG production (thus increasing costs per unit of gas captured.)
In considering options for technical assistance, areas that could be viable include:
• In Algeria, gas flaring appears to be systemic within the sector and its minimization should be
viewed within the context of how policy priorities could be changed to reduce flaring (e.g.
giving AG priority over NAG in meeting demand) and strengthening the enforcement by
regulatory authorities over flaring.
• As the Paris Accord requires limits on Algeria’s GHG emissions, analysis and capacity building
on how those GHG limits should be integrated into the investment and operating decisions in
the O&G sector, especially for Sonatrach and for the appropriate regulatory agencies.
• While data is thin, the WB/GGFR data suggests that substantial flaring exists within the
overall process and transportation components of the O&G sector, not just at the oil fields.
Considerable knowledge could be added by making an accurate GHG footprint of the sources
and volumes of GHG throughout the sector so as to focus on GHG reduction priorities. To do
so would require the full cooperation of the Ministry and Sonatrach.
• Technical assistance on individual flaring projects appears to add little value. The three
projects identified have had well-defined technical solutions for more than a decade. The
failure to implement lies with financial or other barriers, not a lack of technically appropriate
options.
1 The Ministry is often referred to as the Ministry of Petroleum but on the Ministry and OPEC websites, the official name is
listed as Ministry of Energy and Mines.
5
• Despite appropriate legislation, the enforcement of gas flare regulation appears weak. This
could be an area deserving of international assistance, but to be effective the government
would need to assure the independence and effectiveness vis-à-vis the state oil company.
Germany provides considerable assistance in support of the Paris Accord and the Nationally
Determined Contributions (NDC) developed by the individual countries. Based on the Algerian
experience, an argument could be made that technical assistance could focus on helping to measure
and quantify the sources and quantities of GHG emissions (such as in the O&G sector) to help set
priorities in the implementation of the NDCs.
3.0 Country Context
Algeria is the largest gas producer in Africa as well as being its third largest oil producer2. The
importance of the oil and gas sector to the country’s economy is demonstrated by the fact that it
represents approximately 30% of GDP, 60% of government revenues, and almost 95% of export
revenues. The O&G infrastructure is well-developed and extensive, moving gas from fields in the
central and south-eastern deserts to the central oil and gas hubs, and thence to domestic and
international markets (See Appendix 1 for an O&G infrastructure map). For the EU, the country plays
a vital role in gas imports, providing almost 12% of imports in 2017 (see Figure 1).
Figure 1: 2017 Extra-EU Imports of Gas from main trading Partners.
Source: Eurostat database
The system is anchored by the two giant fields -- the Hassi Massaoud oil field that still contributes
almost 40% of Algerian production and the Hassi R’Mel gas/condensate field that is the largest gas
source.
The country ranks fifth in the GGFR’s listing of global flaring countries and the flaring is a major
component of the country’s GHG emission. While major flaring reductions have occurred since the
1990s, flaring has increased slightly in the last four years.
2 IEA as cited EIA 2016
6
Despite this increase, the Minister of Environment recently stated an aggressive objective to reduce
flaring from a current level of 6% to 1% (presumably of gas produced) by 20203 (This is also stated as
the 2030 objective in the NDC).
The gas supply/demand market in Algeria is in a sensitive position. Traditional gas supplies from
older fields are under stress both by natural field decline and increasing need for upstream pressure
maintenance. These factors have caused the government to focus on gas production and have led to
several major new investments for non-associated gas production. Several of these projects came on
stream in 2016-2018 allowing for a significant increase in production, which contributed to gas
exports increasing by 20% over the last five years. Nevertheless, these projects being designed for
NAG have had no noticeable impact on reducing flaring.
4.0 Gas Flaring in Algeria
4.1 Magnitude and direction of gas flaring and GHG emissions
Starting in the 1990s, Algeria developed a stringent program that brought down associated gas (AG)
flaring from 33% of the gross natural gas produced in 1995.4 Historically the high flaring levels were
due to the high gas-to-oil ratios (GOR) for the oil fields (many of which would be considered
condensate fields) and production focused solely on the high value oil. This has changed as gas
became valuable both for the domestic market and internationally. The construction of gas pipeline
infrastructure (both domestic and international) and liquefied natural gas (LNG) infrastructure made
the commercialization of large volumes of gas possible (See Note 1). However, as Algeria has major
non-associated gas (NAG) fields, gas demand could be met without connecting smaller or higher cost
flares, and such flaring continues to this day.
Data over the last five years shows that flaring in absolute volumes is largely stable (See Figure 2).
Figure 2: Current Trend of Gas Flaring and GHG emissions
0
5
10
15
20
25
100
150
200
250
300
350
2012 2013 2014 2015 2016 2017 2018
MM
tCO
2e
Bsc
f
AG Flaring (Bscf) AG Flaring(CO2+CH4)
Note: GHG emissions are estimated by 98% of the gas being combusted and 2% un-combusted methane
released into the atmosphere
Source: GGFR/NOAA Data and CLN
3 Réduction de ses émissions de gaz : L’Algérie réclame des aides financières http://www.lactualite-dz.info 4 EIA 2016
7
During the mission, it was noted that the GGFR flare estimates and those used by Sonatrach were
substantially different. Sonatrach estimates that around 4% of total AG production is flared (flaring
in first half of 2018 is 1.2 bcm while flaring for the full year of 2017 is 2.9 bcm). This is significantly
lower than GGFR/NOAA estimate of 8.8 bcm in 2017.
Part of the reason may be that the location of flares from the NOAA satellite data indicates that
substantial gas flaring occurs at the major oil hub of Hassi Messoud and the gas hub Hassi R’Mel as
well as Azrew on the Mediterranean coast where the LNG and shipping facilities are located (Figure
3). Thus, the difference in flaring could relate to the distinction between the gas flaring that occurs
throughout the entire oil/gas production and supply chain (presumably the GGFR estimate) and the
AG flaring that occurs only at oil fields (presumably the Sonatrach estimate).
The flaring at oil fields distant from gas infrastructure (such as the three proposed projects) would
likely be flared AG. The flaring at the two major hubs and Azrew are counter-intuitive for AG flaring
in that major gas infrastructure, including pipelines and compressors, are available to take gas to
market at those very sites.
Figure 3 Location of gas flares and magnitudes in Algeria
Natural gas is an important component within the Algerian oil and gas sector. Importantly many of
the aging major oil fields require large amounts of pressure maintenance to reduce and manage
natural decline, a situation that requires increasing gas reinjection over time (See Figure 4).
8
Figure 4 Principal Uses of Gas in the Algerian O&G Sector
-100
-80
-60
-40
-20
0
20
40
60
80
100
1962 1966 1970 1974 1978 1982 1986 1990 1994 1998 2002 2006 2010 2014
Bcm
Net production
Shrinkage
Flared
Reinjected
Source: Aissaoui 2016
In examining the flaring in Algeria, an important consideration is that the gas system is very complex
and that while some oil fields flare AG simply because of being distant from infrastructure, other
flaring may be driven by the industrial processes for treating and transporting oil and gas, or even
infrastructure barriers further up the supply chain (This is however only a hypothesis as no specific
details on the flaring were provided). This implies that flaring could perhaps be more fully addressed
by looking at the issue from a system basis, and not just at individual, upstream flares.
4.2 Specific Upstream Gas Flare Reduction Projects
Regarding investments in gas flaring, in March 2017 the Ministry of Environment stated that
Sonatrach had worked on 32 projects to reduce flaring and one project to sequester CO25 (no details
were provided).
During the October mission, three projects were specifically brought up by the Algerian officials as
being high priority as AG flare reduction projects. These are the same three projects that were the
focus on a 2003-2005 WB/GGFR project. Given this history, it is worth reviewing the WB/GGFR
project and its results.
In 2003-2005, the WB/GGFR partnering with Sonatrach conducted a major gas flaring study. When
the project began the WG/GGFR had only recently been established and the Kyoto Protocol was not
yet in effect. At that time, it was not known how gas flare reductions would be viewed as to CDM
eligibility and if so, what the parameters of any future CDM methodology would be. While the
project had major components related to capacity and institutional building, the primary activity
related to identification and analysis of actual gas flaring locations operated by Sonatrach so as to
assess the technical options and GHG impacts of eliminating the flaring. These results were also to
help in developing a CDM gas reduction methodology.
What makes this project especially relevant is that the three gas flaring projects identified and
assessed are the same three projects put forward by Sonatrach during the October 2018 mission.
5 Réduction de ses émissions de gaz : L’Algérie réclame des aides financières http://www.lactualite-dz.info
9
During the 2018 mission, Sonatrach did not provide quantitative flaring or other data but stated that
the most likely option to reducing the flaring was to capture the gas and transport it to market, the
same technical option as before (Table 1).
Table 1: Gas Capture Projects Proposed by Sonatrach in both 2005 and 2018
Gas Project 2005 Description of Project 2018 Status
Ohanet – Gisement de Pétrole et Gaz
Associés
The project captures and transports the
flared gas from 6 seperate reservoirs to
existing gas transmission lines
In Amenas – Gisement de Pétrole et Gaz
Associés
The project captures and transports the
flared gas from 4 seperate reservoirs to
existing gas transmission lines
Tin Fouye Tabankort (TFT) – Gisement
de Pétrole et Gaz Associés
The project captures and transports the
flared gas from 3 seperate reservoirs to
existing gas transmission lines
All projects continue to flare and the preferred
option contiunes to be gas capture and transport to
market
All these fields have been on production for decades and are on natural decline. Available
information indicates that the natural decline rate is in the 3-5% level -- which implies the current AG
production is between one-third and one-half less than when the WB/GGFR study was conducted.
Indeed, the flaring could be even less as a fixed proportion of the gas is used for on-site energy
before flaring.
All the three fields are in the same general south-western part of the country, near the Libyan
border, meaning they are the end of the principal oil and gas infrastructure (Figure 5, p. 10).
Security concerns are very real. In January 2013, militants seized control of the Tigentourine gas
plant during a four-day siege where dozens of hostages were killed.6 The plant processes NAG from
gas reservoirs in the In-Amenas field complex (the same area as the three fields discussed). The plant
is a joint venture operated by Norway’s Equinor (owned by Statoil at the time), with BP and
Sonatrach as partners.
The comparison between the projects over time has important implications as to the importance of
these projects in reducing flaring, specifically:
• GHG impacts: Given the almost certain natural decline of AG over time, the impact of the
projects on reducing GHG emissions would be significantly less than in the GGFR study.
• Project Design: In the GGFR study, the technical design was at the early concept stage, but
gas capture and transport were assessed as the most attractive option, this appears to
continue to be the case.
• Infrastructure and Investment: Since the gas volumes have decreased, the infrastructure
needed for the gas capture project would likely be little affected, which with the lower gas
volumes and field pressure could require more compression capacity – the highest cost
component. This implies that investment per cubic meter of gas captured has increased,
perhaps substantially.
• Economics: In the initial GGFR project, the economics of the gas capture projects were
marginal and thus the importance of earning and selling carbon credits related to the GHG
reductions. Given the substantially lower gas volumes, the economics could well be even
more marginal, and any value of carbon credits is speculative.
• Security, while an issue in 2005, is a greater issue today and must be considered in assessing
options.
6 Armstrong, H “The In-Amenas Attack in the Context of Southern Algeria’s Growing Social Unrest” CTC Sentinal, Volume 7,
Issue 2 https://ctc.usma.edu/the-in-amenas-attack-in-the-context-of-southern-algerias-growing-social-unrest/
10
Figure 5 Location of the Proposed Flare Projects in Relation to Existing O&G Infrastructure
Source: Modified and expanded version based on ALNAFT 20137 (The full map is included in Annex 1)
It should be noted that several major gas projects have been implemented over the last few years
and have successfully increased gas production, however these projects have apparently been
exclusively focused on NAG and that little effort has been made toward capturing AG and reducing
flaring. Such a policy is likely driven by the higher economic returns related to NAG and imply that
GHG reduction and non-flaring policies are not having the desired effect.
5.0 Structure of the Algerian Oil and Gas Sector
5.1 Principal Actors and Stakeholders
The modern Algerian energy sector was born of the 1971 nationalization of the French-owned assets
in the oil sector. Sonatrach was set up and given the responsibility for the full development and
operation of the sector, albeit state control has been relaxed over time to bring in Production
Sharing Contracts (PSC) with private international oil companies so as to tap their expertise and
finance. In the PSCs, Sonatrach typically holds a 51% non-operating interest in the PSC blocks.
7 Alnaft website:
http://www.alnaft.gov.dz/images/outils/outils/CARTE_DE_RESEAU%20_DE_TRANSPORT_DES_HYDROCARBURES_TRC_201
3.pdf (25/03/2019)
11
There are many actors in the oil & gas sector, but the Ministry of Energy and Sonatrach acting
together are the dominant players. The sector is of such economic importance to the country, the
Presidency is assumed to take a direct role in all major decisions. As the de facto implementer of oil
and gas policy, Sonatrach has a pervasive role and is the implementer of government policies.
In 2005 Hydrocarbons law took away Sonatrach’s direct regulatory role in the sector and assigned it
to two agencies. Figure 6 illustrates its current organizational structure.
Figure 6 Schematic of Principal Algerian Oil & Gas Sector Actors
Note: The % share of oil and gas resources are generally reported estimates. Sonatrach does not provide this information.
Annex 2, Note 3 shows the major stakeholders involved in flaring and their roles.
Source: CLN
The Ministry of Energy and Mines
The Ministry is the dominant player in the Algerian energy sector via its policy and administrative
role and has direct supervision over Sonatrach. It also has major influence on the regulatory agency.
Sonatrach
Sonatrach, dominates the country's hydrocarbon sector, owning roughly 80% of all hydrocarbon
production as well as most midstream and downstream infrastructure. While private companies play
an important role, Sonatrach is the largest field operator. By law, the company is granted the
majority ownership of oil and natural gas projects but is not the operator in PSC contracts.
Ministry of
Energy & Mines
Own Operations,
80 % of Oil & Gas
Resources, Primarily
Appionted
Management
Sonatrach (State Oil Company)
Private Operators,
20 % of Oil & Gas
Resources, Newer Fields
Oil & Gas ResourcesState Share
100 %
51 %
Flaring Volume
Almost all
Minor
Algeria Oil & Gas Sector
ALNAFT
(Regulator)
Responsible for flaring
permits and collecting
of flaring fees
12
In 2017, Sonatrach had revenues of 33.2 billion US$, an increase of 19% from 2016 (driven primarily
by the higher oil price). The company’s substantial assets make it the largest oil and natural gas
company not only in the country, but also in Africa.8
Regulators
Two regulators exist; National Agency for the Valorization of Hydrocarbon Reserves (ALNAFT) and
Hydrocarbons Regulatory Authority (ARH) both created under the 2005 Hydrocarbons Law.
National Agency for the Valorization of Hydrocarbon Reserves (ALNAFT)
ALNAFT is primary regulatory agency in the O&G sector and has the responsibilities for gas flaring
matters including the issuing of permits for flaring (on an exceptional basis) and collecting flare
penalties. The gas flaring fee was set at 8000 dinars/000m3 in 2005 and with periodic adjustment
was reported during the mission to now be set at 20,000 dinars/000m3.
ALNAFT has broad responsibilities, and its website9 lists the following;
• Evaluate the hydrocarbon mining sector by carrying out basin studies,
• Promote investments in hydrocarbon research and exploitation,
• Manage and update the database on hydrocarbon research and exploitation under the
responsibility of the Minister in charge of hydrocarbons,
• Study and approve development plans and their periodic updates and the granting of
prospecting authorizations,
• Call for tenders and evaluate tenders for research and / or exploitation activities and
conclude contracts, monitor and control, as a Contracting Party, the execution of research
contracts and/or exploitation in accordance with the provisions of the Hydrocarbons Act,
• Ensure that the exploitation of hydrocarbon resources is carried out respecting optimal
conservation,
• Collaborate with the departments of the Ministry in charge of hydrocarbons in terms of
sectoral policy and the drafting of regulations governing hydrocarbon activities,
• Monitor, control and audit the costs related to the activities covered by the research and / or
exploitation contracts,
• Determine and collect royalty and proceed to its repayment to the Treasury,
• Ensure that the operator has paid the petroleum income tax (TRP) and the land tax, as well
as, if applicable, the payment of taxes relating to the flaring of gas and the use of water,
• Collaborate with the tax administration for the exchange of tax information concerning
research and/or exploitation contracts,
• Consolidate a medium and long-term plan for the hydrocarbon sector, based on the medium
and long-term plans of the contractors, and send it annually to the Minister in charge of
hydrocarbons,
• Maintain and update a state of gas reserves, a state of gas requirements for the satisfaction
of the national market and a statement of the quantities of gas available for export,
• Ensure that the supply of the national market is assured by the contractors,
• Periodically determine a gas reference price and the basic prices of exported products (crude
oil, condensate, LPG).
Interestingly in these fifteen specified responsibilities, while “optimal conservation” is mentioned, no
direct reference is made of flaring or venting, nor the setting or collection of flaring fines and fees.
8 EIA 2016 9 Alnaft website: http://www.alnaft.gov.dz (01/11/2018)
13
The Agency is under the supervision of a five-member Management Committee. The members are
nominated by the Minister of Energy and Mines and appointed by Presidential decree.
While a strong legal framework on flaring is in place and flaring fines are high, in 2011 the WB/GGFR
noted there was little evidence of monitoring, reporting, and tax collection and this may in part be
attributable to the political power of Sonatrach.10
Hydrocarbons Regulatory Authority (ARH)
ARH implements and enforces regulations related to technical and transportation tariffs as well as
free access to oil and gas infrastructure. It also oversees the implementation of environmental
regulations in the hydrocarbon sector, specifically:
• designated to take charge of control and regulation of mission activities in the field of
hydrocarbons as well as issues related to industrial safety and the environment
• oversees the transparent operation of natural monopolies, non-discriminatory third-party
access to pipeline and storage systems, and the regulation of margins on the domestic
market for natural gas and petroleum products
• develops and updates an indicative supply program for the domestic market in petroleum
products
• authorizes pipeline transport concessions and manages and monitors them. Similarly, it
authorizes storage and/or distribution activities of petroleum products
• safety inspections of hydrocarbon facilities
• ensures compliance with the regulations applicable to hydrocarbon activities, including on-
shore and off-shore activities and approves Environmental Impact Assessments.11
Despite these wide-ranging responsibilities, it does not appear that ARH has any direct role regarding
flaring or venting (except on a safety basis).
Private O&G Companies
Private companies play a notable role in the O&G sector, especially related to investment and
development of new hydrocarbon resources. While flaring data per company is not publicly
available, their total flaring amount is believed to be much lower than that of the state company.
They all operate in close cooperation with Sonatrach. The most active companies include Anadarko,
ENI, BP. Other include CEPSA, Repsol, Total, and Equinor.
Anadarko is the biggest international oil company operating in Algeria. It signed production-sharing
agreements with Sonatrach in the late 1980s and since then has produced oil from three mega
projects located in the Sahara Desert. The company has recently completed a project at its El-Merk
facility that minimizes flaring by reinjection of the AG.
BP focuses on gas and operates two major NAG fields: In-Salah and In-Amenas. The In-Salah gas has
a high CO2 content, and BP undertook a major project to remove the CO2 and reinject the gas into
the field. In-Amenas has recently completed a major expansion of its production.
10 WB/GGFR Presentation, 2011, “ International Practices in Policy and Regulation of Flaring and Venting in Upstream
Operations” http://siteresources.worldbank.org/INTGGFR/Resources/578035-1164215415623/3188029-
1324042883839/1_International_Practices_in_Policy_and_Regulation_of_Flaring_and_Venting_in_Upstream_Operations.p
df 11 ARH website: http://www.arh.gov.dz/index.php/fr/ (01/11/2018)
14
ENI has major investments in both oil and gas. ENI also imports gas via the Enrico Mattei Algeria-Italy
pipeline, making it a major customer as well as producer of Algerian gas.12
In recent years, Algeria has had difficulties attracting foreign investors. In the most recent licensing
round in 2014, only 4 of 31 blocks were awarded, and no additional licensing rounds have occurred
since. Some analysts believe that the lack of fiscal incentives to attract foreign investors to new
projects, coupled with past Sonatrach corruption allegations, are to blame. Algeria's precarious
security environment has also been a concern for investors.
Several projects are in the planning and development stage, albeit several of these have had their
implementation dates postponed in the past. (Note 4)
5.2 The Gas Market
Domestic Gas Market
According to the International Energy Agency, natural gas accounted for 93% of power generation in
Algeria in 2013.13 Algeria has an important initiative regarding expanding renewables in the
electrical sector, which will impact gas demand, but this is only now beginning. The Electricity and
Gas Regulation Commission (CREG) forecast for the decade 2014 - 2023 (considering the renewables
program) estimates gas demand growth of 5.2%/year in a central scenario, resulting in a demand of
54.6 bcm in 2023. If the renewables program is implemented successfully, growth in gas demand
would start to moderate mainly post- 2023. Using these parameters, the 2030 gas demand could be
70 bcm, representing a major claim on Algerian gas production.14
It should be noted that there are substantial subsidies and price distortions in the sector, and policy
adjustments could have significant impacts in limiting future demand.
International Gas Market
As of 2016, Algeria was the seventh largest exporter of LNG in the world as well supplying gas via
international gas pipelines. Algeria has four LNG units along the Mediterranean Sea with a total
design capacity to process 44 mt/year of natural gas plus three pipeline connections – the largest to
Italy and two smaller ones to Spain.
Until recently Algeria's natural gas exports have gradually declined, apparently limited by both gross
production decreases and domestic consumption increases. In 2017 however, natural gas exports
were 53 bcm, a major increase over the last several years, driven by increased pipeline exports to
Europe15. Algeria faces pressure to boost natural gas output so at to meet growth in domestic
demand and maintain its international gas markets (See Note 2 on issues in Algerian gas production).
5.3 Legal and Regulatory Framework for Gas Development and Valorization
Oil and gas activities in Algeria were governed by law number 86-14 of 19 August 1986 until
replacement with law n°05-07 dated 28 April 2005 (Hydrocarbon law) that liberalize to some degree
the sector. To further attract foreign investors to exploration and development of unconventional
hydrocarbons, the laws were amended (n°13-01 dated 20 February 2013). These laws apply to both
12 Information on all four private companies is from the companies’ websites 13 Cited in EIA 2016 14 Aissaoui A, 2016 15 BP 2017
15
upstream and downstream oil and gas activities. Key points to note with regards to these laws could
be summarised as follows:
Ownership oil and gas reserves: Article 3 of law n°05-07 of 28 April 2005, states that
Government owns all oil and gas reserves. This was relaxed in 2013. In Article 25 of law n°13-
01, oil and gas reserves are State’s property until they are extracted, and title of minerals
transferred to the contracting party.
Hydrocarbon contracts and State participation: Article 24 of the law referred to ‘Exploration
and Exploitation Contract’ usually awarded after transparent and competitive tender
exercise as approved by decree. These contracts have state participation clause with
minimum equity stake not less than 51%. The state does not bear the cost and the risk of
exploration.
License duration: According to article 35 of the law, exploitation period is 25 years for oil and
30 years for gas in conventional zone while unconventional zone, 30 years for oil and 40
years for gas.
Gas Flaring: Amended slightly in 2013, gas flaring is prohibited, but the Government on
exceptional basis and at operator’s request could grant Flaring Permit (FP). Contrary to the
previous law, duration of the FP is no longer set. Revised article 52 of the law allows quantity
of gas that can be flared, and flaring permit details set by ALNAFT by decree, on case by case
basis. The gas flaring prohibition law does not make distinction between existing AG fields
and new oil developments.
During the mission it was confirmed that the flare fine was 20,000 dinars/m3, however the
granting of exemptions and its enforcements was not clarified.
Gas Master Plan: This requirement is dictated by the law. According to Article 62 of the
Hydrocarbon law, a ten-year Gas Master Plan shall be drafted by ALNAFT and regularly
updated.
Domestic Market Obligations and Gas Sale Contracts: Article 51 of the Hydrocarbon law,
states ALNAFT could ask gas producer to help meet national market with respect to their
production.
For Gas Sale Contracts, two regimes are bound by the Hydrocarbon law: For sales on the
local market, the sale price is determined by ALNAFT considering a series of criteria listed in
Article 10 of the Hydrocarbon Law (market-based energy pricing).
Gas intended to be traded on international market, and in accordance with Article 48 of the
Hydrocarbon law, the gas sale contracts must contain; a joint sale clause with
SONATRACH and copies of these contracts must be sent to ALNAFT for verification and
information purposes.
Fiscal incentives: to encourage gas utilization investments, special fiscal treatment such as
investment tax credit or uplift or reduced rate for corporate tax is applied to LNG, LPG and electricity
generation projects (see Articles 88 and 91 of the Hydrocarbon Law).
16
6.0 Geological and Production Technical Issues
Most proved oil reserves are in the country's oldest and largest oil fields. Hassi Messaoud, located in
the eastern part of the country, near the Libyan border, is estimated to hold 3.9 billion barrels of
proved and probable recoverable reserves, followed by the Hassi R'Mel field (3.7 billion barrels) and
the Ourhoud field (1.9 billion barrels).16 According to Sonatrach, the Hassi Messaoud- Dahar province
contains about 71% of the country's combined proved, probable, and possible oil reserves, while the
Illizi basin, the second-largest area, contains about 15%.
Oil and gas fields are largely located on a northeast of a northwest-southeast-trending line
connecting Hassi Messaoud with In-Amenas. Recent discoveries have been made in upper Paleozoic
and Mesozoic reservoirs. Hydrocarbons are present throughout the entire sedimentary column, but
major production currently is restricted to the lower Paleozoic (Cambrian-Ordovician and Lower
Devonian) and Triassic reservoirs. Algerian oil fields tend to be high-quality light crude oil with very
low sulfur content. 17
The Ghadames Basin, encompassing eastern Algeria, southern Tunisia, and western Libya, has been
identified as a major shale gas basin. Algeria is estimated to hold the third-largest amount of shale
gas resources in the world. The U.S. EIA estimates that Algeria contains 707 trillion cubic feet (Tcf)
and 5.7 billion barrels of technically recoverable shale gas and oil resources18.
Preliminary exploration work for the shale has been undertaken, but the costs and barriers of
development (including sufficient water) cause uncertainty as to its future development.
As to the composition of the gas, both AG and NAG tends to be of good quality – meaning no
significant impurities and relatively high energy content. The gas tends to have a relatively high
percentage of higher carbon molecules, C3 and above, but not excessively so. Extraction of C3+
generally occurs at treatment hubs, which suggests that AG flared at the field includes the NGLs.
In one case, the in-Salah project operated by BP, the NAG has a high concentration of CO2, 7%;
significantly above the 2% that is allowed in the gas market. The CO2 is stripped out (0.3% remaining)
and instead of being vented, is reinjected into a sealed reservoir. This is the only one of such CO2
reinjections in Algeria, and one of the very few in the world.19
16 Arab Oil & Gas Directory cited in EIA 2016 17 Attar, A., Chaouch A, Petroleum Geology of the Major Producing Basins of Algeria, AAPG 1988, and EIA 2016, 18 EIA 2015 19 Fairly, P., 2008, “Algerian Carbon Capture Success”, MIT Technology Review
https://www.technologyreview.com/s/411417/algerian-carbon-capture-success/
17
Annex 1: Map: Oil and Gas Infrastructure in Algeria
Source: Modified and expanded version based on ALNAFT 2013 20
20 Alnaft website:
http://www.alnaft.gov.dz/images/outils/outils/CARTE_DE_RESEAU%20_DE_TRANSPORT_DES_HYDROCARBURES_TRC_201
3.pdf (25/03/2019)
18
Annex 2: Notes and Illustrations
Note 1: Flared Gas vs. Gas Production
Source: Toledano P
Note 2: Issues Related to Algerian Gas Production
While the decline in Algerian gas production has been well observed, the general belief is that it has
been brought about by natural production depletion decline in the old, mature fields and that it
could be easily reversed by bringing on new gas production. Indeed, this seems to be the
government policy. However, Ali Aissaoui in a paper produced under the Oxford Institute for Energy
Studies sees a much more problematic situation.
He notes that since 2004, Algeria’s primary energy demand grew at an average annual rate of 4.1%
while domestically-sourced energy supply decreased by 0.8%/year, resulting in a contraction of total
hydrocarbon export volume of 2.6%/year. Natural gas flows are impacted as well. Their decline is
first noticeable in gross production, which dropped from 201.2 bcm in 2008 to 179.5 bcm in 2013
before slightly improving to 186.7 bcm in 2014 as Gassi Touil and El Merk (associated gas) came on-
stream. (It does improve in 2016, CLN).
Importantly wet natural gas production in Algeria is cycled for liquids content and that the bulk of
this process takes place in Hassi R’Mel. Once stripped of NGLs, gas is partly re-injected to maintain
stable reservoir pressure and avoid retrograde condensation and the excess dry gas is then supplied
to the domestic and export markets.
19
It can be inferred, from the declining trends in gross production and the volumes of gas re-injected,
that there may not have been enough raw gas to maintain the cycling process at its optimum level.
(Indeed, with the continued depletion of the oil reservoirs, the reinjection level could grow
substantially CLN). This in turn suggests that, notwithstanding additional volumes supplied during
the last decade from Ohanet, In-Salah, In-Amenas, Gassi Touil, El-Merk and Menzel Lejmat,
production is on a clear decline.
Cost of gas production is also raising. Assuming existing fields are producing at plateau levels, a
weighted-average unit cost of production is about $0.60/MMBtu. Obviously, the cost is higher – up
to $0.70/MMBtu - if we assume lower production rates from depleting mature fields, which is closer
to reality. As for the long run marginal cost of supply it may be approximated by the unit cost of
production from the upcoming, most expensive tight-gas project, i.e. Timimoun, at $4.70/MMBtu.
These trends in both volumes and costs have raised concerns over the depletion of easily accessible
gas with low production costs and have prompted a serious review of the country’s reserves and
resources.
Note 3: Key Stakeholders on Flaring in the Algeria’s O&G Sector
Stakeholders Who they are Influence on Flaring
Ministry of
Energy & Mines
Policy, strategy and administrative
oversight for the sector. Directly
controls Sonatrach
Ultimate decision maker
Partner GGFR
Sonatrach
State O&G company, controls 80%
of production21: interests in
remaining 20%, by far largest flare
operator
Decisive. Sonatrach support
necessary for flare reduction;
largest flare source
Partner GGFR & ZRF 2030
Regulators
ALNAFT
Grants permits for flaring
exemptions and collects flare
penalties
Has mixed priorities, and
limited power
ARH
Oversees tariffs and free access
regulations as well as
environmental regulations
including CO2 emissions.
Minor role, unclear as to
effectiveness
Private Companies
Multiple International, public O&G
companies
Flaring appears limited to
operational, generally follow
Sonatrach direction
NGOs
None identified, O&G sector
considered national security area
Donors
WB/GGFR Very active prior to 2010, limited
activity now
Source: CLN
21 Sonatrach does not provide breakdowns between oil and gas production, but for both categories the share is believed to
be in the 80% range.
20
Note 4: Planned Gas Projects -- 2016
Project name Companies
Peak
output
(Bcf/y)1
Target start
year
South West Gas Project: Phase 1
Touat Engie/Sonatrach 155 2016
Reggane Nord Repsol/Sonatrach/DEA/Edison 155 2017
Timimoun Total/Sonatrach/Cepsa 64 2017
South West Gas Project: Phase 2
Ahnet Total/Sonatrach/Partex 141 2018
Hassi Ba Hamou Sonatrach 64 --
Hassi Mouina Sonatrach 49 2018
Other Gas Projects
In Salah (expansion)2 BP/Sonatrach 500 2016
Isarene (Ain Tsila) Petroceltic/Sonatrach/Enel 127 2018
Tinhert, Illizi basin Sonatrach 332 2018
Menzel Ledjmet SE Sonatrach 155 2019 1 Billion cubic feet per year is Bcf/y.
2 Field expansion at In Salah is to ensure that the current level of output at In Salah is maintained.
Source: Middle East Economic Survey
Source: EIA 2016
21
Note 5: Major Sources
Aissaoui A. “Algerian Gas: Troubling Trends, Troubled Policies” Paper: NG 108, Oxford Institute for
Energy Studies, Oxford, May 2016
Bengrina M. H., Sigra A.R. L’étude d’impact environnemental – facteur de valorisation des
ressources gazières de l’Algérie ou entrave bureaucratique, presentation at International Workshop
on Global Gas Markets, Oran, 1-2 December 2014
Klett T.R. Total Petroleum Systems of the Illizi Province, Algeria and Libya—Tanezzuft-Illiz, United
States Geological Survey, Denver Colorado, 2000
Sonatrach HSE, “Efforts de SONATRACH dans la réduction des gaz à effet de serre” presentation at
Salon International des Energies Renouvelables, des Energies Propres et du Développement Durable,
Oran, 27-29 October 2015
Toledano P., Karishma P., Banerjee S. “Algeria: Associated Gas Utilization Study”, presentation at
Columbia Center for Sustainable Investment, New York, May 2017
US Energy Information Agency (EIA) “Technically Recoverable Shale Oil and Shale Gas Resources:
Algeria” September 2015, Washington DC
US Energy Information Agency (EIA), “Country Analysis Brief, Algeria” March 2016, Washington DC
World Bank GGFR: “CDM Capacity Building Pilot Projects for Gas Flaring Reduction in Algeria, 2004
(other sources noted in footnotes)