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From Burden to Opportunity – Associated Gas Utilisa tion in Nigeria Raphael S Awoseyin, Oando PLC, Nigeria

February 2012

Abstract

While Nigeria's enormous gas resources is the envy of many countries, and of industry operators in many countries, most of the major hydrocarbon prospecting license holders saw the resource as something of a burden. Without government fiat, most would have no interest in the domestic gas market. Despite this – and adding to the puzzle – is the fact that Nigeria is one of the world's greatest contributors to global warming through gas flaring. This paradox resulted from an ill-informed government approach, and a conventional but narrow-viewed approach by industry operators. However, operators are today seeing the poor social infrastructure in much of the hydrocarbon producing areas of the country as providing an opportunity to reconcile the seemingly conflicting objectives. If operators would move away from the concept of gas gathering for central utilisation, to a decentralized energy conversion approach, routine gas flaring could be stemmed while the economies of host communities could be boosted. A further benefit could be the economics of marginal field development.

Introduction

Nigeria's proven gas reserves is currently estimated at 187 trillion standard cubic feet (tcf) – equivalent to 33 billion barrels (bbl) and about equal to the country's proven oil reserves in terms of barrels of oil equivalent (boe). Approximately 35% of the gas reserves are in form of solution gas – gas that is dissolved in, or associated with oil. Such associated gas (AG) can only be produced along with the oil. It is the flaring of AG that has earned Nigeria the infamy of being one of the top gas-flaring countries in the world – possibly second only to Russia.

When Shell D’arcy commenced oil exploration in Nigeria in the fifties, the only interest was oil. Neither the then Nigerian government (of the British at that time) nor Shell viewed AG as having any value. The licenses the government issued to Shell were Oil Prospecting Licenses (OPL), underscoring this fact. Till today, the Nigerian government issues Oil Prospecting Licenses to companies, even though the value of gas is now better appreciated, and the OPL covers prospecting for gas as well! It was this mindset in both the government and the prospecting companies that shaped investors’ attitude in the industry.

Electric power generation in Nigeria was for decades fuelled by coal, drawing on the large coal deposits in Eastern Nigeria. Much later, hydro-electric power kicked in with the likes of Kainji Dam, Shiroro, and Kura Falls. However, during the seventies, the government was sensitised to the potential link between electric power generation and hydrocarbon gas. This gave rise to the first set of non-associated gas (NAG) processing plants.

Neither the government’s policy makers nor the oil prospecting companies could connect the dots of electric power and hydrocarbon gas. There were of course no industries that considered use of natural gas. The result was that AG was seen as a waste product that had to be burnt as a by-product of oil production. In its basic form, a typical flowstation design comprised an inlet manifold where flowlines from the wells tie in, two-phase or three-phase separation facilities, pumps to deliver the liquids to the export terminal, and a gas flare line.

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Fig. 1: The most basic oil production infrastructure

This remained the basic concept of oil field development in Nigeria for decades. Scores of flowstations across the Niger Delta flared AG as part of their normal process. It was considered inevitable. That was until the global community woke up to the danger posed by global warming, and attention was focused on those countries known to be big contributors. Nigeria was, and still is one of them.

Stranding of Associated Gas

As it became inevitable to pursue an end to routine gas flaring in oil production, operators viewed that the only way to deal with the problem was to construct a network of compressors and pipelines to gather associated gas from the flowstations and transmit to potential consumers in the few industrial centres in the country. However, there were significant challenges to this approach:

• While the AG volumes were big enough to be a nuisance when flared, the volumes were too small to form the basis of continuous supply to consumers. There would have to be non-associated gas as the main supply source into which associated gas would be spiked.

• By far the largest consumer of natural gas would be the thermal stations owned and operated by the public power utility company. Power tariff was, and still is controlled by the government and pegged at such levels that made the entire gas commercialisation business unattractive as a project. The economics of commercialising AG was even worse. On the average, the cost of transmitting AG to a location 100km from source is about five times the cost of transmitting an equivalent volume of NAG.

Eventually, some operators that struck commercially attractive deals with private gas consumers (like glass or cement manufacturing industries), and that had NAG reserves, developed such reserves to serve specific customers. Then, if there was a flowstation nearby and the AG was of reasonable volume, a booster compressor could be installed to inject the AG into the NAG stream. Otherwise, the AG was flared.

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The Classical Solution

The standard solution developed by operators for handling AG comprises compression, dehydration, conditioning, and sale.

Fig. 2: The Classical Solution for Associated Gas Utilisation

Compression is required because the gas is at the production separator pressure which is too low to propel the gas through processing and delivery to the point of use which could be:

• Re-injection into the reservoir for pressure maintenance • Transmission to some remote location for power generation or manufacturing

It is the cost of this compression that makes AG utilisation so unattractive.

The NNPC Complicity

Despite the high cost of AG compression and utilisation, from the early eighties, industry operators – all exclusively IOC's (international oil companies) started to propose AG gathering (AGG) projects as part of their JV (Joint Venture) work programme – the Nigerian government, through the Nigerian National Petroleum Corporation (NNPC), owns majority (55 to 60%) stake in the onshore operation of the IOCs. Operations and projects executed by JVs are funded by cash calls from the JV partners in proportion of their participation. Now, the NNPC must approve programmes proposed by the JV operators before the programmes can be accepted as the basis for cash calls. Unfortunately, while the IOCs proposed AGG projects in the spirit of operational excellence, their NNPC partner was only interested in oil. The result was that in the annual JV budget ranking, AGG projects rarely made it above the line.

However, NNPC in the late eighties came up with its own strategy for dealing with AG. After building the Escravos-Lagos Pipeline System (ELPS) – built primarily to transport gas from the Niger Delta to Lagos where the largest power plant in the country and most industries are situated, NNPC rightly saw an

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RE-INJECTION

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opportunity to deal with the AG problem. First, it made clear to the JV operators that the AG did not belong to the operators but only to the NNPC. This position actually alienated the IOCs from the problem – if Shell, operator of the NNPC-Shell-Total-Agip JV was being told that it had no share in the AG, why should Shell put its money into dealing with the AG problem? Having established this position, the NNPC then proceeded to proffer its own solution. It got its subsidiary NGC (Nigerian Gas Company) to install AG compressors adjacent to many Shell-operated flowstations to mop up the AG from the flowstations and deliver same into the ELPS. Sadly, many of those compressors never worked largely because their design was not matched to the AG volumes from the flowstations – the AG volumes were too small to prime the compressors. But even if they had worked, there was the potential degradation of the gas quality in the ELPS as compression alone would not deliver the design specifications for the ELPS gas; proper treatment involving both water and hydrocarbon dew-point control was needed.

Recent Developments

With the multinationals as the JV asset operators, they constantly face criticism over gas flaring. Besides international focus on gas flaring, even the Nigerian National Assembly made it an issue. In developing a strategy for dealing with the AG, Shell saw that the compressors NGC had installed, which hardly worked, could in fact be integrated into a solution. The solution was to revamp those compressors and, where possible, use them to deliver the AG to nearby NAG conditioning plants which deliver sales-specification gas to the network. Of course, this was still very much along the line of the same traditional solution. It also does not address the fact that the NGC compressors were in some cases not matched to the AG volumes from the flowstations.

The New Thinking

This author advances the view that a fundamentally different approach is necessary. Essentially, the new thinking is to utilise the AG at, or close to its source in such a way that it could fuel rapid development in the neighbourhood. Already, a small part of the AG from flowstations is used to generate power for use in the flowstation. Consider the following extensions of this concept:

• Install generation capacity to consume possibly all the AG from a station’s production, and transmit the power up to a 50km radius neighbourhood. Where the neighbourhood is currently not connected to the national electricity grid, it could mean a major transformation of the economic life as cottage industries could spring up utilising the power.

• With a small pressure boost, the AG could feed a chemical processing plant built next to the flowstation. An example of this is the co-operation between the Energia/Oando Joint Venture development and Energia Gas Processing, in OML 56 in the northern Niger Delta. Here, the small volume of 25 MMscf/d AG from the marginal field is processed to produce about 280 bpd of LPG (butane), deliver excess propane to a future high-octane field additive (HOFA) plant. Unfortunately, the dry methane from this plant is still flared. This dry methane could be fuel for power generation that could support local cottage industries.

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Fig. 3: Alternative Options for Associated Gas Utilisation

A Help to Marginal Fields Developments

Marginal fields are those hydrocarbon discoveries in volumes that are so small that the economics of their development would at best be marginal. Typically, such fields have less than 50m boe P2 reserves and are located remote from existing evacuation infrastructure. In many cases, these marginal fields are located onshore where environmental regulations are most stringent.

The main challenges to marginal field development economics are:

• Evacuation pipelines for the oil: A common solution for evacuation of oil from marginal fields is trucking – the operator transports degassed oil in road tankers to some evacuation node or a refinery.

• Produced water disposal: Produced water may be handled by re-injection into a suitable formation in the field. This is indeed the method favoured by the Nigerian regulatory authorities. However, in some arid countries the operator treats the produced water and uses it for irrigation.

• Associated gas utilisation: Associated gas poses the greatest challenge. Re-injecting it into the formation requires expensive compression, the cost of which often frustrates the economics. It is this type of situation that the approach being espoused by this author could be helpful.

Summary

In summary, a strategy that focuses on utilisation of associated gas at or close to its source of production holds promise for all stakeholders: Local communities could experience rapid development and cottage industrialisation, the environment would be all the better as less land would be required for fluid transmission pipelines, and otherwise uneconomic marginal oil fields could become economically viable. The new indigenous players in the upstream sector, many of whom have only marginal fields to start with, would benefit from this approach.

Tank

Tank

Tank

WATER

OIL $$$

GAS

LIQUID

3-phase

3-phase

3-phase

To LNG

Manufacturing

Power Distribution

POWERGEN

POWERGEN

DEHYDRATION

CONDITIONING

ASSOCIATED GAS UTILISATION OPTIONS

OIL DEHYDRATION AND EXPORT

RE-INJECTION

FR

OM

WE

LLS

From Burden to Opportunity – Associated Gas Utilisa tion in Nigeria - R.S. Awoseyin

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The Author:

Dr. Raphael Awoseyin is Chief Engineering and Technology Officer for Oando Group.He had previously spent 24 years in Shell, 4 of which were in the Sultanate of Oman. He left Shell Nigeria in 2008 as General Manager Gas Development to join Oando. He holds a BSc in Mechanical Engineering from the University of Greenwich (UK) and a PhD from Pacific Western University. His technical articles have been published in international journals, and is the author of RAFFLO – a pipeline network hydraulics simulation program (www.rafflo.com).