flow assurance and sour gas

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NORWEGIAN UNIVERSITY OF SCIENCE AND TECHNOLOGY DEPARTMENT OF PETROLEUM ENGINEERING AND APPLIED GEOPHYSICS

TPG 4140 - NATURAL GAS

Flow Assurance and Sour Gasin Natural Gas Production

Egor Bokin, Feby Febrianti, Eldar Khabibullin,Carlos Eduardo Sanchez Perez

Trondheim, November 2010



TPG4140 - Flow Assurance and Sour Gas in Natural Gas Production ii

Abstract

The main objective of this study is to analyze flow assurance and sour gas problems in natural

gas production in Indonesia, Venezuela and Russia. Hydrate and wax appearance are thetraditional issues for Russian offshore gas production. This study considers flow assurance at

Sakhalin-2 project on Russian Continental Shelf. Monoethylene glycol system is used to

prevent hydrate formation in multiphase pipelines. Wax prevention strategy is based on the

regular cleaning of pipelines and flowlines.

In the case of Indonesia, the main component of natural gas reservoirs is CO2. In the Natuna

field CO2 represents 71% of the gas. Despite of this, Natuna is very attractive for the

significant quantity of natural gas deposited in this field. The present study shows the

different technological alternative of treatment and disposal of CO2 in Natuna.

Regarding to the Venezuelan case, there are significant reserves of natural gas associated with

heavy and extra-heavy oil. It is necessary to ensure the heavy and extra-heavy oil production

and transport to exploit natural gas there. This paper explains the challenges and possible

alternatives of heavy and extra-heavy oil exploitation in Venezuela, especially in the Orinoco

Oil Belt. This report reveals the current situation in the Orinoco Oil Belt, including some

political issues, and the technology applied there.



TPG4140 - Flow Assurance and Sour Gas in Natural Gas Production iii

Table of Contents

Abstract ........................................................................................................................................... ii

1 Introduction...............................................................................................................................1

2 Flow Assurance Phenomena .....................................................................................................2

2.1 Gas Hydrates....................................................................................................................2

2.2 Corrosion .........................................................................................................................2

2.3 Wax Precipitation and Deposition ...................................................................................3

3 Flow Assurance in Offshore Russia..........................................................................................5

3.1 Sakhalin-2 Project Overview...........................................................................................5

3.2 MEG System Details .......................................................................................................5

3.3 Hydrates Prevention Strategy ..........................................................................................6

3.4

Economical Estimations of MEG System........................................................................6

3.5 Wax Issue on Sakhalin-2 Project .....................................................................................8

4 Flow Assurance in Heavy Oil Production in Venezuela ..........................................................9

4.1 Heavy Oil Overview in Venezuela ..................................................................................9

4.2 Production of Heavy Oil in Venezuela ..........................................................................10

4.3 Transport of Heavy Oil in Venezuela ............................................................................11

5 Sour Gas in Natuna Gas Field, Indonesia ...............................................................................14

5.1 Natuna Gas Field Overview...........................................................................................14

5.2 CO2 Removal Technologies for Natuna Gas Field ........................................................14 5.3 CO2 Disposal in Natuna Gas Field.................................................................................15

6 Discussion...............................................................................................................................16

7 Conclusions.............................................................................................................................18

8 References...............................................................................................................................19

9 Tables......................................................................................................................................23

10 Figures ....................................................................................................................................25

11 Appendix.................................................................................................................................33

11.1 Appendix A – History and Projections for Energy Consumption .................................33 11.2 Appendix B – Platform Luna-A and OPF .....................................................................34

11.3 Appendix C – Multiphase Pipelines Profile and MEG Injection Graph........................35

11.4 Appendix D - Overview of the Orinoco Heavy Oil Belt (The Faja) .............................36

11.5 Appendix E - Pumping Systems Applied in Venezuela ................................................37

11.6 Appendix F - Orimulsion...............................................................................................38



TPG4140 - Flow Assurance and Sour Gas in Natural Gas Production 1

1 Introduction

Flow assurance is a relatively new term in oil and gas industry. It describes the phenomena of

precipitation and deposition of solids, and offers technical solutions at amenable cost without

risk to installations, operators and the environment (Gudmundsson, 2010). Flow assurance

very often appears in offshore oil and gas production.

Over the last decades offshore production gradually increased due to relatively high oil and

gas prices and decreasing of “easy” onshore resources. With the development of offshore

production new technologies are introduced. One of them is multiphase transport via

pipelines. It is necessary to ensure safety and economical multiphase flow of hydrocarbons

using flow assurance solutions.

In addition to the precipitation and deposition of solids, the flow assurance faces other obstacles. For example, if the natural gas is associated with oil, it is necessary to ensure oil

production before exploiting gas. In the specific case of heavy oil, production and

transportation are very challenging because oil viscosity is very high. There are immense

reserves of heavy and extra-heavy oil with significant quantities of associated natural gas in

Venezuela. However, it is quite difficult to establish strategies of production, transport and

commercialization of heavy oil. For example, the transport relies on blending heavy oil with

conventional oil and the recovery factor in production is low.

But not only high viscosity heavy oil requires significant efforts to produce it. The

composition of a natural gas itself may be an additional difficulty for gas production.

Different gas fields have different gas compositions. For example, the most gas fields in

Norway have relatively high quality gas in reservoirs with low carbon dioxide and hydrogen

sulfide content. But in case of Natuna gas field, Indonesia, the carbon dioxide content may

achieve 71% of the total gas amount. Undoubtedly, the production of such gas requires new

technologies to be introduced.

Referring above flow assurance and sour gas issues of 3 different cases in 3 different

countries, this report strategically discuss and provide more information about these issues.

Starting with hydrates prevention system in Sakhalin, Rusia, then heavy oil technology in

Venezuela and finally, sour gas treatment in Natuna gas field Indonesia.




2 Flow Assurance Phenomena

2.1 Gas Hydrates

Hydrates are ice-like solids composed of water and gaseous hydrocarbons, which can form in

multiphase transportation systems under conditions of low temperature and high pressure.Hydrate plugging of subsea gas pipelines is a common threat (Fadnes et al., 1998).

The shape of elementary polyhedral cavities and their characteristics are shown in the Figure

2.1. Elementary cavities are formed by the hydrogen bonded water molecules. They trap small

gas molecules inside them (Makogon, 1997).

The requirements for hydrate formation are free water, small gas molecules, low temperature

and high pressure. Temperature pressure curves and zone of hydrate appearance are presented

in Figure 2.2. (Sandengen, 2010). There are several ways to avoid hydrate formation: to keeptemperature high, to keep pressure low or to dilute water. One of the most effective ways is

the injection of monoethylene glycol (MEG) solution into a pipeline. MEG shifts hydrate

equilibrium curve from pipeline operational zone.

2.2 Corrosion

One of the common problems in natural gas production is corrosion. Corrosion is defined as

deterioration of materials, usually a metal, due to its reaction with the environment or

handling media (Mokhatab et al., 2006). Corrosion in multiphase system is a complex

phenomenon. It depends on partial pressure of components, temperature, pH, and

concentration of corrosion products. Consequently, corrosion prediction requires substantial

understanding of the simultaneous interaction of the many process variables that govern both

flow and corrosion condition (Mokhatab et al., 2006).

The presence of sour gases such as H2S and CO2 in natural gas composition from well is one

main factor which causes corrosion. Thus, these have to be removed in order to prevent

corrosion along the pipeline and equipment in natural gas production. In Table 2.1 is shown

technologies commonly used for CO2 removal (Forde, 2010)




2.3 Wax Precipitation and Deposition

Wax precipitation and deposition are important issues in natural gas/condensate production

and transportation. Paraffin waxes are predominantly heavy hydrocarbons, which contain in

natural gas condensate. “Natural gas condensate is a low-density mixture of hydrocarbon

liquids that are present as gaseous components in the raw natural gas produced from many

natural gas fields.” (Wikipedia, 2010). It may contain the following components: hydrogen

sulfide (H2S), mercaptans, carbon dioxide (CO2), straight-chain alkanes (from C2 to C12),

cyclohexane and other naphthenes, aromatics (benzene, toluene, xylenes and ethylbenzene). A

phase envelope with a dew point curve is shown in Figure 2.3.

Wax starts to precipitate upon cooling down of a stream, for example, in long pipelines and

forms deposits. Thus some difficulties during gas/condensate transportation may occur. The

bigger pressure drops, the decreasing of the flow rates or even plugging of the cross-section of a pipeline are the common problems.

Wax appearance temperature, or WAT is the temperature at which paraffin wax starts to

precipitate. Also the term “cloud point” is used (Gudmundsson, 2010). As the condensate is

cooled further below the cloud point, higher amount of paraffin wax is precipitated. A soft

solid formed as a result of paraffin wax mixture being cooled down is called gel. The pour

point is the temperature at which gelling occurs. It should be mentioned that ‘stationary gel

can increase in stiffness with time’ (Gudmundsson, 2010).

A typical precipitation curve shows the amount of paraffin wax precipitated from condensate.

It depends on the extent to which the paraffin wax mixture is cooled down below the WAT.

This curve is called wax precipitation curve, or WPC, and shown in Figure 2.4. “Precipitation

curves can be measured and estimated by modeling” (Gudmundsson, 2010).

The precipitation of paraffin waxes in crude oils and condensates is dependent on the

solubility. As the heaviest waxes are the least soluble they precipitate first, and upon further

cooling on lighter paraffin waxes precipitate. From here one can conclude that with thedistance and, consequently, lower temperatures the density of paraffin waxes precipitated

decreases.

As the precipitation occurs it does not mean that paraffin wax will form a deposit. To

determine paraffin wax precipitation one needs to know thermodynamic equilibrium and the

phase behavior. In addition, pipeline temperature calculations should be carried out and




appropriate deposition models should be applied. In other words, the wax precipitation from

solution does not necessarily lead to the deposit formation on a pipe wall.

Paraffin waxes are crystals with the crystals of small size forming in condensate and of big

size in crude oil (Bacon et al., 2009). Wax crystals can be classified as paraffinic

(macroscopic) and microcrystalline (microscopic). “The stiffness (hardness) of paraffin wax

deposits in laboratory flow loops and operational pipelines ranges from mushy to hard. Mushy

soft deposits are usual in flow loops while hard deposits are found in pipelines”

(Gudmundsson, 2010).

The amount and location of the deposits are the most important things to know while

operating a pipeline with potential wax deposition. The widely used practice is to send a

mechanical scraper (pig) through such a pipeline at appropriate time intervals. Pressure drop,

tracer testing and pressure pulse measurements can be used to monitor paraffin wax

deposition in pipelines. These methods work properly in pipelines with liquids, particularly,

condensate. The most suitable method to determine both the volume and location of paraffin

wax in a pipeline is pressure pulse measurement. This measurement is shown in Figure 2.5.

The most commonly used methods for paraffin prevention are pigging (cleaning up the

pipelines), chemical inhibition and heating while utilizing steam or electricity. For

gas/condensate pipelines pigging are usually used. The typical scrapper is shown in the Figure

2.6. Chemical inhibition and heating may be useful for heavy oil production and transportation. Typical heat tracer and steam heat tracer are shown in the Figures 2.7 and

2.8.It should be mentioned that sometimes these procedures are implemented together to

provide flow assurance solutions for oil and gas industry.




3 Flow Assurance in Offshore Russia

3.1 Sakhalin-2 Project Overview

The first Russian LNG project is located on Sakhalin Island, in the East of Russia. The

Sakhalin-2 Project is one of the largest integrated oil and gas development in the world. It produces 9.6 million tons of LNG per year and about 180,000 barrels of oil per day. The total

project cost reaches 20 billion dollars (U.S. Energy Information Administration, 2008).

There are three platforms PA-A, PA-B and Lun-A which produce oil, gas, water and

condensate (Figure 3.1). Platforms PA-A and PA-B have separation units, therefore oil and

gas are transported to Onshore Processing Facilities (OPF) by different pipelines. There is no

threat of hydrates formation in these pipelines.

The feed from Lun-A platform is transported to OPF by two parallel multiphase pipelines.This feed consists of gas phase, condensate phase, water in a vapour phase, 85% MEG which

is used as a hydrate inhibitor and carrier for corrosion inhibitor. Produced water and MEG

form aqueous phase and three phase flow appears (Figure 3.2). The main issues of these

multiphase pipelines operation are handling of liquids during ramp up and start up, slugging at

low flow rates and hydrate prevention by means of MEG injection. Multiphase pipelines facts

are shown in the Table 3.1.

3.2 MEG System Details

MEG system designed for maximum flow rate 14.3 m3/h and maximum pressure 130 bar. But

it is operated under the flow rate 12 m3/h and pressure 113 bar. The four inches diameter

pipeline connects OPF and platform Lun-A. Lean MEG (85% purity) is pumped into this

pipeline and injected to multiphase pipelines at Lun-A.

There are two P-5602A pumps for MEG pumping: one operating and one standby. Three

MEG regeneration units are used to separate water and condensate from MEG. Each of them

is sized to process 15.6 m3/h of rich MEG (MEG with condensate and water). In addition,

there are two tanks for rich and lean MEG storage. The tanks capacities for rich and lean

MEG are 2755 m3 and 1459 m3 respectively. This MEG system is illustrated in Figures 3.3 -

3.5.




3.3 Hydrates Prevention Strategy

The first element of the hydrate prevention strategy consists of the injection of the correct

amount of MEG and the daily verification of the MEG concentration in the inlet vessels. It is

recommended to inject 12 m3/hr MEG per 1800 MMSCFD gas. The following formula was

used to calculate this amount (Sakhalin Energy, 2008):

The second step in the hydrate management strategy consists of the continuous monitoring of

the MEG injection system. As long as sufficient MEG is injected hydrates will not form

during normal production. However, the injection of insufficient MEG can have serious

consequences such as production deferments and the formation of a hydrate plug.

For gas/condensate lines, a decrease or stoppage of the water production rate is usually thefirst sign that hydrates are forming. An additional problem to spot this first warning sign

might be the unsteady production at low flow rates caused by terrain induced slugging.

However, any major decrease in the aqueous flow should trigger a careful check of MEG

system.

3.4 Economical Estimations of MEG System

“Capital investment is the total amount of money needed to supply the necessary plant and

manufacturing facilities plus the amount of money required as working capital for operation

of the facilities” (Peters, 1991).

The following equipment has been used for MEG system at Sakhalin-2 Project: rich MEG

storage tank, lean MEG tank, pipeline (4 inches @ 21108 m), two pumps P5602-A, three

MEG regeneration units. Rich MEG storage tank may cost about 3 MUSD. By using six-

tenths-factor rule the price of lean MEG Tank will be:

Cost lean MEG tank = Cost of rich MEG tank * (Vlean meg tank /Vreach meg tank )0.6

Cost lean MEG tank = 3 MUSD * (1600/3040)0.6 = 2 MUSD

The climate conditions in Sakhalin waters are very similar to Alaskan waters. By using Table

3.2 it is possible to estimate that 21 km MEG pipeline costs:

MEG pipeline = 21.108*377000$ = 8 MUSD

/h][mCond.Rate*102.4+/hr][ksmGasRate*104.21=/h][mRateMEG 3-33-33




Each P5602-A pump costs approximately 0.1 MUSD and MEG regeneration unit may cost

0.45 MUSD (Vergara, 2007). The necessary value of MEG to fill rich MEG storage, lean

MEG storage and pipeline may be calculated:

VMEG pipeline = 3.14D2/4*L = 3.14*0.10162*21,108/4 = 171,04 m3

VRich MEG Tank = 2755/2 = 1377.5 m3 (due to 50% MEG in rich tank)

VLean MEG Tank = 1500 m3

VTotal = VMEG pipeline + VRich MEG Tank + VLean MEG Tank = 171,04 + 1500 + 1377.5 = 3048.54 m3

The density of lean MEG is 1034 kg/m3, so m=3048,54*1034=3152.19 tons. One kg of MEG

costs 3$ (for offshore conditions). Price of initial MEG = 3152.19*3000=9.46 MUSD

Operational costs per year may be presented as MEG losses during MEG regeneration and

labor cost. Heat gases from gas turbines can be used for MEG heating, so there is no need tospend any additional money on this. There is 172.8 kg of MEG lose per day during gas

production with gas flow rate 247 MMSCFD (Vergara, 2007). Gas flow rate in Sakhalin-2

multiphase pipelines is 1800 MMSCFD. Therefore the losing of MEG may achieve 1200 kg

per day. To replace it is necessary to buy new MEG and spend 1200*360*3 = 1.3 MUSD per

year.

For labor cost estimations the following formula may be used:

NOL = (6.29+0.23Nnp)0.5

Where NOL is the number of operators per shift and Nnp is the number of non-particulate

processing steps and includes compression, heating, cooling, and mixing. Four and one-half

operators are hired for each operator needed in the plant any time (Turton, 2008). For MEG

system there are two tanks in the process and three MEG regeneration units so Nnp=5.

NOL = (6.29+0.23 * 5)0.5 = 2.72 operator per shift

Operating labour = 2.72 * 4.5 = 12.24 (rounding to the nearest integer gives 13)

Labor costs = 13 * 100000$/year=1.3 MUSD/Year

The total capital investment (for 30 years of MEG system operation) equals operational cost

per 30 years plus fixed capital investments in equipment and MEG. This sum achieves value

of 102.01 MUSD. The calculations are summarized in the Table 3.3.




3.5 Wax Issue on Sakhalin-2 Project

The relatively large wax deposits are formed during the transport of two-phase fluid

(hydrocarbon vapor and a liquid condensate), MEG and water from the platform to OPF. The

deposits amount scraped by pigs can reach 300-400 kg.

Pigging is commonly used for the cleaning of the pipelines. During pipelines cleaning

operations, the liquid/vapor ratio within the pipeline will change. This may cause slug

formation in the pipeline and slugs can be transferred to the OPF (Sakhalin Energy, 2008).

At OPF liquid slugs enter a gas liquid receiver. The liquid level within this vessel will rapidly

increase. OPF has limited slug receiving capacity, thus a parking loop is applied. The parking

loop is a facility to store excess liquid at high pressure and to enable it to be gradually

processed. The parking loop is a buried pipe and it is designed to accommodate the expected

slug volume (Figure 3.6).

The expected frequency of the liquid slugs received by the OPF is based on the estimated

requirements of pigging for each incoming pipeline from Lun-A every fortnight. To simplify

these operations, the parking loop is designed in the form of a hairpin loop with pig traps at

each end. Both pig traps are located within the OPF area, although the major part of the

parking loop is buried along the pipelines corridor outside the OPF (Sakhalin Energy, 2008).

Lun-A has two vertically mounted pig launchers for two multiphase pipelines to enableregular cleaning and inspection of these pipelines using intelligent pigs. The design of the pig

launchers is such that the pigs are preloaded into a launch cassette, which in turn is loaded

into the barrel of the pig launcher the design allows pigs to be launched into the pipeline

without interrupting the export rate.

The pigging frequency during the early production phase is infrequent and the requirement to

pig is advised by the Pipeline Operations team. When the pig launcher is in operation, gas

flows through the pig launcher camera and drives the pig to the OPF. It is received in pig

receivers. During the early production phase only single pigs are loaded into the Lun-A pig

launchers (Sakhalin Energy, 2008).




4 Flow Assurance in Heavy Oil Production in Venezuela

4.1 Heavy Oil Overview in Venezuela

Nowadays, heavy oil has gained importance due to the steady decrease of conventional oil

reserves. In addition, the prices of oil have rocketed throughout the last decade. Venezuelaand Canada have the largest reserves of heavy oil and bitumen of the world. In Venezuela,

are mainly located in Orinoco Heavy Oil Belt (Faja Petrolífera del Orinoco or the Faja), which

has an area of about 55000 km2 (600 km from east to west, and 70 km from north to south)

(Aular & Amariscua, 2008).

It is estimated that the oil in place of the Faja at about 1.2 billion of barrels (1.2*1012 barrels)

and PDVSA (the state Venezuelan oil company) concluded that about 22% of this oil is

recoverable (Cleveland, 2007). Furthermore, the oil in the Faja contains significant quantities

of natural gas dissolved, with a range from 53 to 262 trillion cubic feet of gas (Schenk et al.,

2007), so it might be a very important source of natural gas if the oil production is guaranteed.

The huge quantity of oil deposited in the Faja seems very attractive but its production and

transport results difficult due to its characteristics. As it is well known, heavy oil is considered

all liquid petroleum which has API gravity between 10 and 21.9, and extra-heavy oil has less

than 10ºAPI (Berberii, 1998). In the Faja, the oil has API gravity from 4 to 16 (Schenk et al.,

2007). This kind of oils have very large viscosities, from 1000 cP to 95000 cP (Berberii,

1998), although in the Faja are relatively low, on the order of 2000 to 8000 cP (Schenk et al.,

2007). However, this range of viscosity is very high comparing to conventional oil, so it

results difficult to produce and transport it.

Another important issue is the content of sulfur, between 1% and 8%, and heavy metals

(Nickel, vanadium and others) in heavy oil, in the range from 100 to 500 ppm (Berberii,

1998). Therefore, it is much more expensive to refine heavy oil than conventional oil. On

table 4.1, it is shown a comparison among conventional and heavy oils.

The oil deposited in the Orinoco Heavy Oil Belt, was actually discovered several years ago (in

the middle of 1930s specifically) but there were enormous reserves of conventional oil in

other places, so oil companies did not take into account this oil until the 1970s. According to

the first studies of the Faja, the oil recovery factor was only from 3% to 10% and it was

considered unprofitable the oil exploitation there. In addition, the technology at those days




was not developed enough to transport very viscous flow from remote reservoirs to the

processing and commercialization areas along the shore.

The energetic crisis in the 1970s and the significant increase of conventional oil exploitation

in nearby areas attracted the interest of a possible exploitation of the Faja’s oil. Furthermore,

after of the nationalization of Venezuelan oil in 1976, it was created an oil research institute

called INTEVEP which has the main purpose to develop feasible strategies of production,

transport and processing of heavy oil. Many years of research and the investment of foreign

oil companies in association with PDVSA since 1996, it has been possible the exploitation of

heavy oil in Venezuela at large scale.

4.2 Production of Heavy Oil in Venezuela

The heavy oil in the Faja has enough low viscosity and enough dissolved gas that it can becollected by cold production technologies, which result economically viable to implement.

However, the recovery factor is very low, typically 5% to 10% (Clark, 2007). For this reason,

it has been though to implement other technologies such as SAGD (Steam-assisted gravity

drainage) which has had excellent results in Canada. Alternatively, it has been used the

method of Cyclic Steam Stimulation which was discovered by accident in Mene Grande tar

Sands, Venezuela, 1959 (Terry, 2001). The president of INTEVEP reported that it is being

produced 120000 BPD of heavy oil in the Faja by using this method (Ford, 2010).

The heavy oil deposited in the Faja has enough low viscosity for recovering it by using cold

production methods. In addition, heavy oil is often located in shallow reservoirs with a range

in depth from 150 to 1400 m (Schenk et al., 2007). It allows use horizontals wells, which

increase the oil production and it has been developed networks of horizontal wells with

multiple lateral branches for improving the recovery efficiency.

Initially the operators at the Zuata field drilled two horizontal wells into a series of “drainage

rectangles” of 1,600 m by 600 m size. The results from the first 95 wells did not meet

expectations, so the operator embarked on an extensive data acquisition program. The next

wells were drilled with multiple laterals in various patterns. It is shown in Figure 4.1 of six

different multilateral patterns used in the Faja region. The use of multilaterals and improved

placement of well completions (resulting from the data collected) allowed the operator to

achieve its target production of 120000 BPD by 2001 (Veil & Quinn, 2008). The Figure 4.1

provides a simplified illustration of a horizontal well network used in Venezuela.




At another Venezuela location, the Sincor project, the operator (Total) has used horizontal

wells and progressing cavity pumps (PCPs) to produce heavy oil. It is reported that Total had

reached a production level of 200000 BPD of heavy oil with 8° to 8.5° API gravity by 2004

(Veil & Quinn, 2008).

It is also required an especial pumping system, because the heavy oil is often accompanied by

sand, water and natural gas. In addition, the heavy oil requires extra work to be pumped. The

most common pumps used in these operations are: progressing cavity pumps and electric

submersible pumps (ESPs). A diluent such as naphtha or light oil may be injected near the

pump to reduce the viscosity of the heavy oil and allow it to be more easily pumped.

Alternatively, diluent may be added at the surface to facilitate pipeline transport (Clark,

2007).

The other method above-mentioned was the cyclic steam stimulation (CCS), which consists

firstly in injecting from 5000 to 15000 bbl of high quality steam (Terry, 2001). It could take a

period of days and even weeks. Then the well is shut in, allowing the steam to soak the area

around the injection well. It usually takes from 1 to 5 days. Afterwards, the injection well is

then placed on production. The length of the production period is dictated by the oil

production rate but can last from several months to a year or more. The cycle is repeated as

many times as is economically feasible (Terry, 2001). This process is illustrated in Figure 4.2.

These processes required special equipment for monitoring and controlling the oil production.In the particular case of Venezuela, especially in the Faja, these electronic devices are

vulnerable to the intense lightning activity in the area. Therefore, Wells, and their associated

electronic equipment are protected by surge protectors and, increasingly, by power backup

capabilities and software modifications which prevent the well from being shut down due to

brief power outages or brownouts (Foster, 2006).

4.3 Transport of Heavy Oil in Venezuela

After of production stage, it is vital to find a feasible form to transport heavy oil. Then, it is

necessary to process it for being commercialized. At the beginning of the 1960s, Phillips

Petroleum Co., Amoco, and Creole Petroleum Co (Exxon Subsidiary) developed a

commercial operation for the production of the Morichal (8.5° API), Jobo (8-9° API), Pilon

(13° API) and Temblador (19° API) oil fields based at the Morichal Camp (Rodriguez, 2004).

Then, Jobo and Morichal were blended with gasoil at the head well to reduce their viscosity,




so they could be transported easily by pipeline and reach the specifications of the commercial

blend Morichal (12.5), which was used to produce asphalt.

Pilon and Temblador were also blended to make the Pilon Segregation with 13.5° API for

general refining feedstock (Rodriguez, 2004). Nowadays, it is still commercialized heavy oil

as a blend but it is called Merey 16, which is produced blending heavy and extra-heavy oil

with lighter crude oils obtained from the adjacent areas. However, during the 1980s it was

carried out other strategies to exploit the heavy oil contained in the Faja. It was thought, that

blending heavy oil with other lighter could be very limiting, the heavy oil commercialization

only relied on the supply of medium or light crude oil.

Among the alternatives found, the most promising was: emulsifying the oil in water and

producing syncrude. The former resulted very challenging, because the knowledge regarding

to behavior of this kind emulsion was very scarce. The latter resulted very expensive, because

the initial investment of building a syncrude refinery was very high. The decision was taken

at the beginning of 1980s and it consisted in transporting heavy oil as an emulsion, which

water was the continuous phase, and to build an especial refinery where the heavy oil would

be converted into syncrude.

Regarding to the emulsion, the research was carried out by INTEVEP and FIRP (University of

the Andes’ Laboratory, located in Merida-Venezuela). Unfortunately, the oil prices

plummeted in the middle of the 80s and the project of producing syncrude was abandoned,although the research concerning to the emulsion was at a final stage. In addition, the

utilization of this emulsion was promising because the viscosity was reduced more than two

orders of magnitude (Langevin et al., 2004). Surprisingly, it originated the idea of burning the

new emulsion as a traditional fuel for generating electricity and this emulsion was called

Orimulsion (Ramirez, 2003).

Orimulsion is an emulsion of approximately 70% natural Cerro Negro bitumen 8.5° API

suspended in 30% fresh water by means of mechanical energy and the addition of less than1% alcohol-based surfactants (emulsifiers) that allow the bitumen droplets to remain

suspended in a stable mode (Rodriguez, 2005). Once the bitumen is produced and treated, it is

sent to the Orimulsion manufacturing plant, where is emulsified with water and the surfactant

under carefully controlled conditions, using special mixers specifically designed for the

product.




Although the bitumen is almost solid at room temperature, the action of the surfactant and the

shear forces provided by the mixer at the formation temperature, results in the bitumen being

finely divided in almost perfect spheres dispersed in water (Gomez-Bueno et al., 1998). Then,

it is transported by pipeline to the shipping port, about 320 km away from the manufacturing

plant (Gomez-Bueno et al., 1998).

Power plants which are run by coal and heavy fuel oil, could be run by Orimulsion with small

modifications. In addition, Orimulsion has environmental advantages compared to the other

two fuels. For example, the Orimulsion produces 20% less NOx than heavy fuel oil and 20-

30% less CO2 than medium BTU coal (Gomez-Bueno et al., 1998).

Despite Orimulsion advantages and its low cost, it was difficult to commercialize due to the

opposition of environmental groups and coal suppliers. The most emblematic example is the

Florida case, where the company Florida Power & Light could not implement Orimulsion as a

new fuel to generate electricity. Due to very strong propaganda made by environmental

groups such as Sierra Club and FCAN (Ramirez, 2004) in conjunction with the coal suppliers.

However, this new fuel was commercialized in other markets such as Japan, Italy, Denmark,

Canada and China.

Surprisingly, the most prominent enemy of Orimulsion has been the current government of

Venezuela. It decided to discontinue the new fuel production in 2006; arguing that it was not

profitable to Venezuelan State (Chirinos, 2006). Nevertheless, others argue that the realreason has political characteristics because Orimulsion had been the pride of former PDVSA

engineers, who were dismissed as punishment for participating in the strike that hit the state

oil company from december-2002 and February-2003. As a result, Orimulsion fell out the

favor of key political leaders and they winded down the Orimulsion program.

Other strategies of heavy oil transport have been studied, but they still are in research stage.

For example, it has been studiy of core-annular flow of heavy oil which water migrates into

regions of high shear at the wall of the pipes, where it lubricates the flow (Joseph, 1997).Arney et al. recommended use cemented pipelines instead of steel or galvanized pipes for

preventing fouling.




5 Sour Gas in Natuna Gas Field, Indonesia

5.1 Natuna Gas Field Overview

The Natuna D Alpha gas field is located in the Natuna Sea or South China Sea in Indonesian

waters, approximately 140 miles northeast of Natuna Island. The Island is 373 miles northeastof Singapore and 683 miles north of Jakarta (Fenter & Hadiatno, 1996). The Natuna gas field,

discovered in 1973, has estimated total gas resources of 222 trillion cubic feet (TCF) of which

CO2 comprise some 71% of the total gas (Suhartanto & Green, 2002). Recoverable

hydrocarbon (75% gas recovery), which is almost all methane, is estimated at 46 TCF or 1270

billion cubic meters. This number is equal in size to Troll, the largest gas field in Norway.

This is enough gas to supply Japan for 17 years based on current annual Japanese gas demand

(PRNewswire, 1994). Figure 5.1 shows the location of Natuna field.

Currently, Natuna D Alpha gas field development is still on debate due to political issue.

Exxon Mobil had planned to develop this field before finally the Government of Indonesia

appointed the state-owned Pertamina to develop the Natuna D Alpha. However, Pertamina

still lacks capability to develop the project in the deep waters, which needs approximately 40

billion U.S. dollars. Thus, it has been decided to split development of Natuna D Alpha

between state-owned Pertamina and Contractor. Based on the latest news, the percentage of

this split has not been decided yet and is still evaluated (tender-indonesia, 2010).

5.2 CO 2 Removal Technologies for Natuna Gas Field

Treating 157 TCF of CO2 from Natuna gas field requires appropriate technologies in order to

operate safe and reliable gas plant. As mentioned previously, Exxon Mobil had planned to

develop Natuna D Alpha gas field, so that some researches had been done and technologies of

CO2 removal had been evaluated. These evaluated technologies are discussed further in this

chapter.

Gas from the Natuna field is planned to be liquefied in a new LNG plant which will be builton Natuna Island, then transported by specially refrigerated ships to markets. Since Natuna

Island is about 225 km (140 miles) away from the Natuna gas field, the produced gas will be

treated offshore to remove most of the CO2. The remaining CO2 will be removed onshore. It

would be very risky to deliver the gas composed by 71% of CO2 directly to onshore and

otherwise, it would be very expensive to build all gas processing plant offshore.




Natuna offshore processing facilities will include inlet cooling and separation of produced

gas, CO2 removal, and compression of treated and excess gas streams. Raw gas is predicted

entering the plant at 91 oC (196 oF) at 1265 psi pressure. A two-step process will condense

and separate most CO2 and hydrogen sulfide (H2S) from the methane, and then producing a

treated gas stream of about 80% methane, 18% CO2, 1% nitrogen, and small amounts of H2S.This stream will then be warmed with inlet gas via a heat exchanger and compressed for

pipeline transport to Natuna Island. Condensed excess gas provides cooling for the CO2

removal process, and is then compressed for pipeline transport and injection into aquifers.

The CO2 removal process is based on extensive industry experience in low temperature gas

separation.

5.3 CO 2 Disposal in Natuna Gas Field

Global warming is important issue regarding CO2 disposal in Natuna. Thus, it requires

appropriate technologies to dispose such large amount of CO2. The removed CO2 is planned

to be transported via pipeline to the injection platforms. There it will be injected underground

into carbonate formations for permanent disposal. Such underground storage is proven

technology. Since 1946, nearly 100 storage projects have been completed in the U.S., Canada,

Germany, France, Italy, Saudi Arabia, and other countries (PRNewswire, 1994).

The CO2 will be injected into the aquifer in the form of a supercritical fluid (with the density

of a liquid and the transport properties of a gas) at high pressure. The aquifers are adjacent, but separate from, the Natuna gas reservoir. They are part of the same Terumbu formation that

makes up the gas reservoir.

Data from 14 wells and extensive studies indicate that the structure has porosity and other

characteristics even better than those of the producing reservoir (PRNewswire, 1994). Also,

the combined pore volume of the two aquifers, greater than 40 times the volume of the Natuna

gas reservoir, is over 100 times the volume of the excess gas which could be injected over a

30 year period. Most of the gas will remain trapped within the rock pore space through a phenomenon known in the industry as residual gas saturation. The small volume of gas which

is not trapped in the pore spaces will be contained below the impermeable rock sealing the top

of the aquifer.




6 Discussion

The prevention of hydrates formation in multiphase pipelines is expensive operation. The

development of new oil and gas fields may be uneconomical with existing hydrate prevention

systems. It is necessary to create new technologies to economically develop small oil and gasfields. One of them may become cold flow. Cold flow technology may reduce the cost of

deepwater production facilities, provide cost effective and trouble free flow of oil and gas and

become environmentally friendly solution of hydrate problem (Gudmundsson, 2002).

As for wax deposition in gas/condensate pipelines it is important to develop more accurate

wax deposition models. It may be difficult due multiphase nature of gas/condensate flow.

Temperature profile influences very much on the wax deposition and there are a lot of

uncertainties in the prediction of temperature profile for multiphase flow pipelines. However,

nowadays Norway is the world leader in multiphase pipelines system. It has the world’s

largest multiphase pipeline with length 143 km in Snøvit (Sandvik, 2010).

Furthermore, the issue of new technologies to prevent deposition of paraffin wax in gas

associated wells tubing has been considered for years. One of the cost-effective approaches is

using microbes. A thermophilic microaerophillic paraffin degrading consortium was

developed along with compatible biocatalysts, which are capable of reducing the pour point of

the paraffinic crude oil (ONGC TERI Biotech Ltd, 2010). Another emerging technology not

been deployed commercially is ultrasonic technology developed to chemically reduce the

length of the paraffinic molecules so they will not precipitate (Mokhatab & Towler, 2009).

For heavy oil production and transport in Venezuela it is also necessary to apply new

technologies to take advantage of the enormous potential of the Orinoco Oil Belt. Concerning

to production, most of the developments have been aimed to improve cold methods. For

example, the implementation of networks of horizontal wells and modern pumping systems

have been possible the exploitation of heavy and extra-heavy oil in Venezuela at high scale.

But it is still at low level so it could be necessary to use the other alternatives to ensure heavyoil production and transport at long term.

Another difficulty in natural gas production is sour gas. There are two main issues in natural

gas production with high CO2 content: to economically separate CO2 and to storage it. For the

last decades the importance of CO2 utilization sharply increased, especially in developed




countries. This is due to global warming worries. So, the utilization of CO2 will be significant

challenge for oil and gas industry.




7 Conclusions

The traditional flow assurance problem in offshore Russian projects are hydrates and wax

appearance. To prevent hydrates formation in multiphase flowlines of Sakhalin-2 project

monoethelyne glycol injection system is used. It consists of tanks for rich and lean MEG, pipeline, pumps for MEG pumping, MEG regeneration units. The initial investment and

operational costs may achieve value of 102.01 MUSD for this project.

For wax and paraffin deposition, the regular cleaning of pipelines allows to avoid these

problems. But for multiphase pipelines the technology is more complicated compare to gas or

oil pipelines. There is a possibility of slug appearance in a pipe. Thus such pipelines require

some additional pieces of equipment like slug catcher or parking loop as for Sakhalin-2

Project. Also, a combination of electrical heating and thermal insulation was deployed on the

production platform on Sakhalin to prevent wax deposition.

The heavy and extra-heavy oil production in Venezuela has increased significantly throughout

the last two decades. However, there are still some problems, especially in oil transport. The

blending of heavy and extra-heavy oil with conventional oil is a solution only for short term

time period.

In case of Indonesia, Natuna gas filed with 71% of CO2 is considered. Despite such a huge

CO2 content it is still economically to develop this field. The produced gas will be treated offshore to remove most of the CO2 and the remaining part will be removed onshore. Natuna

gas is planned to be liquefied and produced CO2 is planned to be injected into carbonate

formations.




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9 Tables

Table 2.1 - Technologies Commonly Used for CO2 Removal (Forde, 2010)

Table 3. 1 – Multiphase Pipelines Characteristic (Sakhalin Energy, 2010)

Total Length Offshore length Onshore length Internal diameter Maximum flow 21108 m 14045 m 7063 m 762mm 900 MMSCFD

Table 3.2 – Main Parts of MEG System (Scandpower, 2004)

Pipe diameter Pipe length Avg. cost ($/mile)4’’-12’’ 150 377,000

16’’-24’’ 10 461,000




Table 3.3 – Investment in Equipment and Initial MEG

Component Amount Total Cost, mln. $Fixed capital investment

Rich MEG Storage Tank T-5601 (2755 m3)

1 3

Lean MEG Tank T-5602(1458 m3) 1 2Pipeline (4’’@21108 m) 1 8Pump P5602-A 2 0.2MEG Regeneration Unit(15.6 m3/h)

3 1.35

Initial MEG 3048.54 m3 9.46Total Fixed capital investment 24.01

Operating cost per yearMEG replacement 421.2 m3 1.3Labor cost 13 1.3Total Operating cost per year 2.6Total Capital investments per 30 years 102.01

Table 4.1 - Comparison among Venezuelan Crude Conventional Oils and Heavy Oils (CrudeOil Specifications, 2010)

Venezuelan crude oil nameCharacteristic Units Mesa Furrial Merey 16 Morichal

Gravity ºAPI 30.5 28.5 16 12.2Sulphur %wt 0.85 1.1 2.45 2.78

Kinematicviscosity at 100ºF

cSt 7.29 11.9 513 145

Vanadium ppm 38 68 262 274 Neutralization

number mg KOH/g 0.03 0.1 0.69 2.83

Morichal is a commercial blend used to obtain very good asphalt. Merey 16 is a blend of extra-heavy oil and light oil which is commercialized in the international market.




10 Figures

Figure 2.1 – Structure of Polyhedron Forming Gas Hydrate (Gudmundsson, 2010)

Figure 2.2 – Hydrate Phase Diagram (Sandengen, 2010)




Figure 2.3 - Hydrocarbon Phase Envelope (Schulumberger, 2010)

Figure 2.4 - Wax Precipitation Curve (Infochem, 2010)




Figure 2.5 - Pressure Pulse Measurement (Gudmundsson et al., 1999)

Figure 2.6 – Mechanical Scraper or a “Pig” (Sakhalin Energy, 2008)




Figure 2.7 – Electric Heating Tracer (Economy Engineering Corporation, 2010)

Figure 2.8 – Steam Heat Tracer (Kentech News, 2009)




A – PA-B and PA-A platforms, B – OPF and Lun-A, C – LNG plant and oil export terminal.

Figure 3.1 – Sakhalin-2 Project Overview (Gunningham et al., 2008)

Figure 3.2 – Multiphase Pipeline (Sakhalin Energy, 2010)

A

B

C

Gas

Aqueous phase

Con ensate




Rich MEG Storage Tank T-5601 (2755 m3) Lean MEG Tank T-5602 (1458m3)

Figure 3.3 – MEG Storage Tanks (Sakhalin Energy, 2008)

Figure 3.4 – MEG Storage and Pumping to Lun-A (Sakhalin Energy, 2008)

Figure 3.5 – MEG Distribution on Lun-A Platform (Sakhalin Energy, 2008)

Ǿ16m

8m

Ǿ22m

8m




Figure 3.6 – The Parking Loop (Sakhalin Energy, 2008)

Figure 4.1 - Network of Horizontal Wells (Clark, 2007)




Figure 4.2 - Sketch of Cycle Steam Stimulation (Aular & Amariscua, 2008). Firstly, thesteam is injected. Then the steam and the condensed water heat the viscous oil. Finally, the

water and oil and pumped together .

Figure 5.1 - Location Map for the Natuna Field (Fenter & Hadiatno, 1996)

1st. Stage : Steam Injection 2nd. Stage : Soak Phase 3rd. Stage : Production




11 Appendix

11.1 Appendix A – History and Projections for Energy Consumption

The graph shows that the consumption of natural gas will significantly increase in future.

Flow assurance issues will be still very important to satisfy world demands in natural gas.

Figure A1 – Forecast of the World Energy Consumption (EIA International Energy Outlook,2010)




11.2 Appendix B – Platform Luna-A and OPF

On these photos you can see platform Lun-A in the Sea of Okhotsk and Onshore Processing

Facilities (OPF).

Figure B1 – Platform Lun-A (Sakhalin Energy, 2010)

Figure B2 – Onshore Processing Facilities (Sakhalin Energy, 2010)




11.3 Appendix C – Multiphase Pipelines Profile and MEG Injection Graph

There are two parallel multiphase pipelines between Lun-A and OPF. Their profile is shown

in the Figure C1.

-50

-30

-10

10

30

50

70

0 5 10 15 20 25

Length (km)

E l e v a

t i o n

( m )

Offshore Onshore

LUN-A

OPF

Figure C1 – Pipeline’s Profile (Sakhalin Energy, 2008)

0

1

2

3

4

5

6

7

0 100 200 300 400 500 600 700 800 900

Pipeline flow rate (MMscfd)

P L M E G i n j r a

t e ( m 3 / h r )

Lower Limi t Higher L imit

Note: upper limit needs to be confirmedUpper limit =25% above target value and smaller than 6 m3/hr

Under inhibiti on of pipeline fluids.

Too much liquids in the pipeline.Risk to flood t he inlet facilitiesduring ramp-up.

Figure C2 – MEG Injection Flow Rate (Sakhalin Energy, 2008)




11.4 Appendix D - Overview of the Orinoco Heavy Oil Belt (The Faja)

Figure D1 - Location of Orinoco Heavy Oil Belt, the Faja (Hewitt, 2007)

Figure D2 - Different Blocks of the Faja (Petropars Ltd., 2010)




11.5 Appendix E - Pumping Systems Applied in Venezuela

Figure E1 - Progressing Cavity Pump (Aular & Amariscua, 2008)

Figure E2 - Electrical Submersible Pumping System (NOVOMET, n.d.)




11.6 Appendix F - Orimulsion

Figure F1 - Viscosity of Oil/Water Emulsions at Different Shear Rates. Source: (Langevin etal., 2004)

Figure F2 - Bitumen Droplets in Orimulsion (Gomez-Bueno, 2004)



Figure F3 - Orimulsion Production Facilities and Infrastructure (Rodriguez, 2005 and http://www.soberania.org)

flow assurance and sour gas

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