TEC GYC.pdf

7/27/2019 TEC GYC.pdf

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GAS CONDENSATE RECOVERY TECHNOLOGIES

IN ENI TUNISIA FIELDS

H. Abdelli, F. Colonna, Eni Tunisia B.V.

This paper was presented at the 10th Offshore Mediterranean conference and exhibition in Ravenna, Italy, March 23-25, 2011. Itwas selected for presentation by OMC 2011 Programme Committee following review of information contained in the abstract

submitted by the author(s). The paper as presented at OMC 2011 has not been reviewed by the Programme Committed.

ABSTRACT

The price of gas condensate is higher than gas, so its recovery can bring an economic gain.This article presents the different technologies used or being evaluated in Eni Tunisia fields,in order to increase gas condensate recovery. Three different kinds of technologies areimplemented or under evaluation in Eni Tunisia plants:

Gas refrigeration (where the gas is refrigerated through an expansion valve). External mechanical refrigeration cycle (that maintain the pressure of treated gas). Vapor recovery unit (from crude oil stock tanks).

The article describes the gas condensate recovery units in Eni Tunisia fields. It shows theeffects of the operating parameters on the gas condensate recovery processes. In the paperare illustrated the results of Eni Tunisia plants simulations, using Hysys and ProII tools,compared with the real data. There is also the procedure needed to evaluate the capitalexpenditure, the operating expense and the breakeven point. All these data are relevant inorder to estimate if the gas condensate recovery unit will be profitable. In order to evaluatethe gas condensate gain, one takes into account the proportions of stock tank condensateliquid and accompanying produced gas reported as GOR (gas oil ratio), in standard cubicmeter per barrel. Another term often used is standard cubic meter of gas per cubic meter ofcondensate liquid. An increase of gas condensate rate means a decrease of GOR.

INTRODUCTION

Raw natural gas produced from underground gas fields or extracted at the surface from thefluids produced from oil wells cant be delivered directly to residential, commercial andindustrial consumers. It consists mainly of methane (CH4), but it also contains varyingamounts of heavier gaseous hydrocarbons, acid gases (CO2 and H2S), nitrogen, water, liquidhydrocarbons and mercury. Contaminants have been removed and often heavierhydrocarbons have been captured for other commercial uses. Most natural gas is processedto remove the heavier hydrocarbon liquids from the natural gas stream. Recovery of naturalgas liquid components in gas not only may be required for hydrocarbon dew point control in anatural gas stream, but also produces a source of revenue, as gas condensate normally hassignificantly greater value as separate marketable product, as part of the natural gas stream.

There are a great many ways in which to configure the various unit processes used in theprocessing of raw natural gas. The objective of this article is how processing the raw naturalgas produced in Eni Tunisia fields in order to produce natural gas liquids. Part of water andgasoline vapours condenses in the liquid phase by the effect of decreasing temperature andpressure (retrograde condensation) of the gas stream flowing from the field to the gatheringstation. In this case, the separation processes of gasoline and free water occur all together inseparators. However, the gas which leaves the separator is still saturated with water andgasoline. To recover gasoline vapours and steam, degassing treatment is carried out. Theoperation often consists in cooling the gas in a refrigerating plant and to expand it, for theJoule Thomson effect. This is the process implemented in Djebel Grouz plant in Tunisia. InOued Zar plant, external mechanical refrigeration using propane chiller will be installed. InTazerka where is located the CPF, the process includes the LPG stripper and the

debutanizer. The article describes the gas condensate recovery units in our fields and showsthe effects of the operating parameters on the processes. Their simulation has been carriedout using Hysys and ProII tools and the results of this, have been compared with the realdata.


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I GAS CONDENSATE RECOVERY PROCESSES

I.1 Gas Condensate Recovery Characteristics

In order to understand the gas condensate recovery processes we must take inconsideration the behavior of the natural gas as a function of pressure and temperature. Letus consider the phase diagram of a reservoir fluid (Fig. 1). The retrograde condensation zoneis an area where the gas expansion produces liquid phase under isothermal conditions. It is

the grey area to the right of the critical point C. Outside this area, the lowering of thepressure causes progressive vaporization of the liquid fraction. Obviously any cooling outsidethe retrograde condensation zone will induce condensation and produce gas condensate.Retrograde condensation phenomenon has an important application in the gas condensaterecovery processes.

Fig. 1: Phase diagram of a reservoir fluid

I.2 Mechanical Refrigeration

Fig. 2: Vapor compression refrigeration cycle

External mechanical refrigeration is the simplest and most direct process for gas condensaterecovery. The process is supplied by a vapour compression refrigeration cycle (Fig. 2) thatusually uses propane as the refrigerant and reciprocating, centrifugal or screw types ofcompressors to move the refrigerants from low to high pressure operating conditions. A gas-to-gas heat exchanger recovers additional refrigeration by passing the gas, leaving the coldseparator countercurrent to the warm inlet gas. The temperature of the cold gas streamleaving this exchanger approaches that of the warm inlet gas. The chiller is mainly a shelland tube, kettle type unit. The process gas flows inside the tubes and gives up its energy tothe liquid refrigerant surrounding the tubes. The refrigerant boils off and leaves the chillervapor space essentially as a saturated vapor. When water is present in the gas processed byrefrigeration, hydrate formation is prevented either by dehydration of the gas or by injectionof a hydrate inhibitor. If the processing temperature is relatively low, the gas is usuallydehydrated before the refrigeration step. If not, injection of an inhibitor (usually methanol orglycols) upstream of the gas-to-gas heat exchanger is often the simplest and most


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economical solution. The inhibitor is injected at the inlet of the gas-to-gas exchanger and/orchiller to prevent hydrate formation, or freeze up, the last one being more common. Freezeup will partially block exchanger tubes, thus increasing pressure drop and decreasing heatexchange. The weak solution, containing absorbed water, is separated in the cold separator,reconcentrated, and recycled (Fig. 3).

Fig. 3: External mechanical refrigeration process

A mechanical refrigeration process is adopted when sizeable amounts of condensate areexpected. This process may also lead to the recovery of LPG. As for recovery up to 90 %, asimple propane refrigeration system provides refrigeration at temperatures to -40 C. Thereare many straight refrigeration process schemes, which vary according to all the designvariables, such as gas composition, process pressure, and LPG recovery objectives.Any material could be used as a refrigerant. The ideal refrigerant is no toxic, no corrosive,

has Pressure-Volume-Temperature (PVT) and physical properties compatible with thesystem needs, and has a high latent heat of vaporization. The practical choice reduces toone, which has required physical properties and will vaporize and condense at reasonablepressures at the temperature levels required. In general, the lower practical limit of anyrefrigerant is its atmospheric pressure boiling point. It would be better to carry some positivepressure on the chiller to obtain better efficiency in the compressor, reduce equipment size,and avoid air induction into the system. Propane is by far the most popular refrigerant in gasprocessing applications. It is readily available (often manufactured on-site), inexpensive, andhas a good vapor pressure curve. It is flammable but this is not a significant problem if properconsideration is given to the design and operation of the facility.This configuration is typical of LPG unit of CPF, our treatment plant. Scope of our studyconsist in optimize the operatives conditions in order to increase the gas condensate

recovery.

I.3 Self-Refrigeration

As opposed to external mechanical refrigeration, in the self-refrigeration process, the inletgas is precooled against the treated gas (through the gas-to-gas exchanger) andsubsequently cooled further by isoenthalpic expansion (Joule Thomson expansion) through avalve, resulting in heavy hydrocarbons and water to condense. The main concept is to chillthe gas by adiabatically expanding it across the Joule Thomson valve. With appropriate heatexchange and large pressure differential across the Joule Thomson valve, cryogenictemperatures can be achieved resulting in high extraction efficiencies. In this process, the noideal behavior of the inlet gas causes the gas temperature to fall with the pressure reduction.

The temperature change depends first on the pressure drop. The use of the Joule Thomsoneffect to recover liquids is an attractive alternative in many applications. The advantages ofthe Joule Thomson unit are:


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Low gas rates and modest ethane recovery. The process can be designed without rotating equipment. Broad range of flows. Simplicity of design and operation.

The condensed liquids are then removed in one or more separators to meet the vaporpressure and composition specifications. The gas from the low temperature separator, once

satisfying the sales gas specification, is reheated against the incoming feed. Generally,treated gas must be recompressed to sales pipeline pressure if it has been expanded to alower pressure. Thus, this process is most favored when the raw gas is produced at a veryhigh pressure and can be expanded to sales line pressure without recompression. If the gasmust be recompressed, the process is penalized by the recompression horsepowerrequirement. Note that the extent of cooling in this process is often limited by the hydrateformation temperature at the prevailing pressure unless a hydrate inhibitor, such as methanolor glycol, is injected upstream of the gas-to-gas heat exchanger (Fig. 4). In this case, the wetglycol and hydrocarbon condensate are heated and separated in a three phase separator.Glycol can be regenerated in a stripper. Because glycol shows some affinity forhydrocarbons, the off-gas from the glycol stripper often contains BTX (benzene, toluene andxylene). The self-refrigeration process is also attractive if the inlet gas pressure is very high.

It is important that the reservoir pressure remain high for the intended life of the plant. If thereservoir pressure is less than the sales line pressure, a possible configuration consists ofinstalling a compressor before the Joule Thompson valve. The discharge pressure must besufficiently higher than the sales line pressure in order to obtain the necessary temperaturereduction. This is the solution adopted in Djebel Grouz, an on-shore field located in the Southof Tunisia where Eni is operator. In this article we want to underline the importance of JouleThomson Expansition phenomen to avoid loss of heavy hydrocarbon into the gas.

Fig. 4: Self-refrigeration process

I.4 Vapor Recovery Unit

Underground crude oil contains many lighter hydrocarbons in solution. When the oil isbrought to the surface and processed, many of the dissolved lighter hydrocarbons areremoved through a series of separators. After being extracted from production wells andtreatment, crude oil is stored in tanks. During loading and storage, lighter hydrocarbonsdissolved in the feedstock separate from the oil and are often vented into the atmosphere orflared. The composition of these vapors varies, but the largest component is methane

followed by ethane, propane, and butane classified as vapor organic compounds (VOC).Other heavier compounds that may be present are benzene, toluene, ethylbenzene andxylene (BTEX). Losses of the remaining lighter hydrocarbons are categorized in threedifferent ways:


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Flash that occur when the last separator dumps oil into the storage tanks, which areat atmospheric pressure.

Vapors released from the changing fluid levels and agitation of tank contentsassociated with the circulation of fresh oil through the storage tanks.

Daily and seasonal temperature changes.

These emissions can create safety hazard and air pollution. One way to prevent emissions of

these light hydrocarbon vapors and generate significant economic saving is to install vaporrecovery units (VRU) on oil storage tanks. These simple units can capture about 95 % of theemissions from stock tanks. However, feasibility of these units requires close designtolerances. It is a small package composed mainly of a scrubber, a compressor, a pump anda control system. The figure below illustrates a VRU installed on a system of crude oilstorage tanks. Hydrocarbon vapors are drawn out of the tanks under low pressure andthrough the suction line go to the scrubber to collect any liquids that condense out. Theliquids are usually recycled back to the storage tanks through the pump. From the scrubber,the vapors flow through the compressor that provides the low pressure suction for the VRUsystem. Rotary vane compressors are recommended for VRU to move the low volume of gasat low pressures. The vapors are then metered and removed from the VRU. Because of thevery low pressure differential between the storage tanks and the compressor, large diameter

pipe is recommended to provide less resistance to the gas flow. The control system detectspressure variations inside the tanks and turns the compressor on and off (Fig. 5). To preventthe creation of a vacuum in the top of the tanks when oil is withdrawn and the oil level drops,the controller stops the unit and permits the backflow of vapors into the tanks. The controlunit also permits to operate the VRU remotely and is equipped of:

Pressure indicator controller (PIC). Level indicator controller (LIC). Low pressure shutdown (LPSD).

It is very important to choose reliable, sensitive control systems, because the automated gasflow valves must be opened and closed on very low pressure differences. VRU provides

significant environmental and economic benefits for oil and gas producers. The gasesflashed from crude oil and captured by VRU can be:

Sold as natural gas. Used as a fuel for onsite operations. Sent to a stripper unit to separate LPG and methane when the volume and price of

LPG are attractive.

Fig. 5: Vapor recovery unit


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By capturing methane, VRU also reduces the emissions of a potent green house gas (GHG).Vapor recovery can provide generous returns due to the relatively low cost of the technologyand in the cases where there are market outlets for the high heating value vapors. VRUshould be installed whenever they are economic, taking into consideration all of the benefitsenvironmental and economic.This kind of process is not actually used in EniTunisia fields but it is being evaluated. In thisarticle, we will present an economic study in order to evaluate the profitability of Vapor

Recovery Unit installations in Oued Zar storage tanks.

II. ENIS ECONOMIC EVALUATION

Every company invests money in different projects to get profit. The same way is followed bythe oil companies. Enis strategy to evaluate if a project is profitable is to find the bestprocess alternative that reduce the investments and increase the returns: select the processand provide for its optimization. The problem is difficult because very many processalternatives could be considered. For each alternative, project manager consider two keycost indicators: CAPEX and OPEX. Capital expenditures (CAPEX) are expenditures creatingfuture benefits. A capital expenditure is incurred when a business spends money either tobuy fixed assets or to add to the value of an existing fixed asset with a useful life that extends

beyond the taxable year. CAPEX are used by a company to acquire or upgrade physicalassets such as equipment, property or industrial buildings. An operating expenditure OPEXis an on-going cost for running a product, business or system. Its counterpart, the capitalexpenditure (CAPEX) is the cost of developing or providing non-consumable parts for theproduct or system. In our case, the purchase of a plant is the CAPEX and the cost of workersand fuel are the OPEX. CAPEX and OPEX estimations allow operation and project teams toevaluate capital and operating expenditure trade off in order to optimise the design and thecost through the entire lifecycle of the asset. The input data for this evaluation are:

Plant number and type. Production profile. Contract strategy.

Logistic strategy.

Third party transportation.

The steps to be followed to estimate the capital expenditure are:

Identify the asset (In our case, the gas condensate recovery unit, the storage andloading facilities, etc.).

Definition of its cost.

The process to evaluate the operative costs foresees the following steps:

Identify the activities associated with the asset (In this case operate and maintain the

gas condensate recovery unit, chemical injection, fuel consumption, etc.). Identify the necessary resources (Personel, spare parts, chemical, etc.). Definition of the operative costs.

The revenues and the costs must be normalized with respect to a reference time, usually theactual. The objective consists in maximizing their difference. In this way, we can find the bestprocess alternative to realize our project. Enis strategy to measure and compare theprofitability of investments, consist in taking into account these key economic indicators; NetPresent Value (NPV), Internal Rate of Return (IRR), and Payback Period. These indicatorsenable the comparison of different solutions. The economic framework includes the studyperiod (the time frame in which the cash flows are evaluated), the discount rate which takesinto account the risks related to oil price and other pertinent elements such as theenvironment in which the company would operate. Sensitivity and risk analysis are includedin the economic evaluation, to provide insight into the major risk factors in the developmentof Enis projects.


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The net present value (NPV) of a time series of cash flows is defined as the sum of thepresent values of the individual cash flows. The NPV of a sequence of cash flows takes asinput the cash flows and a discount and outputs a price. Each cash flow (inflow and outflow)is discounted back to its present value and then they are summed. Therefore NPV is the sumof all terms:

( )tt

i

R

+1

t - time of the cash flowi - discount rateRt - net cash flow (inflow minus outflow) at time tR0 - projects investment

The rate used to discount future cash flows to the present value is a key variable of thisprocess. An approach to choose the discount rate value is to decide the rate which thecapital needed for the project could return if invested in an alternative venture. It isappropriate to use higher discount rates to adjust for risk or other factors. NPV is an indicator

of how much value an investment or project adds to the firm. With a particular project, ifRt isa positive value, the project is in the status of discounted cash inflow in the time t. Instead, ifRt is a negative value, the project is in the status of discounted cash outflow in the time t.Appropriately risked projects with a positive NPV could be accepted. This does notnecessarily mean that they should be undertaken since NPV may not account for opportunitycost (the advantage forgone as the result of the acceptance of an alternative) in other words,comparison with other available investments. In financial theory, if there is a choice betweentwo mutually exclusive alternatives, the one producing the higher NPV should be selected.

NPV > 0The investmentwould add value to

the firm

The project should be economically accepted

NPV < 0The investmentwould subtractvalue from the firm

The project should be rejected

NPV = 0

The investmentwould neither gainnor lose value forthe firm

We should be indifferent in the decision whether to accept or rejectthe projectThis project adds no monetary valueDecision should be based on other criteria, for example strategicpositioning or other factors not explicitly included in the calculation

Tab. 1: NPV decision criteria

The internal rate of return (IRR) is the rate used in capital budgeting to measure andcompare the profitability of investments.The IRR is a rate quantity, so it is an indicator of theefficiency, quality or profitability of an investment. This is in contrast with the NPV, which isan indicator of the value or magnitude of an investment. An investment is consideredacceptable if its internal rate of return is greater than an established minimum acceptablerate of return. This minimum rate is the cost of capital of the investment (which may bedetermined by the risk adjusted cost of capital of alternative investments). Given the pairs,time and cash flow of a project the IRR follows from the NPV as a function of the rate ofreturn. The rate of return for which this function is zero is the IRR. Given for each time t thecash flow Rt where t is a positive integer, the IRR is given by i in:

( )0

10

=+

=

N

t

t

t

i

R

N is the the study period that is usually given in years or in months (using months if most ofthe cash flows occur at monthly intervals).


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As an investment decision tool, the IRR should not be used to rate mutually exclusiveprojects, but only to decide whether a single project is worth investing in.Payback period in capital budgeting refers to the period of time required for the return on aninvestment to repay the sum of the original investment. Payback period intuitively measureshow long something takes to pay for itself. The shorter payback period is preferred because:

The investment costs are recovered sooner and are available again for further use.

A shorter payback period is viewed as less risky. It is usually assumed that the longerpayback period is the more uncertain. For this reason, payback period is often usedas a measure of risk.

Payback period as a tool of analysis is often used because it is easy to apply and easy tounderstand. The payback period does not account for the opportunity cost. When used tocompare similar investments, it can be quite useful but it has no explicit criteria for decisionmaking. This tool for investment decisions should not be used in isolation. An implicitassumption in the use of this economic indicator is that returns to the investment continueafter the payback period.

III. CASES STUDIES

III.1 Mechanical Refrigeration (CPF Tazerka)

Maamoura and Baraka Facilities are designed to process the reservoir fluid delivered fromMaamoura and Baraka fields through the dedicated 10 and 12 pipelines to the CPF(Treatment Plant). Maamoura and Baraka on-shore treatment plant is located, approximately13 km northwards from Nabeul and located at 1.8 km from the coast.The facilities are design to receive the off-shore fluids and produce sales gas, stabilized oil,and Butapro I (A mixture of propane and butane). The streams are routed to the slugcatchers (Finger type) to separate water and liquid hydrocarbons from the gas. The fingersoperate at approximately 12 Bara and 20 C. Liquids from the two slug catchers arecombined and sent to the oil treatment section (Three phase separator and crude oilstabilizer) for further separation.

Gas from the three phase separator is combined with the crude oil stabilizer overhead gasand sent through a booster compressor before combining with gas from the slug catchers.Then the gas will be combined with gas from the LPG unit and routed to the three maincompressors. Compressed gas from the main compressors passes through the amine unit toremove carbon dioxide in the gas stream before going to the dehydration unit and then to theLPG unit. Dry gas from the top of the TEG contactor is sent through the TEG outlet coalescerto remove any glycol carryover before being cooled to -37 C through the Gas/LiquidExchanger (340-HA-001), the Gas/Gas Cooler (340-HA-002) and the Propane Chiller (340-HA-003). Condensed liquids are removed through the Cold Separator (340-VA-001). Treatedgas from the top of the Cold Separator is heated to 41 C through the Gas/Gas Cooler andthe Sweet/Sales Gas Exchanger before going to sales. Hydrocarbon liquids from the Cold

Separator bottoms are heated through the Gas/Liquid Exchanger and then fed to the LPGStripper (211-VE-001). The LPG Stripper Reboiler (211-HR-005) is heated by hot oil. Theoverhead gas from the top of the LPG Stripper is partially condensed via propane refrigerantthrough the LPG Stripper Overhead Condenser (211-HA-006) before going to the LPGOverhead Accumulator (211-VA-005). Gas from the LPG Overhead Accumulator is heatedup through the Gas/Propane Exchanger (400-HA-001) before it is recycled back to the maincompressors. Liquid from the LPG Overhead Accumulator is recycled through the LPGReflux Pumps (211-PA-001 A / B) to the top tray of the LPG Stripper. Condensed liquid fromthe LPG Stripper is routed to the Debutanizer (211-VE-002). Also the Debutanizer Reboiler(211-HR-004) is heated by hot oil. The overhead vapor is condensed by the DebutanizerOverhead Air Cooler (211-HC-001) and flows to the Debutanizer Overhead Accumulator(211-VA-004). The off-gas from the top of the accumulator is sent to the flare header. Liquid

product (Butapro I) from the accumulator a fraction is pumped to the top tray of theDebutanizer as reflux and the rest to storage. The Debutanizer bottom liquid is recycled backto the stabilizer. The propane refrigeration system supplies propane refrigerant to thePropane Chiller (340-HA-003) and to the LPG Stripper Overhead Condenser (211-HA-006).


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Propane gas from the users is routed to the Propane Receiver (400-VN-001) to remove theentrained liquids. It is then compressed to 17.3 Bara by Propane Compressors (400-KA-001A / B). The compressors are oil flooded two stage screw compressors. The dischargedpropane gas flows to the Propane Lube Oil Coalescers (400-CQ-001 A / B) to removeentrained lube oil and is condensed through the Propane Condenser (400-HC-001A / B).Condensed liquid propane is sent to the Propane Surge Drum (400-VA-001). Propane liquidfrom the surge drum is flashed and routed to the Propane Economizer (400-VN-002). Vapor

from the economizer is routed to the second stage Propane Compressors suction and liquidfrom the bottom is sent to the Propane Chiller and the LPG Stripper Overhead Condenser.

Fig. 6: CPF Tazerka - LPG unit

Fig. 7: LPG unit - Hysys simulation


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LPG unit was simulated using Hysys tool (Fig. 7). The results compared with the realoperatives conditions are showed in following table (Tab. 2).

Tab. 2: Hysys results and real data comparison

The setting of LPG unit with the actual operative conditions is not recommended because itis in commissioning phase. Project team is regulating the parameters in order to obtain

Butapro I specifications. So now it is not in steady state conditions, necessary constrain toset our model. After the handover, it will be possible to perform the setting and then optimizethe process. Actually the LPG stripper is the most critical part of the process. As we can seefrom the results, the operative conditions of the column and its equipments are different fromthe simulation outputs. Now the temperature of the top is bigger than the value provided fromour model. This means a high flow rate to LPG Overhead Condenser and then the designcapacity of only one propane compressor is not enough to cool down the stream to -37 C.Our simulation has permitted us to locate the problem and to help the project team in theregulation phases.

III.2 Self-Refrigeration (Djebel Grouz)

The Djebel Grouz field lies in the northern part of the Saharan Platform and covers an areaof 144 km2. Actually, the exploitation of its reserves takes place through two wells PDG 3 andPDG 4. The treatment plant is being designed to treat their productions in order to achieve oiland gas sales specification.The produced fluid is first directed to the oil treatment process that comprises separation,stabilization and storage, then the separated associated gas is sent to the gas treatmentprocess composed by compression, cooling and glycol dehydration. Oil is exported to marineterminal located in La Skhira, while the treated gas is delivered to the STEG pipeline.Associated gas from the two first stage separators is routed to Compressor KB-500 suctionthrough a pressure control valve located on the flare line, to be compressed up to 95 Bargthrough 3 compression stages. This valve maintains a constant pressure at compressorsuction of 3 Barg. Compressed gas from KB-500, at 95 Barg, after being air cooled down to

45 C, flows to Gas Scrubber VC-510 to separate condensed liquids, then to JouleThompson Refrigeration Unit. In this unit, the compressed gas is first cooled by flashedcondensates from 45C down to 40 C, then it expands adiabatically through a JouleThompson valve from 95 Barg to 68 Barg and cools down to 30C. Cold gas is then routed to


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Gas Filter Coalescer VA-530 to be filtered down to 1 micron mesh before entering TEGContactor VE-700. Dehydrated gas from TEG Contactor is directed to export Gas MeteringSkid JM-1100 and then injected into 6 gas departing pipeline. Recovered gas condensatefrom gas treatment plant is routed to the oil station via 4 pipe. Joule Thompson RefrigerationUnit is composed by the following equipments:

Gas/Condensates Heat Exchanger HX-510 to reduce the temperature of the gas

flowing from Gas Scrubber by heat up cold condensates recovered mainly from LPCold Separator.

Joule Thompson Expansion Valve to expand adiabatically the cooled gas from 95Barg to 68 Barg and to cool it down to 30 C.

HP Cold Separator upstream the Joule Thompson valve. LP Cold Separator downstream the Joule Thompson valve.

Gas/Condensates Heat Exchanger HX-510 is constituted by two exchangers collocated inseries. The first one uses the flashed condensates from VC-510, while the second one iscooled by the condensates that come from the two separators. In the HP Cold Separator, thegas separates from condensed liquids and then expands through the Joule Thompson valve.After it is directed to LP Cold Separator where it separates condensed liquids and flows to

VA-530. After it goes to dehydration unit where it reaches the required water dew point (-5C at 77 Barg).On the separators condensate outlet lines, methanol injection is used in order to preventhydrate formation.The gas treatment unit has being designed in order to obtain the requiredgas specification for delivery to STEG and also the insertion of the Joule ThompsonRefrigeration Unit permit to recover condensates that otherwise would be lost in the gas.

Fig. 8: Djebel Grouz process flow diagram


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Fig. 9: ProII simulation - Joule Thomson unit

Actually Joule Thompson Refrigeration Unit does not work. For this reason, we havesimulated and optimized this unit using ProII tool (Fig. 9). We have used the PVT of thelevels actually on production and the last production data. Scope of this simulation is toevaluate the amount of gas condensates that we can recover. The results are reportedbelow:

Tab. 3: Joule Thomson unit simulation results

Our simulation shows a gas condensate recovery of at least 3.5 m3/Day, which are recycledto the oil treatment plant and then are sent with the oil to the storage tanks. Now the JouleThomson Unit does not work because in the tanks, a large amount of light hydrocarbons is

discharged in the atmosphere through the relief valve and then lost. So a modification of theactual plant configuration is strictly necessary in order to reduce hydrocarbons losses. Twodifferent solutions can be carried out:

Installing a dedicated pipeline with the necessary equipments, to connect STEG gascondensate pipeline with Joule Thompson Refrigeration Unit.

Installing a VRU on crude oil storage tanks.

An economic evaluation may help us in the choice.


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III.3 Vapor Recovery Unit (Economic Evaluation - Oued Zar)

When heated during the treatment, some of the oil vaporizes. The heated oil inside the tankscontinues to vaporize, thus filling the space between the liquid and the top of the tanks.When the pressure reaches a predetermined value, this vapor is vented into the atmosphereor flared. This reduces the API gravity and decreases the value of the crude oil. Astemperature changes, pressure of the vapor also changes. If the temperature increases, thevapor and the pressure increase. If the temperature decreases, vapor condenses and thepressure decreases. If the pressure reaches a value too high, venting is necessary. Within abattery of tanks, two or more tanks together, if vapor pressure is high in one tank gas goes tothe other one through the equalizing line. When the pressure in all tanks becomes equal andreaches the set point, the VRU begins operative by draining the vapor through a gas line.The gas by-pass system is made by a series of valves and pipes that re-circulatescompressed vapor back to the scrubber and the compressor. This doesnt maintain vaporpressure at a level which keeping compressor running until the pressure inside the tanks canincrease. Pressure inside the stock tanks is usually measured in inches of water. Thecompressor starts when the vapor pressure increases to a predetermined set point, usually 2inches of water. If the vapor pressure drops to 1 inch of water, the compressor stops. In thegas by-pass system, the by-pass valve opens partially operates by a control pilot and some

of the compressed vapor re-circulates while the rest is discharged to the gas gatheringsystem. The vapor pressure drops well below one inch, a by-pass valve opens full and allcompressed gas re-circulates. However, a continue decrease behind a predetermined setpoint will cause the shutdown of the unit.

Decision ProcessCompanies using fixed roof crude oil storage tanks can assess VRU economics by followingfive steps:

Identify possible locations for VRU installation. Virtually any tanks battery is apotential site for a VRU. The keys to successful VRU project are a steady source andan adequate quantity of crude oil vapors along with an economic outlet for the

collected product. The potential vapors volume depends on the make-up and the flowrate of the oil through the tanks. Pipeline connection costs for routing vapors off-sitemust be considered in selecting sites for VRU installation.

Quantify the volume of vapor emissions. Emissions can either be measured orestimated. A calibrated orifice and a pressure gauge can be used to measure themaximum emissions rate that will be utilized to size the VRU. Orifice meters,however, might not be suitable for measuring total volumes over time due to thepressure of tanks. Calculating total vapor emissions from oil tanks can be complicatedbecause many factors affect the amount of gas that will be released:

o Operating pressure and temperature of the separator dumping the oil to thetank and the pressure in the tank.

o Oil composition and API gravity.o Tank operating characteristics (sales flow rate, size of the tank, etc.).o Ambient temperature.

There are two approaches to estimating the quantity of vapor emissions from crudeoil tanks. Both use the gas oil ratio (GOR) at a given pressure and temperature,expressed in standard cubic meter per barrel of oil. The first approach analyzes APIgravity and separator pressure to determine GOR, through curves constructed atdifferent temperatures using empirical flash data from laboratory studies and fieldmeasurements. This graph can be used to approximate total potential vaporemissions from a barrel of oil. For example, given a certain oil API gravity and thevessel dumping pressure, the total volume of vapors can be estimated per barrel of

oil. Once the emissions rate per barrel is estimated, the total quantity of emissionsfrom the tank can be determined by multiplying the per barrel estimate by the totalamount of oil cycled through the tank. The shortcoming of this approach is that it doesnot generate information about the composition of the vapors emitted.


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The second approach is to use a process simulation software (Hysys, Pro II, etc.) forestimating vapor emissions from crude oil tanks. These tools can estimate thequantity of vapor using thermodynamic flash calculations. An operator must haveseveral pieces of information to use a process simulation software, including:

o Separator pressure and temperature.o Separator oil composition.

o Tanks reference pressure.o Reid vapor pressure of sales oil.o Sales oil production rate.o API gravity of sales oil.

Determine the value of recovered emissions. It depends on how these vapors areused:

o Using the recovered vapors onsite as fuel produces a value equivalent to thepurchased fuel that is displaced, mainly natural gas.

o Piping the vapors to a natural gas gathering pipeline should generate a pricethat reflects the higher heating value of recovered emissions.

o Piping the vapors to a processing plant that will strip the LPG from the gasstream and resell the LPG and the methane separately should also capturethe full energy content of recovered hydrocarbons.

Value of recovered vaporsR = Q x PR = gross revenueQ = rate of vapor recoveryP = price of natural gas

Determine the cost of a VRU project. The major elements that impact the profitabilityof VRU are the initial capital equipment, the installation and the operating costs.

Equipment costs are determined largely by the volume handling capacity of the unit,the sales line pressure, the number of tanks in the battery, size and type of thecompressor and the degree of automation. The main components of VRU are thesuction scrubber, the compressor and the automated control unit. A VRU should besized to handle the maximum volume of vapors expected from the storage tanks.When sizing a VRU, the industry rule of thumb is to double the average daily volumeto estimate the maximum emissions rate. Thus in order to handle a given volume ofvapor, a unit capable of handling at least the double should be selected. Installationcosts can add as much as 50 100 % to the initial unit cost. Installation costs canvary greatly depending on location (remote sites will likely result in higher installationcosts) and number of tanks (larger VRU systems will be required for multiple tanks).Expenses for shipping, site preparation, VRU housing construction (for cold weatherprotection) and supplemental equipment (for remote, unmanned operations) mustalso be factored when estimating installation costs. Operations and maintenance(O&M) expenses vary with the location of the VRU (sites in extreme climatesexperience more wear), electricity costs and the type of produced oil. For instance,paraffin based oils can clog the VRU and require more maintenance. Finally, the costof a pipeline to interconnect the tanks battery site with a processing plant or a pipelineis a factor in overall VRU economics.

Evaluate VRU project economics. Installing a VRU can be very profitable, dependingon the value of the recovered vapors in the local market. When assessing VRUeconomics, gas price may influence the decision making process. Therefore, it isimportant to re-examine the economics of installing vapor recovery unit as natural gas

prices change.


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Economic EvaluationThe economic evaluation performed for supporting the installation of Vapor Recovery Unit inOued Zar plant was based on the following base case:

Gas price equals 0.25 $/Sm3. Oil price equals 92.44 $ (Zarzaitine Mlange - January). Discount rate variable 2.5, 5, 7.5 and 10 %.

Operating and Maintenance costs equal 33678 $/Day.

Capital costs equal 118810 $/Day. Installation costs equal 89108 $/Day. Gas recovery factor equals 80 %.

The VRU was based on the compressor operating at 100 psig and on a design capacity of15000 Sm3/Day, corrected by a factor to take into consideration the recovery ofhydrocarbons from the gas phase stream. In fact, the amount of gas from Adam and OuedZar fields that is sold to STEG (Socit Tunisienne de llectricit et du Gaz) is less than theproduced, all the rest is burned. But the gas recovered by the VRU, contains a great quantityof gas condensate. So the value of this gas is higher and its recover brings an economicgain.The flow rates of gas and liquid recovered by this process were estimated by a

simulation with Hysys using the PVT data of well HAWA 1 (Adam concession). The results ofour simulation are:

Gas flow rate equals 10265 Sm3/Day. Gas condensate flow rate equals 0.4252 BBL/Day.

The results of the economic evaluation are the follows:

DISCOUNT RATE IMPACT ON ECONOMIC ANALYSIS

DISCOUNT RATE (%) 2,5 5 7,5 10

PAYBACK PERIOD (MONTHS) 4 4 5 5

NPV ($) 880825 631418 459625 337751

In the table above we can see how the variation of discount rate variable influencing the NPVand the payback period. The project was justified with 29 % of IRR at a discount of 10 % in aperiod of 5 months.Finally this project should be economically accepted.


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CONCLUSIONS

This article has illustrated the different technologies used or being evaluated in Eni Tunisiafields, in order to increase gas condensate recovery. We have spoken about the existingLPG recovery plants in Djebel Grouz, Maamoura and Baraka fields. We have studied andsimulated each process and where was possible optimazed. The differents steps are:

Data collection:

o Project data (Technical equipments data, P&ID, PFD, O&M manual, etc.).o Actual operative conditions (Flow rate, temperature, pressure, etc.).o PVT data of wells on production.o Delivery specifications.

Building the model of the process using a simulation tool (Hysys, ProII, etc.). Setting the model using actual operative conditions. Optimizing the model by regulating where is possible, the operative parameters.

The Djebel Grouz study consists in quantifying the amount of recovered gas condensate.

Actually this unit does not work. The scope of this article is to explain why now this processis not profitable and what we can do to obtain an economic gain. Gas refrigeration process issimple to manage but the recovered LPG is off spec. It is necessary another treatment or aswe can see in the actual configuration, we can stock it with the oil. But this solution is not thebest because an important quantity of light hydrocarbons can be lost in the atmosphere. Toimprove the performances of this plant, we have proposed some alternative solutions andone of these consists in joining two different technologies (VRU and expansion valve). Forchoose, we need an economic evaluation.

In Tazerka plant, The LPG recovery unit consists in a complex process that uses an externalmechanical refrigeration cycle. Also in this case we have simulated the plant but we did notset the model with the real data because actually the CPF is in commissioning phase. For

the existing plants we can optimize the process or study different technical solutions in orderto increase the performances.

The evaluation of vapor recovery unit in our fields is in progress. For the non-existing plantsmany alternatives have to be considered and the choice depends on economic evaluation.Each alternative must to be profitable and the best is selected for the development phase.

REFERENCES

Natural Gas Epa Pollution Preventer, Installing vapor recovery unit on crude oil storagetanks.Gas Processors Suppliers Association, GPSA Engineering Data Book.Saeid Mokhatab - William A. Poe - James G. Speight, Handbook of natural gas transmissionand processing.

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