paper id 20100195 flow assurance studies for

Petrotech-2010

31 October-3 November 2010, New Delhi, India

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Paper ID : 20100195 Flow Assurance studies for development of Deepwater field Vasishta in the east coast of India

B.Ravishankar, Rajan Jayaram & C.P.Singhal

Institute of Oil and Gas production Technology, Oil and Natural Gas Corporation Ltd, Phase-II, Panvel, Maharashtra –410221 Email : [email protected] Abstract

ONGC has many discovered fields which are marginal in size and spread in the Deepwater’s off the

East coast of India. Since no infrastructure is existing in the close proximity stand alone development

needs to be envisaged. Many technical challenges have to be overcome to develop these structures

techno economically. There is a pressing need to monetize these assets to meet the overall energy

shortfall/requirements.

Vasishta is one such structure which is in the anvil for development. The structure lies south east of

Kakinada city of Andhra Pradesh in 400 ~ 700 mts of water depth. Of the various development

options considered, subsea tie back to shore was selected after detailed study. Low subsea

temperatures, long offset distance to shore with a steep fall of the seabed from around 50 to 400 mts

throws flow assurance challenges for evaluation during both steady state and transient operating

conditions.

The present paper describes the various flow assurance issues likely to be encountered during the

lifecycle of the field and the strategies to predict the likely hood of Hydrate formation, means for

mitigation and remediation; extent of slugging during both steady state and transient conditions

through the simulation studies using the industry standard transient multi phase flow simulators.

Introduction

Exploratory efforts in the deepwaters of the east coast of India have led to discoveries of small pools.

Vasishta is one such deepwater gas discovery in 400-690 mts of water depths and around 35 km from

the coastline. Due to cost intensive nature of any Deepwater development, standalone development

of Vasishta was not becoming attractive. Integrated development along with nearby gas field S1 was

considered. The development plan envisages drilling and completion of 4 subsea wells and subsea

tieback to shore through a dual 14”x35 km flowline.The schematic is placed in fig:1. The subsea wells

are planned to be connected to the flowline in a daisy chain configuration. The development

envisages peak production rate of 6 mmscmd of gas with a field life of 10 yrs. High withdrawal rates

are envisaged in order to minimize the well count. The fluids are likely to fall in the hydrate envelope

due to low seabed temperatures and high reservoir pressures. Flow assurance studies were carried

out to predict the likely scenarios that could be encountered during the field life both during steady

state and transient conditions.

Flow Assurance Aspects:

Flow Assurance could be a critical factor in any Deepwater field development. Low ambient seabed

temperatures and long tieback distances lead to heat losses even with the best insulation. The major

Flow Assurance aspects that might affect the production over the field life in view of the low sea bed

temperatures, fluid properties, flowline profile and operating conditions are HYDRATE formation,

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SLUGGING tendency have been analyzed in this paper both during steady state and operability

scenarios. In the operability cases following scenarios were studies Startup, Turndown & Rampup.

Simulation Model

The development model was built considering 4 subsea wells, two each in Vasishta and S1.Flow from

2 wells from each field is manifolded and taken to the shore through dual 14”x 33km lines to shore

facilities at a receiving end pressure of 10 ksc. The water depth in S1 field is 230-350 mts while

Vasishta is in 400-689 mts of water depth and the two fields are ~ 8 km apart.The flow from the

fields are taken to the shore by connecting the manifolds in a daisy chain format. Simulation studies

were carried out by using/ simulation model in the Transient multiphase flow simulator OLGA 2000.

The model was built considering a standard well model with an average well depth of 2000 mts. The

thermal conductivity and heat capacity values for four different materials steel, concrete, FBE and soil

have been considered for insulation of the pipelines for generating a thermo-hydraulic model. The well

fluid was indicated to be dry gas, however for the calculation purpose saturated water has been

considered along with water of 2 bbl/mmscf while generating the fluid model.The envisaged peak flow

rate is of the order of 5.75 mmscmd from the 4 wells.The production profile is placed in fig:2

Simulation Results: During the steady state for a peak flow rate of 5.75 mmscmd with a receiving end pressure of 10 ksc,

the required pressure at the Vasishata end is 22 ksc. Simulation run predicts a temperature of ~ 50

C .

The hydrate curve for the fluid composition indicates that the operating conditions fall within the

hydrate zone fig:3. The temperature profile during steady state is depicted in fig:4.Also the liquid

arrival rates during steady state indicate no evidence of slugging.

Propensity to form Hydrate is the key Flow Assurance issue that has to be addressed during Steady

state flow.

Hydrates: Hydrates are crystal lattices where gas molecules are entrapped in cages of water and can form

potential blocks in the pipeline leading to severe disruption in production and need costly remediation

in deepwater systems. In a gas condensate system the amount of water is critical to the hydrate

formation. The pressure temperature condition at which the formation and dissociation of hydrates

take place are plotted in the Hydrate curve.

Globally the Hydrate formation is well understood. The present field practices for hydrate

management include ways to

� Prevent hydrate formation, � Manage and handle hydrates � Mitigate and carry out remediation.

Hydrate Prevention: Proper modeling tools are available to predict the hydrate formation and dissociation conditions. The

hydrate formation and dissociation models can be validated with experimental data facilitating in

predicting the HYDRATE formation over vast operating conditions. The various means to prevent

could be through maintaining Operating parameters above the hydrate region, through Mechanical

means like providing Insulation, Active heating methods or through Chemical means.

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In the deepwater conditions since the seabed temperature is low, not much leeway exists for

changing the operating parameters to keep the conditions above the hydrate envelope.

The trade off between higher CAPEX spends vs lower OPEX would dictate use of Mechanical means

like Insulation. Two simulation runs were carried out with and without insulation. At the well jumpers

immediately after the choke due to JT effect the temperature of the fluid is below the ambient

conditions. Uninsulated pipe would help in improving the fluid temperatures as can be seen from fig:5.

It is predicted that fluid temperatures in the Vasishta to shore part of the dual flowline reach ambient

temperature within the first 1000 mts for a bare pipe and continue to be 3-40C lower than the ambient

for a wet insulated pipe. It is hence recommended for the subsea flowline to shore to be laid without

insulation.

Active heating has not been analysed due to higher CAPEX and OPEX involved and as conditions are

not very harsh.

The other most vastly practised means of hydrate prevention /management means is through use of

CHEMICAL inhibitors. Thermodynamic and Low Density Hydrate Inhibitors (LDHI) are the two broad

categories under which the chemical means of hydrate prevention is categorized. Thermodynamic

inhibitors like MeOH and Glycols tend to lower the hydrate formation conditions, LDHI’s tend to

prevent water molecules from agglomerization. However the LDHI’s suitability and its dosage has to

be arrived at after carrying out extensive tests with the specific well fluid. In the present study MeOH

was considered so as to share the shore handling and injection facilities with the other deepwater

development. For the considered fluid 20% MeOH was found to be adequate to keep the fluid above

the Hydrate zone.

Operability Scenarios: The flow transients induced during the operability cases-Startup,Rampup &Turndown during the peak

Rate Case Have Been Simulated.

Start Up:

The initial start up has been considered at 25% of the peak rate case of 5.75 mmscmd. The flow has

been allowed to stabilize. Although mild slugging was evidenced at the lower most points they

subsided upon arrival at the shore facility. The arrival rates and the liquid hold up plots are as

depicted in fig 6: During start up at 25 % of peakrate compared to 100% flowrate predicted after bean

temperature is – 200 C which is around 20

0 C less than the steady state case of 0

0 C.fig:7

Ramp Up And Turn Down:

The ramp up from 25% to 100% of the peak rate over a 3hour period has been simulated. The gas

and liquid arrival rates indicate no evidence of slugging.fig 8 .Turn down case from 100% flow rate to

75%,50% and 25% rates over a 8 hr interval has been simulated. It was observed that the liquid hold

up increases at the low points. No slugging is indicative during ramping back to peak rate.

Conclusion:

� Low sea bed temperatures and low well fluid temperatures get the operating conditions into the hydrate envelop even during the steady state. Prevention as a means of addressing Hydrates scores over the other two aspects of Hydrate Control and Remediation.

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� Various methods for preventing, handling and remediation of hydrates like, Operational parameters, Mechanical means(insulation effect),Active heating(DEH and Hot fluid circulation), Chemical means(Thermodynamic Hydrate Inhibitors and Low Dosage Hydrate Inhibitors), have been discussed. The effects of insulation and thermodynamic inhibitors have been simulated.

� It was observed that during the steady state, because of JT cooling the temperature of the fluid becomes sub-ambient and hence system can gain heat from the surroundings by using an un-insulated flowline and same has been suggested.

� Continuous inhibition is required in the present development. Use of 10% methanol by wt. of free water is found to be adequate to keep the fluids above the hydrate conditions throughout the field life.

� The other major Flow Assurance issue-Slugging has been analyzed. During both steady state and operability scenarios like turndown followed by rampup no slugging was evidenced.During the steady state flow,the arrival rates and the liquid hold up in the line are predicted to be normal without any evidence of slugging. During the ramp up from 25% flow to 100% of the peak rate flow, peak liquid arrival rate was found to be 100 m3/d.During turn down from 100% of peak rate to 75% and to 50% the liquid hold up at the low points is predicted to be 2-5% and upon regaining its peak rate the time taken for the fluid temperature to stabilize is long.

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paper id 20100195 flow assurance studies for

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