Oil & Gas Drilling and Extraction Industry

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COMPREHENSIVE INDUSTRYSERIES: COINDS/61/2006-2007

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COMPREHENSIVE INDUSTRYSERIES: CO INDS/61/2006 -2007

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Website: www.cpcb.nic.in e-mail: [email protected]

July, 2006



CPCB 200 Copies, 2006

Published By : Dr. B. Sengupta, Member Secretary, Central Pollution Control Board, Delhi - 32

Printing Supervision & Layout : P.K. Mahendru and Mrs. Anamika SagarComposing & Laser Typesetting : Mohd. JavedPrinted at :ational Institute of Science Communication and Information Resources, CS IR ,

Dr. K.S. Krishnan Marg, New Delhi



T. t. ZTárj Lí,D r. V . R A J A G O P A L A N , AS

CHAIRMAN

1Jfi r- r(r r a r wrap )

Central Pollution Control Board(A Govt. of India Organisation)

Ministry of Environment & Forests

Phone : 22304948 / 22307233

FOREWORD

At the time of independence, oil production in India was of the order of 0.25 milliontonnes which increased to about 34 million tonnes in the year 2004-05 due to expansionin oil dril l ing an d gas extraction in dustry.

Considering the growth and importance of exploration and extraction of hydrocarbon

resources, it has been decided to develop Minimal National Standards (MINAS) for thiscategory of industry. Industry-specific effluent/emission standards and guidelines forcontrolling pollution are prepared by the Central Pollution Control Board (CPCB) inassociation with M/s. EIL. CPCB further revised the waste disposal guidelines and thesame notified for implementation under the Environment (Protection) Act, 1986. Fo revolving such standards, CPCB prepares industry-wise comprehensive documentbased on the information collected through studies in representative industries and fromvarious sources. Techno-economic criteria constitute an important component for thestandards.

The present document deals with the Oil Drilling & Gas Extraction Industry withparticular reference to water and air pollution, disposal of solid wastes andenvironmental standards & guidelines for these.

Dr. Inamul Haq, Addl. Director, Shri N.K. Verma, Addl. Director and Dr. B. Sengupta,Member Secretary coordinated the study and prepared the report. Relevant informationprovided during the interaction meet with Directorate General of Hydrocarbons (DGH)and Oil Companies including ONGC, Oil India, Cairn Energy, Hardy Oil, Reliance &Premier Oil etc. for f inalisation of environmental guidelines is gratefully acknowledged.

( D r . V. Raj ago pa lan )Cha ir m an , CPCB



CONTENT

Page No.

1.0 Introduction 1

2.0 Oil

as

rilling

nd

xtraction

rocess

nd

ollution 3Generating Sources

2.1ril l ing Operation 3

2.2roduction 5

2.3ype and Source of Pollution from Oilrilling and 7

Processing Facilities

3.0 Survey of Oil Drilling Industries 7

3.1ethodology Adopted for Survey/Study 7

3.2onclusion 17

4.0 Characterisation of Liquid Effluent and Treatment Plants Installed 17

by Industry

4.1ril l ing Stage Effluents 17

4.2roduction Stage Effluent 18

4.3reatment / Disposal of Drill Site Effluents 18

4.4

reatment Systems for Produced Water Effluents18

4.5ffluent Treatment Plants (for produced water) Installed 19

by OIL and ONGC and their performance

5 .0 Proposed Treatment Systems for Liquid Effluent 26

5.1roposed Treatment of Drill Site Effluent 26

5 .2roduced Water Treatment 35

5 .3ffordability of Waste Treatment and Disposal 37

6.0 Characterisation and Proposed Mode of Disposal of Solid Waste 38

6.1olid Waste Ge neration 38

6.2ril l Cuttings — Off-shore Handling and Disposal 39

6.3ril l Cuttings — On-shore Handling and Disposal 40



7.0

6.4 Dril l Mud Disposal 40

6.5 Production Stage Solid Waste Disposal 40

Characteristics and Proposed Mode of Flaring the Gaseous 41

Emissions

7.1 Dril ling Stage Gaseo us Em ission 41

7.2 Production Stage Gaseous Emission 41

7.3 Present Mode of Disposal 41

7.4 Proposed Mode of Flaring 42

7.5 Location and Height of Flare Stack 43

7.6 Ground Flares 45

7.7 Enclosed Ground Flare System 45

Environmental

tandards for Oilrilling

nd

asxtraction 47

Industry

8.1 MINAS for Liquid Effluents 46

8.2 Solid Waste Disposal 48

8 .3 Gaseous Emissions 51

Monitoring P rogram 5 3

9.1 Organization Needs 5 3

9 .2 Monitoring 5 3

9.3 Monitoring of Wastewater 53

9.4 Monitoring of Solid Waste and Ground Water 5 4

9.5 Monitoring of Gaseous Pollutants 5 4



1.0 INTRODUCTION

Directorate General of Hydrocarbons (DGH) has so far recognized 26 sedimentarybasins for Hydrocarbon potential in India. The major sedimentary basins includeBombay high, KG basin, Cambay, Cuavery, Assam, Andaman and Nicobar Islands,Rajasthan etc. The total sedimentary area basins including onshore and offshore areaswithin Indian Territorial limits have been estimated as approx. 3.14 million sq. km, ofwhich about 40% of area is still unexplored. The sedimentary basin map of India isshown in (Fig.1).

Total hydrocarbon resources, inclusive of deep waters, are estimated at around 28billion tonnes oil and oil-equivalent of gas (O+OEG). As on 01.04.2004, initial in place oilof 7.89 billion tonnes and ultimate reserves of 2.94 billion tonnes have beenestablished.

India currently imports 70% of its domestic hydrocarbon requirements and is rapidlyrising due to the rapid development. The oil companies in the country produces about34 million tones of oil per annum and 65 million standard cubic meters of gas a day.ONGC alone accounts for 77% of the oil and gas produced in India.

The national oil companies i.e. Oil and Natural Gas Corporation Limited (ONGC) and OilIndia Ltd. (OIL) and private companies that work as Joint Venture (JV) with national oilcompanies are engaged in the Exploration and Production (E&P) of oil and natural gasin the country. The private companies include Reliance, Cairn Energy, Essar, BritishGas, Niko Resources, Hardy Oil, Gujarat State Petrochemicals Ltd. (GSPCL), Phoenix,Premier Oil, HOEC etc.

Government of India is taking several measures to enhance the hydrocarbon reservesand increase production to narrow the gap between supply and demand. The measuresinclude liberalization of the petroleum sector, encouraging participation of foreign andIndian companies in the exploration and development activities. A number of contractshave been awarded to both foreign and Indian companies for exploration anddevelopment of fields on production sharing basis. Operations are presently beingcarried out by national and private oil companies in 529 concessions, of which 235 areunder Petroleum Exploration License ( P E L ) and 294 under Mining Lease (ML).

During the 2003-04, a total of 404 hydrocarbon wells were drilled which include 179exploratory and 225 development wells.

Considering the growth and importance of exploration and extraction of hydrocarbon

resources, the Central Pollution Control Board (CPCB) has decided to evolve NationalEnvironmental Standards for liquid, gaseous and solid waste generated. M/s. EIL wasinvolved in the study and based on the study and discussion, the environmentalguidelines for effluent disposal, air pollution and solid waste disposal were modifiedunder Environment (Protection) Act in the year 1996. Further, in-house work wascarried out during 2001-02 by CPCB to review the environmental guideline particularlywith regard to solid waste disposal which was subsequently notified under EPA.



Sedimentary Basin Map of n i

Fig.1 : Sedimentary Basin Map of India

The above findings are presented in this report. It covers collection, monitoring of airemission and wastewater from ETP and interpretation of the data for existing industriesviz. M/s. OIL and M/s. ONGC, development of environmental standards and wastedisposal guideline in oil drilling and gas extraction industries.

2



2.0 OIL DRILLING & GAS EXTRACTION PROCESS AND POLLUTIONGENERATING SOURCES

2.1 Drilling Operation

The majority of the wells are drilled to obtain access to reservoirs of oil & gas. However,some are also drilled to gain knowledge of the geological formation.

Most wells are drilled nowadays by rotary drilling methods. Basically the methodsconsist of

1. Machinery to turn the bit, to add sections on the drill pipe as the hole deepens,and to remove the drill pipe and the bit from the hole.

2. A system of circulating a fluid down through the drill pipe and back up to thesurface.

This fluid "drilling mud" removes the particles cut by the bit, cools and lubricates the bitas it cuts, and, as the well deepens, controls any pressures that the bit may encounter

in its passage through various formations. The fluid also stabilizes the walls of the wellbore .

The drilling fluid system consists of tanks to formulate, store, and treat the fluids, pumpsto force them through the drill pipe and back to the surface and machinery to removecuttings, fines and gas from fluids returning to the surface. A system of valves (blow-outpreventer) controls the flow of drilling fluids from the well when sub-surface pressuresare so great that they cannot be controlled by weight of the fluid column (Fig. 2).

For off-shore operation, drilling rigs may be mobile or stationary. Mobile rigs are usedfor both exploratory and development drilling, while stationary rigs are used for

development drilling in a proven field. On-shore drilling rigs used today are almostcompletely mobile. The derrick or mast and all drilling machinery are removed when thewell is completed and used again in a new location.

The major source of pollution in the drilling system is the drilling mud and cuttings fromthe bit. In early days, before formulated muds were developed, drilling mud was madeby mixing water with naturally occurring soils and clays for different characteristic forsuperior performance. The composition of modern drilling muds is quite complex andcan vary widely, not only from one geographical area to another, but also in differentportion of the same well. A well is drilled in sections, and as each section is completed itis lined with the section of pipe or casing.

The different sections may require different types of mud. Basic mud component includebentonite to increase viscosity and create a gel, barium sulphate (barite) a weightingagent, and lime and caustic soda to increase the pH and control viscosity. Additionalconditioning constitutes may consist of polymers, starches, lignitic material, and variousother organic and inorganic additives to achieve the desired consistency, lubricity,density, pH control , corrosion inhibit ion, weighting and emulsif ication.

3



Fig. 2 Various Stages of Drilling



Most muds have a water base but some have an oil base. Oil base muds are used inspecial situations when bottom hole temperatures are very high or where water basedmuds would hydrate water sensitive clays or shells. They may also be used to freestuck drill pipes, to drill in permafrost areas, and to kill producing wells. Oil based mudscontain carefully formulated mixture of oxidized asphalt, organic acids, alkali, stabilizingagents and diesel oil.

As the drilling mud is circulated down the drill pipe, around the bit, and back up inannulus between the bore hole and the drill pipe, it brings with it the material cutloosened by the bit, plus fluids which may enter the hole from the formation (water, oil orgas). When the mud arrives at the surface, the cuttings, silt, and sand are removed byshale-shakers, desilters and desanders (Fig.3). Oil or gas from the formation is alsoremoved, and the cleansed mud is cycled through the drilling system again. In case ofoff-shore drilling the cuttings, silt and sand are discharged overboard if they do notcontain oil above a specified level whereas in on-shore drill-sites these are dumped inearthen pits.

The process of mud treatment and conditioning is done to keep the mud characteristic

constant or to change them as required by the drilling conditions. Many constituents ofthe drilling mud can be salvaged when the drilling is completed.

22Production

Crude oil, natural gas, and gas-liquids are normally produced from geological reservoirsthrough a deep bore well into the surface of the earth. The fluid produced from oilreservoirs normally consists of oil, natural gas and brine containing both dissolved andsuspended solids. Gas wells may produce dry gas but usually also produce varyingquantities of light hydrocarbon liquids (condensate) and brine.

In the case of oil field brines, the water contains dissolved and suspended solids

(sands, clays or other fines from the reservoir) and hydrocarbon. The oil can vary widelyin its physical (mainly density and viscosity) and chemical properties. The oil can rangefrom very light gasoline-like materials (called natural gasolines) to heavy, viscousasphalt-like materials. The fluid after rising to the surface, flows through various valvesand flow control devices.

Fluids from nearby wells are taken through pipes to the central Group Gathering Station(GGS) / Oil Collecting Station (OCS) / Gas Collecting Station (GCS), as the case maybe, for separation of the various constituents in the fluids (viz, gas, oil and water). Theseparation is done in several stages at successively lower pressure before the oil is freeof gas. Usually a quantity of oil and water is present as an emulsion. This emulsion can

occur naturally in the reservoir or due to mixing during passage of the fluids throughwellhead, pipes, valves, chambers and through any centrifugal pumps in the system.Moderate heat, chemical action, and / or electrical charges tend to cause the emulsifiedliquids to separate or coalesce. Some types of chemicals and fine suspended solidstend to retard coalescence. The characteristics of the crude oil also affect the case ordifficulty of achieving process separation.

5



Fig. 3: Mud System on a Drilling Rig



Water which is not emulsified and separate easily may be removed in a simpleseparation vessel (free water knockout). The remaining oil-water mixture will continue toanother vessel (which may be called a heater-treater, electric dehydrator, gun barrel orwash tank, depending on the configuration and the separation method employed) formore elaborate treatment. De-emulsifiers are often added before the liquid enters thisvessel. A combination of treatment methods is often employed in a single vessel. Inthree phase separation, gas, oil, and water are all separated in one unit. Oil from the oil

water separators is usually sufficiently free of water and sediment (less than 2%) so asto be marketable (Fig. 4).

In case of wells producing only gas, the extraction is controlled as per requirement ofusers (Fig. 5). However for oil & gas wells although the oil is collected in Crude oil tank(before transported to refineries), the associated gas which is in excess can betransported through pipelines and flared through stacks. The water (produced water)which separates out is collected at the bottom of the tank and is taken out for treatmentbefore final disposal.

2.3Type and Sources of Pollution from Oil Drilling and Processing Facilities

The various types of and sources of pollutants generated in this industry is listed below:

Liquid Effluents Gaseous Emissions Solid Waste

1. Drilling Stage

Formation water Test-Flaring(insignificant)

Drill-cuttings

Wash waste from bit cuttings(mud treatment), auxiliarywaste-sanitary

DG sets D ri l ling mud

2. Production Stage

Produced water Associated gas O ily sludge

30URVEY OF OIL DRILLING INDUSTRIES

3.1Methodology Adopted for Survey / Study

Since the oil exploration of hydrocarbons in India is being carried out mostly by M/s. OILand M/s. ONGC, the collection of relevant data was carried out by sending aquestionnaire, carrying out actual sampling and visiting at various oil fields of both the

organizations.

The questionnaire sought information on the production of crude oil and natural gasfrom each region, type of drilling process adopted, type and quantum of liquid, solid andgaseous effluents generated and at what stage of the production these are generated,present system of liquid effluent treatment and disposal of gaseous and solid waste.

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The characteristics of waste water (produced water) generated by various fields ascarried out by EIL is given in Table 1. The gaseous emission from drill site as well asfrom Group Gathering stations and oil collecting stations are given in Table 2 andquantum of drill cutting (solid waste) generated is given in Table 3.

For characterizing of liquid effluents actual sampling at various locations was carried outby M/s. EIL with the help of State Pollution Control Board and the Table 4 and Table 5

highlights the results of 41 sampling locations.

For collecting information on the resultant ground level concentrations (GLC) ofpollutants due to gaseous emission, the ambient air quality survey carried out by NEERIfor ONGC has been utilized.

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Table 2 : Gaseous Emission

A. Sources of Gaseous Emission

Drilling:

•laring

•.G. Sets

Production:

•laring of associated gas which is not being utilized.

B. Gaseous Emission

Drilling:

Diesel consum ption 5-6 K I/day/drilling site

Characteristics SO2 -.5 kg/hrNO X -ilHCilCO -ilProduction:

Flaring:

Flow rate 450-1500 Nm 3/hrStack height 5-10 m

(Some case 28-30 M for emergency flaring)

Concentration SPMNil

SO2Nil

NOx200 ppmHC80 ppmCO0.2%

12



Table 3 : Categories of Major Discharges from Off-shore Oil and Gas Operations

S.No. Discharge Category Exploration Development Production

1. DrillingluidsTotaladditivesoater-basedystemsndvolumes discharged)

Well depths less than 520-709 7090-212793050 m tons/well tons platform

417-1094m 3/wel

Wellepthsreater 672-2118 10940 —32820than 3050 m tons/well m3 /platform

900 —4800m 3/well

2. Drill Cuttings 823-1285 9000-27000tons/well tons/platform

3. Produced water 0 —2709

m 3/day perplatform

(Source : Mis. EIL information)

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32Conclusions

Based on the careful examination of the information available and data collected duringthe study period following conclusions could be drawn.

1. The major source of pollution during drilling and production stage is waste water.

2. The major part of solid waste generated during drilling stage is drill cuttings andwaste mud. Drill cuttings are inert in nature however drilling mud adhered in theform of coating could be a source of pollution due to wash out. Small quantity ofsolid waste is generated during production stage in the form of oily and bio-sludge.

3 .ource of air pollution during the drilling stage is exhaust gases from dieselgeneration sets and well testing. The well testing lasts for about 2 days per well.

During production stage the major source of air pollution is the flaring ofassociated gas. The other source is the exhaust gas from natural gas fired power

generation sets. Captive power generation is adopted only in absence of powerfrom outside source. Gaseous pollutants during both the drilling and productionstages are product of combustion of natural gas and oil.

4 . 0h a r a c t e r i s a t i o n o f L i q u i d E f f l u e n t a n d T r e a t m e n t P l a n t s I n s t a l l e d b y

I n d u s t r y

4.1 Drilling Stage Effluents

4 . 1 . 1 Types of Effluents

During drilling operation two types of effluents are being generated

1. Formation water which comes out from the formation along with drill cuttings andmud.

2. Effluents from washing of drill cuttings floor washings, pump and seal leakages,spillages etc.

4.1.2 Characterisation of Effluents

Based on the data presented, the effluent from well site may be characterised as given

below:

•uantity of Effluents : Flow rates of effluents from drill site is of the order of 5-10m 3 /day.

0uality of Effluent: R ange of chara cterist ics for dril l site eff luent is as p er Table 6.

1 7



4.2 Production Stage Effluent

4.2.1 Produced Water.

During production stage oil, associated gas and formation water is separated. The waterso separated is the major source of wastewater generated during oil/gas production andis identified as `Produced Water'. Unlike the drilling stage effluent from production stage

are generated at a centralized processing facility such as Group Gathering Station(GGS), Oil Collecting Station (OCS) or Gas Collecting Station (GCS).

4.2.2 Characterisation of Effluents :

Based on the data presented, the produced water effluent may be characterised asbelow:

•uantity of Effluent : The quantity of effluent at GCS range from 60-100 m 3/dayand that at GGS/OCS from 1000-4000 m3/day depending upon the water cut andnumber of wells connected to each station.

•uality of Effluent : Characteristics for produced water is given in Table 7.

4.3 Treatment! Disposal of Drill Site Effluents

Effluents generated at on-shore drill site are taken to an effluent pit of sufficient size tocater to the total quantity of effluent generated during the complete drilling operationperiod of 45 to 60 days.For off-shore installations all the drill site washings are discharged into sea. A typicalscheme for washing and discharging the liquid effluents is shown in Fig. 3 for on-shoreand Fig. 6 for off-shore installations respectively.

4.4 Treatment Systems for Produced Water Effluents

The treatment plant are provided at their major GGS/OCS in order to meet standards fortreated effluent discharge. Since the major pollutants in the effluents are oil, emulsifiedoil and BOD, the following principal stages of treatment are essential.

i) Primary oil separationii ) Secondary oil separation (Emulsified oil removal)i i i )iological treatment

4.4.1 Oil and Grease Removal:

The oil in waste water can exist in free, emulsified and in soluble phases. Free oil of thesize of 60-150 micron size are removable by primary oil separation units such as API oilseparators or TPI o il separators.

18



Entrained oil lower than 60 micron size and the emulsified oil are removed byflocculation and sedimentation. This can be achieved by Dissolved Air flotation units.Flocculants such as alum, ferrous sulphate and lime are commonly used for thispurpose. Soluble oil in waste water is removed by secondary biological processes.

4.4.2 Biological Treatment:

Biological treatment unit is primarily meant for removal of pollutants like residualsulphide, dissolved oil, phenol and BOD due to dissolved organic pollutants. Biologicaltreatment can be achieved by various processes such as activated sludge and bio-filters. In case where BOD is high a bio-filter can be installed as roughing deviceupstream of the activated sludge process.

4.5Effluent Treatment Plants (for produced water) Installed by OIL and ONGC

and their performance

Both OIL and ONGC have installed waste water treatment plants and salient featuresof some of these are described below:

4.5.1 ETP Installed by M/s. OIL at Duliajan:

M/s. OIL have installed ETPs in Naharkatia oil fields at there oil collecting stations. Thetreatment plant consists of CPI oil separator for free oil removal, Depurator foremulsified oil removal and pressure filter for residual oil and suspended solids removal.The indicative block diagram of this ETP is shown in Fig. 7 and its performance isshown in Table 8.

4.5.2 ETP Installed by M/s. ONGC at Lakwa GGS:

The ETP installed at Lakwa has facilities for equalization and then free oil removal inAPI separators, sulphide and emulsified oil removed by chemical treatment in a flashmixer and clariflocculator. Finally the clear effluent is taken to the guard pond and isfiltered through a Hay filter before discharge. The treatment scheme is shown in Fig. 8and performance of ETP is shown in Table 9.

4.5.3 ETP Installed by ONGC for their GCS at Tatipaka:

The ETP for GCS at Tatipaka consists of equalization and TPI oil separator for free oilremoval and chemical coagulation for emulsified oil removal. After oil removal, theeffluent is subjected to biological treatment using biofilter with plastic media. Then

treated effluent is passed through dual media pressure filter for removal of residualturbidity. Effluent treatment scheme is shown in Fig. 9.

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4.5.4 ETP Installed by ONGC at Off-shore Platform:

The produced water treatment at off-shore platform is slightly different due to the spacelimitation and the treated effluent is to be discharged into sea. The effluent is taken to aflash vessel whose lower hydrocarbon are flashed and sent to flare. The effluent fromflash vessel is taken to CPI and D A F / IGF for f ree o i l remo val and em ulsif ied o i l remo val

respectively and the treated water is discharged into sump caisson. Floating oil fromsump caisson is sent to skimmer vessel. Fig. 10 shows the treatment scheme andperformance in terms of oil removal.

Table 6: Characterisation of Drill Site Effluents

S.No. Parameters Units Ranges

1. Totaluantityuringherillingoperationi) Forellepthsesshan

3000 M

ii) For

ell

epths

ore

han

3000 M

m 3

m 3

400-1000

900-2500

2. PH - 7.15-10.33. Oil and Grease Mg/lit. 5 —5 0

4. Total Suspended Solids 200 —850

5 . Total Dissolved Solids 500 —2000

6. BOD. 100-1507. COD 500-8008 . Iron " 2.0-11.09. Heavy Metals like Chromium Nil —8.0

(Source : M/s. EIL report)

Table 7: Characterisation of Produced Water from Oil and Gas Installations.

S . No. Parameters Units Range

GGS/OCS GC S

1. Flow rate m 3 / d a y 1000-4000 60— 100

2. pH - 6.7 — 10.4 5 — 9

3. Oil and Grease mg/lit. 100 —2000 Nil —100

4. BiochemicalxygenDemand

200— 1000 200— 1000

5 . Chemical Oxygen Demand 500 —2000 500 —2000

6.Total Suspended Solids 100 —2000 200 —800

7. Total Dissolved Solids 1000-43000 500 —1000

8. Sulphides ND —6.0 ND

9 . Chlorides 500 —16000 10 0 —200

10 . Cyanide ND-4.0 -

11 . Phenolics ND —7.0 2 —10

12 . Chromium ND-1O.0 -

(Source : Mis. SEIL report)

24



) SKIMM INGVESSEL

SYSTEM HANDLING CAPACITY : 138,908 B W P D E & E N D

DESIGN OIL CONTENTROTH

FL ESH DRU M IN L ET500PPMRO DU CED WA TERCP I SEP AR A TOR OUTLE T: 50 PPM

S U M P C A I S SO N O U T L E T : 25 PPM-RECOVERED OIL

Fig. 10: Produced Water Treatment at ICP Platform

NO



Table 8: Performance of ETP installed at OCS, M/s. Oil India Ltd.

S.No. Parameters Unit Effluent CharacteristicsBefore

TreatmentAfter Treatment

1. pH - 8 .8 8 .8

2. TSS mg/lit 38 36

3. TDS mg/lit 6534 65724. Oil and Grease mg/lit 486 Traces

5 . Sul hides mg/lit Traces Traces

6. COD mg/lit 24 6 118

7. Chloride mg/lit 1154 1154•

(Source : Mis. EIL report)

Table 9: Performance of ETP installed at Lakwa GGS, M/s. ONGC

S.No. Parameters Unit Effluent Characteristics

Before

Treatment

After Treatment

1. pH - 7.2 7.1

2. TSS mg/lit 122 -

3. TDS mg/lit 1238 -

4. Oil and Grease mg/lit 845 5 .8

5 . BOD5 mg/lit 330 19.0

6. COD mg/lit 1642 37.0

7. Chloride mg/lit 5 00 61 0

8 . Sulphate mg/lit - 40

(Source : M/s. EIL report)

5.0 PROPOSED TREATMENT SYSTEMS FOR LIQUID EFFLUENT

The proposed treatment system for drill-site effluents and produced water from GCSand GGS on-shore and produced water at off-shore are different due to difference inflow rates and characteristic and disposal method. These (the treatment schemes) aresumm arised in Fig. 11 — 18 .

5.1Proposed Treatment of Drill Site Effluent

5.1.1 Treatment Scheme (On-shore):

The treatment scheme proposed is shown in Figure 11 which comprises of an oil

removal unit (DAF) followed by a pressure sand filter. At some of the sites dependingupon the mud composition, chromium will be present in pit effluent. In such situationsthe flotation unit will be replaced by a clariflocculator unit. The chromium present will befirst reduced to trivalent state and then precipitated as hydroxide. The chromiumhydroxide sludge will be disposed off in the secure land fill facility along with drillcuttings. The secure land filling facility will be developed as per the existing guidelines.

26



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The treated water will be re-used for mud-preparation or disposed off suitably. Thespecified standards for the disposal of drill site effluents is given under section 8 of thisreport. For arriving at these standards the best practical control technology approachhas been adopted.

5.1.2 Cost Analysis of Drill Site Effluent Treatment (On-shore):

1. Cost of drill site effluent treatments. 30lakhsplant (10 m 3/d)

2. OperatingostwithoutCr" -s. 10,000 per yearremoval)

O perating cost (With "Cr" rem oval)R s. 15,000 per year

3 .mortized cost (15 years @ 1 8 % )R s. 5.895 Lakhs

It is not possible to compare pollution control cost with turnover, as the crude willultimately go to the GGS for treatment.

52Produced Water Treatment

5.2.1 Produced Water Treatment (Off-shore):

Oily water from various production vessels are collected in produced water flash vesselwhere dissolved gases are separated and free-oil is separated by gravity. Theseparated oil is collected to the closed drain header. The produced water from flashvessel is collected in CPI (corrugated plate interceptor) separator. The oil recovered isrouted through oil sump and pumped to surge tank. The produced water is routed toinduced gas floatation unit where water is separated from oil and fine particulate andclear water is discharged to the bottom of sump caisson. The sump caisson is located at

Jacket level and extends up to 5 ft in sea water from surface. Accumulated oil at thesurface is lifted to be re-routed through separator. The caisson discharges treated waterfrom bottom (Fig. 18).

5.2.2 Cost Analysis Produced Water Treatment (Off-shore):

A . Capital cost (TPI + IG F)Flow 1000 m3/d

Operating costB. A n n ua l T ur n o ver

C.mortized Cost (15 years @ 18 % )

-s. 150 lakhs

-s. 5.25 lakhs-s. 30,000 lakhs

-s. 30 Lakhs

3 5



5.2.3 Produced Water Treatment (On-shore):

A . When Total Dissolved Solids are less than 2100 mg/I:

Produced water will be collected in an equalization tank followed by a TPI unit for freeoil removal. The effluent will then be passed through a DAF or an IAF unit for the

removal of emulsified oil. Depending upon the BOD level it will be subjected to eitherone stage or two stages biological treatment. Effluent will be polished in pressure sandfilter before disposal. Capacity of plant will be 100 m 3/day in case of gas collectingstation (Fig. 12) and 1000 m 3/day in the case of group gathering station (Fig. 13, 14/15and 16).

B. When the Total Dissolved Solids are more than 2100 mg/I:

When produced water contains high dissolved solids (land based facility), there is noalternative but to dispose off the effluent by re-injection in an abandoned well. In thiscase the facility will comprise of free and emulsified oil removal, fine filter unit

(cartridge), deoxygenation tower (in case of open system) and chemical injection thewater is re-injected by using high pressure pumps (Fig. 17).

5.2.4 Cost Analysis* for Produced Water Treatment (On-shore) :

1 . Disposal on land

Capital cost (TPI + D A F + Bio-reactor + Pres. Filter)

Flow 1000 m3/d (GGS)80 IakhsFlow 100 m 3/d (GCS)0 lakhs

Operating cost

Flow 1000 m3 /d3.68 lakhsFlow 100 m3 /d.01 lakhs

2. Disposal by re-infection

Capital Cost

Flow 1000 m 3 /d80 lakhs

Flow 100 m3/d00 lakhs

Operating cost

Flow 1000 m 3/d0 lakhsFlow 100 m3 /dIakhs

36



3. Annual turnover

GGSGCS

4. Amortized cost

a) Disposal on landb) Disposal on landc) Disposal by re-injectiond) Disposal on re-injection

300 crore2 crore

Flow 1000 m 3/dFlow 100 m 3/dFlow 1000 m 3/d

Flow 100 m 3/d

-75lakhs-6 lakhs-95lakhs-20lakhs

5 .atioOperating cost + Amortized Cost---------------------------------------------- X 100

Annual turnovera) 0.295%

b) 9.0 %c) 0.38 %d) 13.0 %

The cost analysis is based on 1990-91 figures.

5.3Affordability of Waste Treatment and Disposal:

Capital and operating costs have been worked out for the treatment of wastewatergenerated during extraction of oil and gas. Wherever possible sum of amortized costand operating cost has been compared with figure of turnover. For calculating turnoverof gas f ield, gas production rates of 1500 N M 3/Hr have been assumed at each GCS. For

GGS the oil to produced water rates has been assumed to be 1 : 0.4 as the quantitymay very from 10% to 90% during the lifetime of well. For Amortization purposes, thepay back period is 15 years and the rate of interest 18% p.a. Cost of associated gas hasnot been included in the turnover cost as till full utilization is realized it will be flared. (Itmay however add marginally to turnover).

It is observed that for off-shore installation the treatment cost works out to be 0.11% ofthe turnover. For on-shore installations the cost of treatment for GGS is 0.3 to 0.4%depending upon mode of disposal. Cost of disposal for GCS (Gas collecting stations) ishowever a bit higher (9-13%) due to higher cost of treatment plant relative to turnover.

Cost of development of disposal site for drill cuttings is of the order of 0.5 crores anddefinitely worthwhile as it avoids the uncertainly associated with off-shore disposal ofdrill cuttings and drilling muds.

37



Wastewater Treatment Cost Analysis

S. Type & Source Qtty. & Char. Cost of treatmentNo .

On-shore

1. Drill site effluent 10 m 3 /day Table 7 •reatment plant = 30 lakhs

•perating cost = 15,000

nmortized = 5.6 lakhs

2. Produced water

2.1 Gas collecting Stn. 100 m3 /day Table 8 •reatment plant cost = 80 lakhs (L.D.)

•ost of disposal by reinjection = 10 0

lakhs (L.D.)

•perating cost = 2 lakhs

•perating reinjection cost = 6 lakhs

•atio (OC + AC) / AT = 9% (L.D.)

•atio for reinjection = 13 %

2.2 Groupathering 1000 m3 /day Table 8 •reatment plant cost = 380 lakhs (L.D.)Stn. nost of disposal by reinjection = 480

lakhs (L.D.)

•perating cost = 14 lakhs

•perating reinjection cost = 20 lakhs

•atio (OC.+ AC) / AT = 0.3% (L.D.)

natio for reinjection = 0.4%

Off-shore

3. Produced Water 1500 m3/day Table 8 •reatment Plant = 150 lakhs

•Ratio=0.11%

OC - Operating Cost;C - Annual Cost;

AT - Annual turnover;D - Land disposal

Standard proposed: refer section 8.

6.0 CHARACTERISATION AND RECOMMENDED MODE OF DISPOSAL OF

SOLID WASTE

6.1 Solid Waste Generation

6.1.1 Drilling stage:

Solid waste generated during drilling stage comprises of drill cuttings which arebasically crushed sedimentary rocks and used drilling muds which are not furtherusable.

3 8



Quantity of Drill Cuttings Produced

Quantity of drill cuttings depend upon the depth of drilling, the hole size and the intervalof each section. Average figures are of the order of 800 — 1200 tons/well.

Characteristics of Drill Cuttin

Drill cuttings comprise of inert sedimentary rock. Trace quantities of metals mayhowever be present depending upon the formation composition. Drill cuttings aregenerally passed through mud recovery and treatment plant which essentially removesall the mud present in cutting. Small quantities of drilling mud may however be stillpresent on the cuttings in the form of coating and clings.

6.1.2 Solid waste generated during production stage:

Small quantities of sand and other solids are produced along with the produced water atapproximately 1 barrel per 2000 barrels oil.

Other solid waste generated during production stage is the oily and biological sludgeproduced in the GGS/OCS waste water treatment plants.

6.2rill Cuttings — Off-shore Handling and Disposal

6.2.1 Present Practice

Drill cuttings are separated from the drilling fluids on shale shaker units. They are eitherwashed with high pressure spray or by immersion in a tank containing a wash solutionequipped with agitator. The wash solution may be sea water, a water based washsolution or closed solvent wash system. Sometimes a detergent is used to facilitatewashings which separates the solids, oils and additives from wash solution. Theseparated oil and additives may be returned to the drilling mud system. Wash solution isrecycled and the washed cuttings are typically discharged overboard.

6.2.2 Proposed Methodology for Handling and Disposal of Drill Cuttings

Drill cuttings separated from mud will be transported on-shore through supply vessels. Itwas proposed by EIL for all types of drilling fluid used in the process. However, theguideline revised further and proposed that only drill cutting in case of oil-based mud bebrought to shore. They will be transported further by trucks to a suitable site to bedisposed off in a secure land fill facility developed specifically for the purpose.

K 7



6.3 Drill Cuttings — On-shore Handing and Disposal


The °mechanism of separation of drill cuttings from drilling mud in the case of on-shore

facilities is the same as off-shore, except for the fact that the disposal point on-shore ismud-pit. The wash water used in the process is also accumulated in the pit.Com posit ion o f the eff luent f rom dril l ing site pit is m entioned in Table 6.

6.3.2 On-shore Disposal of Untreated Cuttings

The drill cuttings from shale shakers, desanders and desilters of the drilling rigs will beconveyed to suitable metal containers on board the platform. The containers will beshipped on-shore by means of supply vessels at the port and the containers will beloaded on trucks which will carry them to the disposal site. The design of disposal sitewill be approved by the SPCB to prevent the material from leaching during rains.

6.4Drill Mud Disposal:


In most of the cases water based muds are being used by both M/s. OIL and ONGC.However, in a very rare case some specialized mud system based on either oil orpolymer have been used.

Since the mud is made up of very costly chemicals, these are used and reused atdifferent drilling sites by safely collecting and transporting it from one site to anothersite. But after several reuse, part of these muds become unusable and it is to bedisposed off.

Presently these are disposed off by dumping on some site nearby the drilling site for on-shore installations and dumped into sea for off-shore installation. This practice has to bemodified and guidelines for its proper and environmentally safe disposal have beenproposed.

6.5 Production Stage Solid Waste Disposal

The dried sludge from waste water treatment plant should be disposed off at a securedland fill as has been suggested for drilling mud.

In case oil content in thé sludge is high it should be incinerated and ash should bedisposed off at a secured land fill.

ái7



Other solid waste produced in the production stage should also be disposed off atsecured landfill.

70CHARACTERISTICS AND RECOMMENDED MODE OF FLARING THE

GASEOU S EMISSIONS

7.1Drilling Stage Gaseous Emission :

D uring dr i l l ing stage fo l low ing em issions are ant icipated :

•xhaust gases from diesel engines and power generators.•roduct of combustion due to burning of oil and natural gas during well testing

durat ion o f 2 days.

The quantity of diesel consumed during drilling is of the order of 5-6 kl/day per site. Theproduct of combustion are :

SPM - 10.8 kg/daySO2-.1 kg/dayN O X-7.6 kg/dayHC2. 1 kg/dayCO3.0 kg/day

The quantity of gas flared during well testing is small and hence the emissions areinsignificant.

72Production Stage Gaseous Emission:

The gaseous emissions during production stage are :

•laring of unutilized associated natural gas.•xhaust gases from power generation sets.

The quantity of gas flared from production facilities like GGS/GCS/OCS are of the ordero f 450 — 1500 NM 3/hr. Exhaust gas composition are as follow:

SPM - NegligibleSO 2-epends on the sulphur contentsN O200 ppmHC80 ppmCO0.2%

73Present Mode of Disposal:

Presently the gaseous emission from production GGS/OCS is flared either throughelevated flares or ground flaring resorted in an effluent pit to cool the nozzles. Elevated

41



flares have glaring effect as well as radiation effect on paddy fields during floweringseason and silkworms in North East region. The ground flares do not have these effectsbut results in high ground level concentration of pollutants and thermal radiation in thevicinity of flare. The light intensifies at night around some of the GGS in North Eastregion and as found after 80-120 m from the source of light, the intensity becomes moreor less constant. Since paddy which is a short day flowering plant requiring less than 12hours for photosynthetic radiation for flowering, this type of elevated flaring needreconsideration in these areas.

74Recommended Mode of Flaring:

In order to overcome the problems mentioned above, it is essential to study andcalculate the proper stack height with respect to ground level concentration as well asthermal radiation point of view for no man's land around the flare. In order to overcomethe problem of roof emission associated with flares it is possible to design smokelessf lares.

7.4.1 Smokeless Flare Design.

Steam assisted flares should be used at processing facilities. Following empiricalformula is recommended for evaluating the requirement of steam for producing asmokeless flare as a function of the flow rate of hydrocarbons and their molecularweight.

WS =H (0.68 — 10.8/M)

WhereS =team Kg/hrWH =ydrocarbon Kg/hrMolecular weight

Since steam consumption may be very high in certain cases and it is too expensive toprovide for smokeless burning for the maximum flare load (Max. load / Normal loadratio: 3), 20% of the maximum load is designed for smokeless burning. This issupported by fact that frequency of occurring of maximum load is rare and hence formost of the time the flare is smokeless.

7.4.2Automatic Smoke Control System:

Automatic control is the best way to minimize steam consumption, supplying only the

required amount to keep the flare smokeless at a particular gas flow rate. Excessivesteam can produce burning back into the flare tip besides increasing the flare noiselevels and wastage of energy.

With automatic control, steam is controlled by the flame appearance. An optical unit iscalibrated to a particular frequency in the infra-red spectrum, ensuring smokeless flaring



over range of flow rates. This system provides a continuous output signal for control ofsteam valve.

The sensing head detects the changes of hot carbon flux density and generates asignal, modulating the automatic steam control valve flow rate, allowing only the steamnecessary for smokeless and complete combustion. With this fast response system thedetector is remote and not in contact with waste gas. Also the control is independent ofthe gas flow conditions. The system is mounted at grade and is very convenient forretrof its.

At places where system is not available air assisted flares should be used.

7.5Location and Height of Flare Stack:

The stack should normally be located on the lee side of the plant / drilling facility(downstream of prevailing wind direction) and remote from operating / trafficked zones.

The minimum height of the flare stack should be arrived at to satisfy the following

condit ions :

i) Maximum ground level concentration of pollutants should be within limitsprescribed by Statutory Authorities (CPCB / SPCB). The maximum GLC may becalculated by using equations given below (para 7.5.1).

ii) Maximum thermal radiation from the flare should be within permissible safe limitsof 440 Btu/hr/ft 2 at the periphery of safety zone provided around the flare. Thesafe distance may be calculated by using relevant equations given under para7.5.2.

i i i )inimum physical height of stack should be 30 m f rom ground level .

Following equations are to be used for arriving at the minimum stack height :

7.5.1 Maximum Ground Level Concentration Criteria:

3.697 V M (D z )Cmax = -------------------------- max =

uHDy(H /Dz)2 / ( 2 -N )

Cmax -oncentration at grade in ppm (volume)

Vp. V ol. O f toxic gas, cu.ftl lbMeight discharge of pollutant in tons/dayD zertical diffusion coefficient = 0.13uir velocity at gra de in ft/secHtack height (ft)

43



Dyorizontal diffusion coefficient = 0.13Nnvironmental factor = 0.25

7.5.2 M axim um R adiation Intensity Exp osure Cr iteria:

1.alculate the radiation intensity using following equation

qQ / 455 X

qadiation intensity BTU/hr/sqftfmissivity of the flame = 0.35Qeat generated by flame BTU/hrXistance from center of flame (X meter feet above grade) to

receptor

Following relation can also be used to calculate `f' from the net calorific value of flaredgas whenever available

f = 0.2 J1Q9 00

hcet heat value of gas in BTU/scf.

Heat generated by the flame is calculated as follows :

Q = W.hc x 379M

Wb/hr of flare gashcet heating value BTU/scfMolecular weight of gas

This safe radiation intensity for unlimited time of exposure is 440 BTU/hr/ft 2 . For

operating personnel the allowable limit is 1500 BTU/hr/sqft and for equipment it is 3000BTU/hr/sqft.

Based on the allowable maximum intensity at receptor, the distance X is calculated. Theheight of flare stack is then calculated based on following equation

Y = [X - H (H + L)]o .5

Wherein

Yadial distance from the base of stack to receptor, ft• Xistance from center of flame to receptor, ft

Htack height, ftLlame length of the flare



The effect of wind velocity on the radiation intensity can be estimated by using followingequation. The stack height is then corrected accordingly.

Tan o = UwU

Where,Ulare exit velocityUw=ind velocity

YX2 — (H + (X m -H ) CosO) 2].5+X m -H). Sino

X m=eight of flame center from grade_H + 0.5L)

Llame length = 118 DDtack diameter in ft.

Figure a and Figure b

76Ground Flares

Only in those locations where elevated flares are not possible to be used due to paddygrowth or silkworm growing areas in the vicinity, the ground flaring may be resorted to.

In the case of the ground flaring area is to be confined with a refractory wall of 5mheight at a min distance of 10 m from the flaring pit. Also a green belt of min 50 mdistance from the pit should be development for containment of pollutants.

77Enclosed Ground Flare System

Several foreign companies have developed a totally enclosed ground flare system andwhich can flare the gases at low pressure with no traces of smoke. This system hasbeen developed jointly with British Petroleum and is successfully operating at BPfacilities. It consists of Fin Plate burners with modular bolted panel enclosure withrefractory lining as shown in Fig. 1 9.

The major advantages of this type of flare are —

•oncealed from view and hence no effect on nearly paddy or silkworm growth•mokeless combustion•o w N O x gen e r a tio n•ow heat radiat ion

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Fig. 19: Enclosed Ground Flare System



80ENVIRONMENTAL STANDARDS FOR OIL DRILLING AND GAS

EXTRACTION INDUSTRY (FINALIZED & MODIFIED)

8.1MINAS for Liquid Effluents

8.1.1 Off-shore Facilities

The oil content of the treated effluent without dilution shall not exceed 40 mg/I for 95%of the observations and shall never exceed 100 mg/I.

Three 8 -hourly grab samples are required to be collected daily, and the average valueof oil & grease content of the three samples should comply with the above prescribedstandards.

8.1.2 On-shore Facilities

Marine Disposal

Parameter LimitspH 5.5 — 9 .0

Oil & grease 10 mg/I

Total suspended100 mg/I

B OD 30 mg/I

In addition to above, proper marine outfall has to be provided to achieve the value asgiven below i.e. the individual pollutant concentration below toxicity limit within adistance of 50 m.

Table : Guidelines for the protection of marine aquatic life.

Parameter Level Reference

Chromium, as Cr 0.100 mg/I US Environmental Protection Agency, 440/9-76-023

Copper, as Cu 0.05 mg/I Environmental Studies Board, 1973, EPA. R3.

73.033

Cyanide, as CN 0.005 mg/I Us Environmental Protection Agency, 440/9-76-023

Fluoride, as F 1.5 mg/I Environmental Studies Board, 1973, EPA. R3.

73.033

Lead, as Pb 0.05 mg/I Environmental Studies Board, 1973, EPA. R3 .

73.033

Mercury, as Hg 0.10 mg/I Us Environmental Protection Agency, 440/9-76-023

Nickel, as Ni 0.1 mg/I Environmental Studies Board, 1973, EPA. R3 .

73.033

Zinc, as Zn 0.1 mg/I Environmental Studies Board, 1973, EPA. R3 .

73.033

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8.1.3 Standards for on-shore disposal and reinjection:

Re-injection (allowable only below a depth of 1000 m from GL)

Oil and gas drilling and processing facilities situated on land and away from saline watersink (sea etc.) may opt for disposal of treated produced water either by re-injection or byon-shore disposal.

The standards are prescribed as follows for on-shore disposal, re-injectionbelow 1000 m.

S.No. Parameter On-shoredischargestandards

Re-injection inabandoned well

1 . P H 5.5-92. Temprerature (deg. C) 4 03 . Suspended Solids (mg/I 1 0 0 1 0 04 . O il & Grease (mg/I 10 105. Phenolics (mg/I 1 .06. Cyanides (mg/I 0.27. Flourides (mg/I 1.5'8. Sulphides (mg/I 2.09. Chromium (Cr') (mg/I 0 .11 0 . Chromium (Total) (mg/I 1 .01 1 . Copper (mg/I 0.21 2. Lead (mg/I 0.11 3 . M er cur y (mg/I 0.011 4 . Nickel (mg/I 3.01 5. Zinc (mg/I 2.0

1 6. BO D (mg/I 301 7. CO D (mg/I 1 0 01 8. Chlorides (mg/I 6001 9 . Sus hates (mg/I 100020 . TDS (mg/I 210021 . % Sodium (mg/I60

Not specified

8.2 Solid Waste Disposal:

Guidelines notified earlier (1996) have been reviewed and notified under EPA. Thenotified guidelines are given below:

8.2.1 Disposal of Drill Cuttings & Drilling Fluids for On-shore Installations:

a)rill cuttings (DC) originating from on-shore or locations close to shore line andseparated from Water Base Mud (WBM ) should be properly washed and



unusable drilling fluids (DF) such as WBM, Oil Base Mud (OBM), Synthetic BaseMud (SBM)) should be disposed off in a well designed pit lined with imperviousliner located off-site or on-site. The disposal pit should be provided additionallywith leachate collection system.

Design aspects of the impervious waste disposal pit, capping of disposal pitshould be informed by the oil industry to SPCB at the time of obtaining consent.

b) Use of diesel base mud is prohibited. Only WBM should be used for on-shore oildril l ing operations.

c) In case of any problem due to geological formation for drilling, low toxicity OBMhaving aromatic content < 1 % should be used. If the operators intend to use suchOBM to mitigate specific hole problem/SBM it should be intimated toM oE F /S P C B.

d) The chemical additives used for the preparation of DF should have low toxicityi.e. 96 hr LC50 > 30,000 mg/I as per mysid toxicity or toxicity test conducted onlocally available sensitive Sea species. The chemicals used (mainly organicconstituents) should be biodegradable.

e) DC separated from OBM after washing should have oil content at < 10 gm/kg fordisposal into disposal pit.

f) The waste pit after it is filled up shall be covered with impervious liner, overwhich, a thick layer of native soil with proper top slope be provided.

g) Low toxicity OBM should be made available at installation during drillingoperation.

h) Drilling wastewater including DC wash water should be collected in the disposalpit, evaporated or treated and should comply with the notified standards for on-shore disposal.

i) Barite used in preparation of DF shall not contain Hg > 1 mg/kg & Cd > 3 mg/kg.j) Total material acquired for preparation of drill site must be restored after

completion of drilling operation leaving no waste material at site. SPCB should beinformed about the restoration work.

k) In case, environmentally acceptable methods for disposal of drill waste such as(i) Injection to a formation through casing annulus, if conditions allow, (b) landfarming at suitable location (c) bio-remediation, (d) incineration or (e )solidification can be considered, in that case oil industry is required to submitproposal to SPCB / MoEF for approval.



8.2.2 Disposal of Drill Cuttings & Drilling Fluids for Off-shore Installations:

a) Use of diesel base mud is prohibited. Only WBM is permitted for off-shoredrilling. If the operators intend to use low toxicity OBM or SBM to mitigate specifichole problems in the formation, it should be intimated to MoEF/SPCB. The lowtoxicity OB M should have arom atic content < 1 %.

b) The toxicity of chemical additives used in the DF (WBM or OBM or SBM) shouldbe biodegradable (mainly organic constituents) and should have toxicity of 96 hr

LC50 value > 30,000 mg/I as per mysid toxicity or toxicity test conducted onlocally available sensitive Sea species.

c) Hexavalent chromium compound should not be used in DF. Alternate chemical inplace of chrome lignosulfonate should be used in DF. In case, chrome compoundis used, the DF/ DC should not be disposed off-shore.

d) Bulk discharge of DF in off-shore is prohibited except in emergency situations.

e) WBM / OBM / SBM should be recycled to a maximum extent. Unusable portion ofOBM should not be discharged into Sea and shall be brought to on-shore fortreatment & disposal in an impervious waste disposal pit.

f) Thoroughly washed DC separated from WBM / SBM & unusable portion of WBM/SBM having toxicity of 96 hr LC50 > 30,000 mg/I shall be discharged off-shoreinto Sea intermittently at an average rate of 50 bbl/hr/well from a platform so asto have proper dilution & dispersion without any adverse impact on marineenvironment.

g) Drill cuttings of any composition should not be discharged in sensitive areasnotified by M oEF.

h) In case of specific hole problem, use of OBM will be restricted with zerodischarge of DC. Zero discharge would include re-injection of the DC into asuitable formation or to bring to shore for proper disposal. In such a case, use ofOBM for re-injection should be recorded and made available to the regulatoryagency. Such low toxic OBM having aromatic content < 1 % should be madeavailable at the installation.

i) In case, DC is associated with high oil content from hydrocarbon bearingformation, then disposal of DC should not have oil content > 10 gm/kg.

j) The DC wash water should be treated to conform limits notified under EPA,before disposal into Sea. The treated effluent should be monitored regularly.

k)ischarge of DC from the installation located within 5 km away from shore shouldensure that there is no adverse impact on marine eco-system and on the shore.

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If, adverse impact is observed, then the industry have to bring the DC on-shorefor disposal in an impervious waste disposal pit.

I )f any, environmental friendly technology emerges for substitution of DF anddisposal technology, it may be brought to the notice of MoEF and regulatoryagencies. If the operator desires to adopt such environment friendly technology apr io r appr o va l f r o m M o E F is r equir e d .

m ) Barite used in preparation of DF shall not contain Hg > 1 mg/kg & Cd > 3 mg/kg.

n ) Oil drilling operators are required to record daily discharge of DC & DF to off-shore and also to monitor daily the effluent quality, and submit the compliancereport once in every six months to MoEF.

83Gaseous Emissions:

8.3.1DG Sets :

i)tacks of all DG sets at drill-site should be as per guidelines already prepared byCentral Pollution Control Board, based on rating of D.G. sets in KVA, with am in imum height o f 9 m .

All the individual exhaust outlets may be connected to one or two manifoldleading to one or two stacks so that the exhaust is let off at a suitable heightcalculated to meet GLC prescribed by CPCB.

8.3.2 Elevated Flares:

i) Cold venting of gases should never be resorted to under any circumstances and

all gaseous emissions are to be flared.

ii) All flaring shall be done by elevated flares except where there is any effect oncrop production in adjoining areas due to glaring. In such cases, one shouldadopt ground flaring with scientifically designed burners to reduce luminousity,heat, smoke, etc, and also construct obstruction to make the flame obscure (asgiven under para 8.3.3).

iii) In case of elevated flaring the minimum stack height shall be 30 m. The flare tipshould be scientifically designed with steam/air injection etc. to reduce smoke.

iv) For flaring sour gas the minimum stack height should be decided as below:

(a )alculate stack height by using the formula

H=140 0.3

Where, H is the height of stack in m and

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Q is the kg/hr of SO 2 em itted.

(b) Using the above H calculate the maximum GLC of SO2 which should notexceed the CPCB limits.

(c) In case the maximum GLC exceeds, stack height is to be increased so as

to bring the GLC below the limits. However the minimum stack height shallnot be less than 30 m.

v) The maximum GLC caused by emission from various stacks shall be worked outand in no case the maximum resultant GLC should exceed the CPCB limits.

vi) At the drill sites where oil based muds are used, oil vapours should bechannelised and connected to elevated flares of minimum 30 m height.

8.3.3 Ground Flares:

i) Ground flaring of gases at surface flare pits to be adopted only as a last resort,ii) Following procedure is to be adopted to minimise effects of surface pit flaring.

The flare pit at GGS/OCS and GCS should be made of RCC surrounded by apermanent wall (made of refractory brick) of 5 m height minimum, to reduce theradiation and glaring effects in the adjoining areas.

Gas distribution system and planning of operation should be such that flaring isminimal .

i i i )nclosed ground flare system (as given underpara

7.7) should be adopted.

8.3.4General:

i) Ambient Air Quality around the drill site should be monitored at least once aweek for 3 months. In case the readings of various pollutants measured exceedthe limits, the frequency of monitoring shall be reviewed and furtherinvestigations should be carried out to find out the reasons and initiate mitigativemeasures.

ii) The drilling exploration production industry must submit detail report to thegovernment the efforts already made and planned for development ofinfrastructure and prospective customers for maximizing utilisation of associatedgas within a time frame which may be fixed by Ministry of Environment & Forest(Government of India) and / or Central or State Pollution Control Board.

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90MONITORING PROGRAM

With a view to ensuring adequate protection of the environment, monitoring of theemissions, both within the industry and outside are necessary.

Monitoring & control measures should be a continuing process, since certain effects of apollutant(s) in the environment could be adequately understood and evaluated only aftera long time. This would further help in taking appropriate measures for effecting therequired improvements in the existing control systems for adequate protection of theenvironm ent in future .

91Organizational Needs

For effective conduction of a monitoring and pollution evaluation program, it isnecessary to create a specialized cell within the organization. This cell may bedesignated as "Environment Protection Cell" and be composed of selected personneltrained in production technology, pollution control technology and monitoring ofpollutants. This cell should interact with the project authorities within the industry for thepurpose of proper planning and implementation of an integrated system of productionand pollution control. Cell should periodically review the pollution prevention measuresfor improvement in the quality of effluent, air and solid waste management to safe guardthe recipient system of environment. The cell should maintain all necessary datarelating pollution control system, monitoring data (air, water, solid waste) safety & healthetc. which can be produced at the time of inspection.

92Monitoring

Monitoring programme of the pollution control system as stated earlier, shouldnecessarily be a two-pronged activity and should cover the following :

1. Sources of Pollution Generation2. Po llution Co ntrol Facilit ies

93Monitoring of Waste Water

Monitoring of the sources of wastewater generation would help in preventing the lossesof valuable hydrocarbons and other materials and would provide for efficient operationof the plant. For the sources of wastewater generation, monitoring should cover the tankfarm (where crude is stored), appropriate sections of production as well as the storagearea. Leakages from these sources should particularly be monitored and corrective

measures be adopted so that the pollutants are prevented to a great extent fromreaching the treatment facilities.

9.3.1 Monitoring at Wastewater Treatment Plant (WWTP)

Since there is only a composite wastewater stream from OCS/GGS which ultimately ishandled in a wastewater treatment plant, it would be desirable to monitor the

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characteristics of wastewater at different stages of treatment. These stages should beidentified as :

i) P rim a r y o il sepa r a tio n un it.ii) Secondary oil separation unit.i i i )iological and p olishing unit .

Stage monitoring of wastewater at three different stages would help in keeping a checkover the operation of the units and also in taking measures to correct malfunctioning ofthe units, if any.

Since the treated wastewaters ultimately reach a water course or sea, monitoring ofthese receiving bodies should also be helpful.

9.3.2 Parameters and Frequency of Sampling

The important parameters of both the raw wastewater and the treated one should be asfollows:

i) pHii) Oiliii) Sulphideiv) Phenolv) BO Dvi) Suspended Solidsvii) Heavy metals etc.

These parameters should be measured everyday for the treated wastewater and everyalternate day for the wastewater treatment facilities.

9.4 Monitoring of Solid Waste and Ground Water

Similar to waste water monitoring the solid waste should be regularly monitored at thesolid waste generation stage and final disposal stage. Since the disposal is done bysecured landfill, after completion of its operation, local flora is to be grown on the pit topsoil and ground water monitoring around the disposal pit should be carried for theparameters such as :

i) Oilii) Aquatic toxicityi i i )eavy metals like chrom ium, i ro n e tc .

95Monitoring of Gaseous Pollutants

i)mbient air quality around the drill site and OCS/GGS should be monitored atleast once a week for 3 months. In case the readings of various pollutants

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measured exceed the limits, the frequency and duration of monitoring may bereviewed and further investigation should be carried out.

ii )he following parameters should be monitored as per the method of samplingand analysis given in IS : 5182

a) SPM

b) SO 2c) NO Xd) COe)CSummary

Effluent standards for pollutants present in treated waste water discharged from anyindustry are essential. In case of oil drilling and gas extraction industry the limits basedon quantum may not be feasible as the quantity of waste water generated goes onvarying over the years of exploitation of oil well. Initially the produced water content ofcrude oil produced may be 20% water and 80% crude and during the tag end of the well

it may be reversed to 80% water and 20% oil. Therefore the standards suggested arebased on

i) Guidelines for effluent discharge standards by BIS

ii ) Most practicable control technology available

i i i )nternational convention followed in the drilling industry.

The gaseous emission are generated from the flaring of associated gas being producedwith the oil. The standard methods for safe flaring of these emissions have been basedo n

1 . Guidelines for calculating suitable heights for stacks.

2. No man's Zone, calculation to determine safe area with respect to thermalradiation.

3 . Resulting ground level concentration to be limited to the prescribed limits underAir Pollut ion Act .

4 . Most practicable flaring technologies.

Similarly the disposal methods suggested for the solid waste generated due to dumpingof drill cuttings are based on

1 . The existing guidelines for solid waste disposal by Ministry of Environment andForests/ CPCB.

2. International procedures followed by the drilling industry.

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