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(1) All waste liquids, used during the drilling or workover of a well, or that have been produced from a well as it cleans up, shall be drained to a waste sump or otherwise disposed of in a manner approved by the Director.
(2) A waste sump referred to in Subsection (1) that is permanently maintained on any location shall be adequately fenced or otherwise protected.
(3) Every practicable precaution shall be taken to prevent pollution of the environment by a waste sump referred to in this section.
136. Disposal of Other Waste.
(1) All worn drilling equipment, damaged or surplus drilling supplies and other rubbish shall be removed from site to an approved waste disposal site and no drilling waste of any description is to be buried on site.
(2) All food scraps and kitchen waste are to be disposed of in an environmentally and hygienically acceptable manner.
(3) Effluent from the toilet facilities provided at the rig and camp is to be treated or discharged in an environmentally and hygienically acceptable manner.
137. Replacement of Well Site Fencing.
Where installed, the well site fencing protecting the wellhead from outside interference shall be replaced upon completion of a repair operation.
138. Penetration Rate.
Every drilling rig shall be equipped to provide continuous recording of the rate of penetration.
139. Detection of Petroleum.
(1) Suitable equipment shall be continuously available and/or installed on or near every drilling rig, prior to the drilling out of the surface casing, to permit the detection of hydrocarbons in cuttings, cores and mud.
(2) Equipment shall be readily available for adequate formation testing and sampling, both in open hole and through perforated casing.
Safety in Drilling and Workover Operations.
Operations carried out at or about a well site and the associated equipment shall be in general accordance with API RP 54.
141. Masts and Derricks.
(1) All masts and derricks exceeding 30m above ground level shall be equipped with a mast head light.
(2) No structural change or addition to a derrick or mast shall be made unless approved beforehand by the Director, who shall require a written submission from the manufacturer or a qualified professional engineer as to the effects of such structural change or addition.
A well shall not be spudded or a rig assisted well reentry shall not start until the rig and its associated equipment are completely rigged up and reliable communications have been established as required in Section 21.
143. Blowout Prevention.
(1) The site person-in-charge of a well that is being drilled, tested, completed or worked over shall, at all times, employ adequately designed blowout prevention equipment.
(2) Prior to drilling below the surface casing string, or before re-entering a completed well, hydraulically operated blowout prevention equipment shall be installed, operated and tested, generally in accordance with the relevant requirement of API RP 53, “Recommended Practices for Blowout Prevention Equipment System for Drilling Wells”, and shall be maintained ready for use subject to Section 147 until abandonment, completion or recompletion operations have been completed.
(3) The blowout prevention equipment referred to in Subsection (2) shall comprise a minimum of–
(a) three remotely controlled hydraulically actuated blowout preventers each with a working pressure which exceeds the maximum anticipated surface pressure and which preventers consist of–
(i) one set of pipe rams appropriate for the size of pipe being run in the hole; and
(ii) one set of blind rams; and
(iii) one annular preventer; and
(iv) extension hand wheels or hydraulic locks on all ram type preventers; and
(b) a drilling spool with side outlets for the attachment of choke and kill lines, or side outlets in the blowout preventer body, for choke and kill lines, which side outlets shall be connected to pipe lines which have a pressure rating not less than the blowout preventer assembly to which they are connected, except that part of the choke line which is down stream of the last valve on the choke manifold; and
(c) one kill pump facility connected to the kill line; and
(d) one fill up line.
(4) Where the pressure rating of the blowout preventers is–
(a) less than 2000 PSI, both the choke and kill lines shall contain related fittings of a minimum diameter of 2 inches and shall be equipped with at least one control valve; or
(b) greater than 2000 PSI, the choke line shall contain related fittings of a minimum diameter of 3 inches, and both kill and choke line outlets on the blowout preventer stack shall be equipped with two control valves, one of which on the choke line shall be hydraulically controlled.
(5) Where the Director has approved the setting of deep surface casing, he may require the installation of an adequate diverter system to the conductor in accordance with API RP 53.
(6) All valves, fittings and lines between the closing unit and the blowout prevention stack shall be of steel construction.
(7) Approved fire resistant hose with a rated working pressure at least equal to the working pressure rating of the stack may be used on equipment rated at 5000 PSI or less.
(8) Where manual controls for blowout preventers are provided they shall be located outside the rig substructure at a maximum practicable distance from the well-head.
(9) An inside blowout preventer assembly and a full opening safety valve in the open position, with crossovers as needed to fit all tool joints in the drill or tubing string, shall be maintained on the rig floor while drilling or work-over operations are being conducted.
(10) An upper kelly cock shall be installed below the swivel and, where high pressures are anticipated, another at the bottom of the kelly of such design that it can be run through the blowout preventers.
(11) Choke and kill lines of flange, weld or clamp connected steel or approved fire resistant hose shall be fitted and equipped generally in accordance with API RP 53 and apart from the choke there shall be no reduction in diameter from the primary choke line to the flare.
(12) The choke manifold shall be fitted with not less than two adjustable chokes and it is recommended that a hydraulically controlled choke be fitted as one such choke, where the pressure rating of the blowout preventer equipment exceeds 3000 PSI.
(13) Each choke manifold shall have the following equipment clearly visible to the choke operator when standing in his normal operating position for either of the adjustable chokes–
(a) a pressure gauge which indicates the drill pipe pressure at the drilling floor; and
(b) a pressure gauge which indicates the casing/drill pipe annulus pressure at a known point upstream of the choke.
(14) The choke manifold shall be sited away from the rig substructure so that the choke and flare lines contain a minimum number of bends and, so far as is practicable, the driller has a clear view of a person operating chokes and monitoring pressures.
(15) An adequately constrained flare line shall extend at least 50m from the well, oil storage tank, separator, temporary production facility or other unprotected source of flammable vapors.
144. Blowout Equipment Certification.
All drilling contractors shall have their blowout preventer stacks inspected by a qualified inspection organization or tested and certified by a qualified facility that is authorized by the manufacturer and such inspections or certifications shall be performed according to the manufacturer’s recommended procedure and schedule, but not less than once every five years.
145. Blowout Preventer Closing Units.
(1) Blowout preventer activating accumulator units generally in accordance with the requirements of API RP 53, shall be located a minimum of 20m from the wellhead and, without accumulator pump assistance, shall have sufficient capacity to–
(a) open or close the hydraulically operated choke line valve; and
(b) close or open the annular type blowout preventer; and
(c) close or open all blowout preventer pipe rams.
(2) After the functions specified in Subsection (1) have been carried out, the accumulator pump shall be capable of rebuilding fluid pressure in the accumulator within a period of three minutes to a sufficiently high level to–
(a) open the hydraulically operated choke line valve; and
(b) close the annular type blowout preventer.
(3) Accumulators shall be connected to the blowout preventers with lines of safe working pressure at least equal to the working pressure of the accumulator, and where these lines are located adjacent to and within the substructure they shall be of steel construction unless completely sheathed with adequate fire resistant material, installed and maintained to the manufacturer’s specifications.
(4) Accumulator pumps shall have two independent sources of power which shall not be connected to the same circuit.
(5) During drilling and work-over operations there shall be a control manifold for operating the blowout preventers accessible to the driller on the rig floor and another located at least 20m from the well, so that where the rig floor controls are rendered inoperable the distant master control unit shall be able to operate all blowout preventer functions.
146. Testing Blowout Prevention Equipment.
(1) The blowout prevention equipment shall be tested in the manner and at the times set out in Subsections (2), (3), (4), (5) and (6) in the event that a test indicates that the equipment is not operating correctly, the equipment shall be made serviceable before operations are recommenced.
(2) The ram type preventers, the annular preventer, the choke and kill lines and valves, the choke manifold and the kelly cock shall be pressure tested on installation and following the setting of each string of casing in the wellhead, prior to drilling out or commencing completion operations or at any time any part of the BOP stack has been altered in any way that compromises the pressure integrity results of the preceding test.
(3) A test under Subsection (2) is to be conducted using water and to pressure consistent with the rating of the equipment, the recommendations of the manufacturer and the casing installed in the well, and the results of any such test shall be reported in the daily report and entered on the tour report.
(4) Under normal operating conditions, at least once every two weeks, the blowout preventers and choke manifold shall be pressure tested and the results shall be recorded in the daily report and on the tour report.
(5) Where well conditions preclude the safe testing of the BOP stack and manifold, the pressure test may be postponed until normal operating conditions are regained, at which time the test shall be immediately carried out and the reasons for the postponement shall be entered into the daily report and the tour report on the day the test was originally due.
(6) The blowout preventers are to be inspected or checked on a daily basis and the rams operated as required to ensure functional competence and such function tests shall be recorded in the daily report and the tour report.
(7) Every closing of the blowout preventer system and the reasons for the closing shall be included in the daily report and the tour report.
147. Installation and Removal of Blowout Prevention Equipment.
During the period of operations when blowout prevention equipment is installed and maintained it shall not be removed until proper plans to safely seal the wellbore, approved by the Director, have been carried out.
148. Well Control Records.
(1) All on-site supervisors and rig personnel holding the position of driller or above, shall maintain valid well control certification.
(2) A certificate issued under Subsection (1) is to be produced when so requested by the Director or a Petroleum Inspector.
(3) Blowout prevention drills shall be conducted weekly for each crew to ensure that crews are properly trained to carry out emergency procedures and the response times shall be recorded in the tour reports and the daily drilling report.
(4) Proper trip sheet records shall be maintained until rig release date of the well, and shall be produced when requested by the Director or a Petroleum Inspector.
(5) Detailed well control procedures shall be displayed at the location.
(6) A well kill work sheet shall be maintained current with respect to the drilling conditions.
149. Drilling Fluid Facilities.
(1) Drilling fluid facilities, materials and procedures shall be established and maintained to minimize the potential of a blowout on any well.
(2) The drilling fluid facilities system shall include–
(a) recording and alarmed mud pit/tank level indicators; and
(b) an appropriate sized trip tank; and
(c) a mud return or full hole indicator; and
(d) pump stroke counters; and
(e) mud degasser.
(3) When pulling drill pipe or tubing from an uncased or perforated well, the annulus shall be filled with a fluid of appropriate density before the change in the fluid level decreases the hydrostatic pressure by 75 PSI, or every five stands of tubular, whichever gives the lower decrease in hydrostatic pressure.
150. Well Testing.
(1) Any formation test in which formation fluids are produced into the test string shall have–
(a) provision to avoid pulling the test string full of produced fluids; and
(b) provisions to kill the well in case of an emergency; and
(c) any other provision as may be prescribed by the Director.
(2) During formation testing, or the removal of pipe after a formation test, a competent supervisor shall remain at the rig site to supervise the operations.
(3) During formation testing flow periods, motors engines and lights not required in the operation shall be shut off and water sprays, fitted to the exhausts of the engines that are required to be run, shall be turned on during all flow periods.
(4) During formation testing flow periods, no motor vehicle shall be operated with 25m of the well bore.
(5) During formation testing, the testing string annulus shall contain sufficient fluid of a density adequate to control formation pressure.
(6) Produced fluids at surface shall be safely routed through an appropriate independent test manifold and choke facility.
(7) Blowout prevention equipment shall not be used for flow control during a formation test.
(8) The site person-in-charge during an open hole formation test shall–
(a) make every endeavour to estimate the rates of flow of oil and/or gas and/or water produced; and
(b) ensure that the volumes of liquids contained in the dill pipes at the conclusion of a test are measured; and
(c) ensure that samples are taken of all fluids produced or recovered from the drill pipe.
(9) Unless otherwise approved by the Director, all formation flowing tests shall utilize appropriate equipment located to accurately measure both flowing and shut in pressures and temperatures of the formation being tested.
(10) During a production test, the fluid flow shall be diverted through an adequate separator and the resultant flows of oil, gas and water shall be measured.
(1) While swabbing operations are being conducted, all engines, motors, and other possible sources of ignition, not essential to the operation, shall be shut down.
(2) During swabbing operations the fluids shall be routed through a closed flow system to a production facility or tank located not less than 25m from the well bore and any flare/vent line from the tank shall incorporate a flame arrester.
(3) Swabbing operations shall not be conducted during the hours of darkness.
152. Equipment and Procedures.
Equipment used on a rig, whether permanently attached or temporarily installed, and all working procedures shall be designed such that the safety of personnel, equipment, resources and the environment is assured.
Rig and Associated Equipment.
153. Drilling and Workover Rigs–General.
(1) Where practical, three exits from the floor of a rig shall be provided.
(2) All work areas and walkways that are elevated by more than 1.8m, and stairs, shall be provided with secure and safely designed handrails or other appropriate safety facilities and shall comply with PNGS 1081 “Code for Fixed Platforms, Walkways, Stairways and Ladders”.
(3) Unless otherwise approved by the Director, the substructure of a rig shall not be enclosed.
154. Derrick and Mast Platforms.
Every derrick and mast shall have a safely designed, secured and adequately sized landing platform level with each principal working platform of the derrick.
155. Ladders and Stairways.
Ladders and stairways shall comply with PNGS 1081 “Code for Fixed Platforms, Walkways, Stairways and Ladders”.
156. Hoisting Lines.
(1) A wire-line service record shall be kept on all drilling and workover rigs and shall be in accordance with the provisions of API RP9B or such other form as may be acceptable to the Director and shall be produced to a Petroleum Inspector when required.
(2) All hoisting lines and hoisting line equipment shall be designed, operated and maintained in safe and serviceable condition.
(3) All overhead sheaves or pulleys shall be securely fastened to their support.
(4) All hooks used in single point hoisting shall be equipped with a device to prevent the accidental release of the load.
157. Pressure Lines and Hoses.
All fluid system pressure hoses, high pressure pneumatic flexible lines, high pressure pipe used in fluid pumping systems including those fitted with flexible joints shall be equipped with restraint devices of sufficient strength, secured to an adequate support, to effectively prevent dangerous movement in the case of coupling or near coupling failures.
158. Safety Valves and Pumps.
(1) A pressure relief device shall be installed on all power driven high pressure fluid pumps and there shall be no valve between the pump and the pressure relief device.
(2) The pressure relief device shall be set to discharge at a pressure not in excess of the manufacturer’s recommended maximum working pressure of the pump and all connecting pipes and fittings.
(3) Shear pins used in pressure relief devices shall be of a design and strength specified by the manufacturer.
(4) A guard shall be placed around the shear pin and spindle of a pressure relief device.
(5) The fluids discharged from a pressure-relieving safety device shall be directed to a place where they will not endanger any person.
(6) There shall be no valve of any kind in the discharge opening of a pressure-relieving safety device or in the discharge pipe connected to it.
(7) The pipe connected to the pressure side and discharge side of a pressure-relieving safety device shall not be smaller than that of the normal pipe size openings of the pressure-relieving safety device.
(8) The piping on the discharge side of a pressure-relieving safety device shall be secured.
(1) Certain minimal distances specified in Part VII may be impractical on a marine facility, but the Person-in-Charge shall ensure that the intent of the provisions of Part VII is observed.
(2) A provision in respect of casing, blow-out preventers, blow-out preventer closing units, and abandonment in Part VII shall apply with equal force to operations both onshore and offshore
160. Mobile Drilling Unit.
(1) Any mobile offshore drilling unit shall be in possession of a current MODU certification and a current certification of seaworthiness from a recognized and authorized classifying authority such as the American Bureau of Shipping.
(2) In the case of the first well to be drilled or worked over by a unit offshore Papua New Guinea, the mobile offshore drilling unit and associated equipment shall be inspected by a qualified inspection company, approved by the Director, and the subsequent inspection report shall be forwarded to the Chief Inspector for review.
(3) Any deficiencies in the equipment, as highlighted by this inspection report, under Subsection (2) shall be remedied prior to spud or start of operations on the well and the rig and associated equipment shall then be re-inspected and approved by a Petroleum Inspector appointed under the Act, prior to the commencement of drilling.
161. Offshore Drilling Program.
An offshore drilling proposal shall address the following items (drilling unit applicable) prior to or in conjunction with the details as stated in Section 104:–
(a) anchoring of the drilling unit;
(b) shallow gas drilling procedures for conductor and surface holes; and
(c) site pull off plans during drilling and/or completion operations in case of emergency;
(d) site repositioning and well reconnect;
(e) disposal of drilling fluid and drill cuttings;
(f) initial site survey and seafloor evaluation for bottom supported drilling units;
(g) details for the containment of hydrocarbon spills into the sea, complete with a copy of the financial responsibility;
(h) details of the chemicals to be used in the drilling fluid, copies of the MSDS sheets and the treatment procedure for rendering the drilling fluids harmless prior to disposal to the sea;
(i) details of safety facilities contracted for offshore personnel safety.
162. Offshore Casing Design.
(1) For drilling operations carried out from a mobile offshore drilling unit, except for the conductor hole, all casing or subsea equipment shall be designed to return drilling fluids to the drilling unit and such design shall take into account all lateral loads that may be exerted on the casing or riser system.
(2) For the design of casing strings used in offshore wells, the design shall be governed by Section 121.
163. Offshore Blowout Preventers.
(1) Prior to drilling below the surface casing string, blowout prevention equipment as generally recommended in API RP 53, shall be installed and tested.
(2) The blow-out preventer assembly shall include at least one blind/shear ram and one annular type.
(3) A sub-sea blowout preventer shall be provided with duplicate sets of control lines, designed to allow for sub-sea disconnect at the stack.
164. Offshore Blowout Preventer Closing Units.
In the case of a well drilled from a mobile drilling unit (other than a jack-up platform), the accumulator unit shall be capable of opening the riser connector in addition to the requirements specified in Section 145.
165. Disposal of Drilling Fluids Offshore.
Offshore disposal of water based drilling fluids and cuttings into the sea shall be in accordance with the prevailing laws of Papua New Guinea, and drilling fluids and cuttings containing oil or other hydrocarbons shall meet the requirements of Section 190.
166. Abandonment of Offshore Wells and Platforms.
All casing strings and pilings from offshore wells or platforms being permanently abandoned shall be severed at least 5m below the seabed and removed, and the sea floor surrounding the well location, to an area extent as determined by the Director, shall be surveyed to determine debris and obstructions and cleared as directed.
The provisions of this Division shall apply whenever air is used as a circulating fluid in rotary drilling operations in the search for and production of petroleum and where there is any conflict between any of the provisions of this Division and of any other provision of this Regulation, the provisions of this Division shall prevail.
168. Delivery Lines.
(1) The main air supply line shall be located so that it does not interfere with pedestrian or vehicular movement.
(2) A check valve shall be installed on the delivery line at or near the standpipe.
(3) All high pressure air lines on the drilling location shall be suitably marked or posted with warning notices and a supervisor shall ensure that all workmen working under his supervision are aware of the method of marking of the high pressure lines.
(4) All main valves in the supply system that may require quick closure in the event of an emergency shall be clearly labeled and shall be readily accessible.
169. Motor Vehicles.
Every vehicle that is not directly engaged in operations on the well shall not approach within a distance of 50m from the well.
170. Fire Precautions.
(1) Adequate fire extinguishing equipment, properly positioned at or under the substructure, safely and effectively to fight a fire or at least one mud gun shall Adequate fire extinguishing equipment, properly positioned at or be permanently mounted under the substructure pointing directly at the rotating blowout preventer assembly, and the line between the mud pump and that mud gun shall be controlled by a single valve situated at the pump end of the line.
(2) Where the mud pump referred to in Subsection (1) is not kept in continuous operation, pump starting controls shall be located at the pump and at the driller’s control panel.
171. Siting of Compressors.
(1) Where practical, compressors and boosters used for drilling shall be sited at least 25m away from the rig and the gas separator, and shall be placed so as to be visible from the driller’s position.
(2) Oil and diesel fuel storage shall be sited at least 25m away from the compressors.
172. Blooey Line.
(1) Blooey and bleed-off lines shall extend at least 50m from the wellhead and shall, where practical, be laid downwind of the well or at a right angle to the direction of the prevailing wind.
(2) A geological sample catcher installed on a blooey line shall be designed to avoid flashback and to provide protection to personnel from dust.
(3) Sufficient space shall be cleared around the end of the blooey line to prevent ignition of vegetation.
(4) Where dust discharged by drilling causes a hazard to health on the drilling location, provision shall be made to inject water into the blooey line to suppress such dust.
(5) Any gas discharged from the blooey line shall be immediately ignited by a reliable, safe and continuous method acceptable to a Petroleum Inspector.
173. Supply Line Valves.
At least two valves shall be installed in the main air supply line, of which one shall be on the standpipe accessible from the derrick floor and one shall be at a distance of at least 25m from the well.
174. Drill string Fittings.
A downhole float valve shall be installed in the drill string and both top and bottom kelly cocks shall be employed in a manner similar to that provided for in Section 143(9) and (10).
175. Mud Stocks.
Drilling fluid, readily available and in adequate volume to fill and circulate the hole, shall be maintained on location in satisfactory condition at all times.
176. Gas Detection Equipment.
Sufficient gas detection equipment, of a type and number acceptable to a Petroleum Inspector, shall be provided and used at all drilling locations when air drilling is in progress.
Special services are those usually provided by a contractor other than the drilling contractor and shall comprise all logging, formation testing, formation stimulation, cementing and other services of a like nature that are carried out in support of the drilling, completion, abandonment, suspension and workover of a well.
(1) Special services shall be conducted in accordance with this Regulation and the applicable recommended practices set forth in API RP 54 “Oil and Gas Well Drilling and Servicing Operations”.
(2) All safety and operating requirements contained in this Regulation are applicable.
179. Stimulation Operations.
In any stimulation operation in which high pressure pumping equipment is used–
(a) all equipment shall be pressure tested to a pressure greater than the maximum anticipated treating pressure; and
(b) where crude oil is to be used in such operations, it shall be weathered in a facility for a sufficient period to ensure that the more volatile components have escaped before the crude is so used and, for any operation using petroleum based products, sufficient fire protection shall be available on site to contain any fire and provide personnel protection; and
(c) pump vehicles and other pumping equipment shall be located at least 25m from the well, whenever possible, and shall be stationed in such a position as to provide the persons operating such vehicles with a clear view of the wellhead; and
(d) injection lines or manifolds shall not be laid beneath vehicles or pumping equipment; and
(e) all unnecessary electrical equipment shall be shut down during a stimulation operation that uses petroleum based fluids; and
(f) only persons, vehicles and equipment necessary for the operation shall be permitted within 50m of the well; and
(g) in any acidization, an adequate source of fresh water shall be available for personnel safety purposes; and
(h) before pumping flammable liquids, all components of the system shall be grounded.
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