History and Discovery of the Piper Oil Field

5106 words (20 pages) Essay in Geography

23/09/19 Geography Reference this

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The Piper oil field was found on December 22, 1972 and Piper alpha platform was tremendous, settled structure stage located around 120 miles north east of Scotland in 474 feet of water, it was one of the greatest as well as productive mechanical assemblies on the planet. At first, it was an oil rig but later changed over to gas producing platform. It begins collected oil and gas from the Piper, Claymore and Tartan fields, confining these into surges of oil, condensate and gas. Woodwind player alpha, at the time gave around 10 percent of oil creation from the U.K region of the North Sea. It is asserted by Occidental Petroleum, started creation in 1976 from the Piper oilfield, which was controlled by the Occidental Petroleum Caledonia joint undertaking. It was at first created as an oil age arrange and was later changed over to energize gas creation with another gas recover module included. The Piper field conveyed oil from 36 wells. By 1988 the platform was making 10 percent of the North Sea’s oil and gas. Together with Tartan and Claymore Stages, Piper Alpha was related by a 128-mile pipeline to the oil terminal in the Orkneys. The platform was around 900 ft high and was disconnected in arrangement, containing four key working areas. The working zones were disengaged by firewalls and the stage was equipped with both diesel and electric seawater guides to supply water to its modified firefighting framework. The platform had a capacity to suit more than 200 people, and highlighted a helideck, which is around 175 ft of range from the water. (Ellul, 2014)

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The well 15/17 was the third very much bored by the Occidental, Getty International. A past penetrating endeavor, close to the disclosure well area, was surrendered at around the feet of about 1490. Seven evaluation wells were penetrated inside the breaking extremity of the Piper field. The whole result was rely on the demonstrated through the flautist field comprised of three tilted, collapsed, blame squares of Maher 1979. A flat oil/water contact was started for the premier Piper oil field at 8500ft subsea which was found by 15/17-7. The net isochore thickness of the store ranges from 90 ft to 330 ft. with the depth of 190ft. Other oil field information incorporated with the porosity of 25%, normal penetrability censures and the water immersion with 5 percent. Extreme blame intricacy was indicated at by the first seismic information and affirmed by boring, anyway the strike of these deficiencies was not comprehended until the aggregation of a lot of generation information. So also the early boring demonstrated the presence of few units of moderately low penetrability, anyway the potential impact of these units on generation and vertical liquid stream was not surely knew and by large misjudged. The future player supply was cored in the last four examination wells anyway results were constrained by the friable idea of the sands. Maybe the most noteworthy topographical component built up by the examination penetrating was the presence all through the field of phenomenal cor-connection markers. The way that units as thin as a barely any feet held on over the 7500 section of land zone of the piper field was in itself was in itself was in itself a ground-breaking piece of information to the idea of sand affidavit and it was simply because of our firm certainty with these connections that we could distinguish and follow up on later challenge related with water. (Webe, 1980)

Moreover, Alpha was actually designed to provide and export oil. The requirement to export the gas with the associated separation of condensation was associate indulged substantial alteration. The retrofitting went ahead in few phases, beginning with separation of condensation and ending with production of export- quality gas. The new facilities were settled alongside the control room, under the electric power, radio area and accommodation modules, so when the disaster struck, it did as such with appalling impact on whatever remains of piper alpha. Everything was running smooth and well functioned but one day unfortunately catastrophe occurred on 06 July 1988, a series of explosion ripped through the Piper alpha Platform in the North Sea in which

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167 men killed and many more were injured as well traumatized. The world’s biggest offshore oil disaster affected 10 percent of United Kingdom oil production and led to financial losses of an estimated $5 billion. The root of these explosions was discovered after the disaster that the safety feature was diluted when the gas compression units were installed next to the control room. Further danger arose when occidental decided to keep the platform producing oil and gas as it set about series of construction, maintenance and upgrade works. (Binder Singh, 2009)

                             DESCRIPTION OF RESERVIOR

The production unit are very thin in the 7500-acre (30sq km) area of the Piper field, was a powerful clue to the nature of sand deposition. Seven appraisal wells were dig within the limit of piper field. (Fig. 1). The results of these well drilled above shows that the piper field consisted of three tilted, folded, fault blocks (Fig. 1) A horizontal oil/water contact was established for the main piper field at -8510 ft. (-2594m) subsea (a small, structurally controlled oil accumulation with an oil/water contact at -9200 ft. (-2804m) subsea was discovered by 15/17-7). The net isochore thickness of the reservoir ranges from 98 ft. (30m) to 332 ft.(101m) with an average of 192 ft. (59m). average porosity for piper field is 24%, average permeability 4 decries, average water saturation 5%. Severe fault complexity was hinted at by the original seismic data and confirmed by drilling (Maher, 1979).

                               Figure 1-Description of Reservoir

From: Piper Field: Improved Reservoir Characterisation. Society of Petroleum Engineers.by Little, E. A., Simlote, V. N., & Bedrock, M. (1993, January 1).


The field comprises of three titled fault blocks. The reservoir in the Piper Field comprises Upper Jurassic sandstones of the Humber Group (Figure 2). The Sgiath Formation rests unconformably on the Middle Jurassic Pentland Formation and is composed of interbedded sands, silts and coals deposited in a paralic environment. Sgiath deposition gradually infilled local topography through a series of distributary channels and mouth-bars building out into a restricted marine environment. Overlying the Sgiath Formation is the Piper Formation which is interpreted by (Boote and Gustav) as having been deposited in a high energy, wave dominated delta system deposition on the periodic basis in the delta result in propagation of shales. The piper field formation consists of ten major subdivisions of stacked sands, each about 20-80 ft in thickness, with some sands capped by thin, and sometimes laterally extensive, shales (Figure 2). The sands mainly comprise coarsening-upward sequences and are dominantly of fine own to fine upper sand grain size. They are largely friable and poorly cemented by small amounts of calcite and silica cement. (E. A., Simlote, V. N., & Bedrock, M. 1993, January 1).

                                                                                   Figure 2- Piper Field stratigraphy and facies

From: Piper Field: Improved Reservoir Characterisation. Society of Petroleum Engineers.by Little, E. A., Simlote, V. N., & Bedrock, M. (1993, January 1).


Utilisation of the probe permeameter along with the reanalysis of the Piper Alpha data enhanced the reservoir description. The development of the new facies model has helped us in better understanding of the layer characteristics in the Piper Field. Fluid redistribution has taken place to varying degrees in different sands in different parts of the field. The extent to which the sands at Piper act as individual layers. It became apparent after the water breakthrough in P9 that the piper Reservoir was behaving as a layered reservoir. Isopach maps of the individual units were then prepared using both field well control and regional data; these were added to the Top Piper Sand Structure map to provide structure maps on the top of each reservoir unit. Graphs of the net reservoir volume as a function of depth were constructed using these maps, the known oil/water contacts and relevant net to gross ratio maps. The entire project was done manually. Fault throws at piper range from 600 ft. (183m) to a few feet; in permeability terms, from total impermeability to no significant effect. Seismic data helps us in mapping top of the piper field but with beneath the ground with less accuracy. Seismic resolution is limited to a few tens of feet, so that many of the unit contacts across fault planes must be inferred. For this purpose, the flowmeter log is extremely valuable. The relationships across the ‘D’ fault, the most extensively studied fault in the Piper field.  The most striking feature of this cross section is the thickening of units F and J across the fault indicating fault movement during sand deposition. The offsets at the top and base piper Sand are based on seismic data. The juxta position of the units across the fault is based on the thickness of the units at the nearby wells, dip meter logs, flowmeter results and production data. The following series of inferences are made:

The J sand, which is normally a poor producer in Block IA due to poor pressure support, produces very well in p12 (30% of the total well flow). Also, more oil has been produced from this unit at P12 than can be accounted for in the volumetric study in Block IA. It is obvious that the J sand in the P12 area is being supported by a highly permeable unit across the D fault. The inference is that the 10 Darcy F sand is providing the pressure support. This fits the structural data precisely. The upper units (C and D) on the downthrown side of the fault block have exhibited a greater oil/water contact movement than indicated by the production and volumetric in Block lB. Conversely the F unit in Block IA has produced significantly more oil than anticipated based on the volumetric and oil/water movement. The inference is that the F unit in Block IA is juxtaposed against the C and D units in Block lB. The calculation of the oil/water contact rise based on volumetric and production data for unit J in Block IB matches the observed performance. The inference is that the J unit on the downthrown side of the D fault is juxtaposed against impermeable Triassic rocks on the upthrown side and no fluid movement is occurring across the fault Wiebe, M. (1980, January 1).



Permeability in the Piper Field commonly exceeds 3000 Md and is largely controlled by grain size and sorting which are undetectable by conventional wireline logs. The permeability in the piper field is too high and due the marked permeability there is water override because of which there is uneven sweep in the field. As a result, one single transform could not be used for the Piper and Sgiath Formations. Instead two transforms were determined for low porosities and high porosities for most of the sand units. The transform works well for most of the Piper/Sgiath sands. Shales of the Kimmeridge Clay provide vertical and lateral seals over much of the field Horizontal permeability is derived from well log properties. Due to heterogeneity normal to the dip plane, the choice of vertical permeability for use in the model is less straightforward. ore measurements suggest that the vertical to horizontal permeability ratio is 3:4. very few genuinely impermeable barriers exist at Piper. Because the reservoir permeabilities range from 1 to 10 Darcie’s, the term “barrier” is used for the purposes of this paper for units of less than about 500 millidarcies. Strictly, a “barrier” at piper is a unit which inhibits the gravity segregation of the reservoir fluids under local producing conditions.

The main factors affecting reservoir performance are: (a) the presence of little’ll continuous reservoir layers which have high and contrasting horizontal permeability, strong variation of vertical permeability between them, and differing strength of natural water influx, and (b) the presence of faults which juxtapose these dissimilar layers.(Dunlop, K. N. B., De Boer, E. T., & Waldren, D. 1982, January 1).


  1. Faulting, causing contact between sands of contrasting permeability, is a major reason for some early conformance problems on Piper field, though it also redistributes the uneven natural aquifer support amongst the producing units.
  2. A simulation tool has been created which permits assessment of the effect of faults on field behaviour, whilst reducing the cost and complexity of interpretation by preserving a convenient correspondence of the model layers with the geological layering.
  3. A complex North Sea field requires close and continuous co-operation between a team of engineers and production geologists to explain observed well effects.
  4. The detailed geological model of the field has been validated because results consistent with those observed are obtained when it is integrated with the petrophysical, production and recorded pressure data. (Dunlop, K. N. B., De Boer, E. T., & Waldren, D. 1982)

                               DESCRIPTION OF RESERVIOR FLUID

The reservoir fluid in piper alpha, which is the largest oil platform consist of a mixture of crude oil, gas, water and sand. The reservoir fluid is brought to the surface by pumping a proportion of the 34 wells which connected the reservoir to the platform. Initially the contents of the reservoir fluid were kept in liquid state due to the intense pressure developed, but by the time they reach the surface during the extraction they changes into gas and fluid. The extracted material is then further transferred into a separator which separates the gas and produced water from the crude oil. The produced water from the separator is pumped to the water treatment plant.

The properties of the reservoir fluid involve porosity, oil gravity and many more. The percentage of the pore space in the rock for the reservoir fluid is 24. The ratio of water volume to the pore volume which is known as the water saturation for the reservoir is 17 percent. Usually the water saturation is calculated from effective porosity and the resistivity log (Crain’s January 1 2015). The value used to compare the volume of oil at reservoir conditions to the volume of oil at surface which is known as the oil formation volume factor for the reservoir is 1.264. The value of oil formation volume factor is generally between 1and 2 RB/STB. Oil in place, also known as the stock tank oil initially in place for the reservoir is 1223 STB/acre-ft.it refers to the oil in place before the start of the production. This quantity cannot be measured directly, it is usually estimated from other previously determined parameters before drilling. Meanwhile the solution gas oil ratio which is the amount of gas dissolved in the oil is 446SCF/STB. Usually the solution GOR of the black oil systems ranges from 0 to approximately 2000 SCF/STB (McCain WD Jr. 2003). Oil gravity of the reservoir is 36 degrees API. That means the oil is lighter than water and it floats on water. Usually the oil having oil gravity less than 10 sinks in water because it is heavier than water.

The piper field lies in 45ft of water and 120 miles northeast of Aberdeen. The original reserve of the plant is 1 billion BBL of oil and 120bcf of gas. Through a 30inch pipeline the oil moves 21 miles and join the Flotta pipeline located in the north of the claymore platform. On the other hand, the gas travel almost 1 mile through a 16inch pipeline to reach claymore platform for transport to St Fergus, Scotland terminal.

Table 1- Piper field average reservoir properties

Porosity percent


Water saturation percent


Initial oil formation volume factor, RB/STB


Oil originally in place, STB/acre-ft


Average core permeability


Original solution gas oil ratio, SCF/STB


Oil gravity, degrees API


Initial datum, pressure, Psig


Datum temperature, degree Fahrenheit


From “The Piper Field – Development Plan For Rapid Field Evaluation. Society of Petroleum Engineers”. Pinson, A. E., & Daniel, E. L. (1975, January 1)


Drilling at the Piper field started in late 1970s with two rigs and its platform has 36 slot cellar arrangement. This arrangement was setup in three rows of 12 slots. In June 1975, Piper field platform was installed. Production well P1(Figure 1) was drilled on October 10, 1976 and put on production on December 7, 1976. P2 was the real challenge as the borehole drifted 40 degrees (King. P.A, 1980, p19).

 After drilling and completing 23 wells, one of the rigs was decommissioned. So, only one rig was used for rest of the drilling. Though no significant problem was experienced while drilling wells. The major change made in drilling procedure was made only to improve the open hole log quality. As hole angles and reaches increased, it became clear that logging was becoming very hard and the data quality started to decline (King. P.A, 1980, p20). The drilling programme was modified as under:

      12 ¼” hole drilled to the top of the sand and following a BHA change the well drilled to total depth in 8 ½” hole.

      On reaching total depth, sand quality was checked using  one logging run and then the 9 5/8” casing set, the 3 ½” hole cleaned out, any further drilling was completed, and the rest of the log and sampling was done.

      7-inch liner run and cemented (King. P.A, 1980, p20).

The wells were given s-profile with a reduced angle before entering the reservoir. This S-profile aided in logging and better log quality and easier wireline work (King. P.A, 1980, p20).

Table 2 (Number and Types of Wells)

Type of wells

Number of Wells

Oil Producers


Water Injectors


Gas Injectors


Total Wells


From “The Piper Field – Development Plan For Rapid Field Evaluation Society Of Petroleum Engineers” By Pinson, A. E., & Daniel, E. L (Jan 1, 1975).

Figure 3 (Piper Field Well Locations)

From “Piper Field: Operational Aspects of Drilling/ Completions/Workovers/Data Acquisition and Well Performance. Society of Petroleum Engineers” by King. P.A Jan 1, 1980.




The basic design criteria were the completions should be least complicated that would ensure safe and successful operation. The decision was initially, the completions should have minimum components. This would reduce the time taken, and number of problems with wireline operations. In later stages of field development, it was necessary to move from simple completions to selective single completions in order to get required reservoir production needs (King. P.A, 1980, p20).

Seventeen of the first twenty wells were completed in similar way as shown in figure 2. Fifteen of these seventeen wells were 5 ½” tubing completions and two were 7” tubing completions.

From P21 onwards completion design was changed to accommodate 4 ½” tailpipe assemblies below the packer shown in figure 3.

 Figure 4 (Typical well completion5 ½”x 4 ½”producer)    Figure 5 (Typical well completion 5 ½” producer)

From “Piper Field: Operational Aspects of Drilling/ Completions/Workovers/Data Acquisition and Well Performance. Society of Petroleum Engineers” by King. P.A Jan 1, 1980

Completion Design Injection well

P16 was the first the first injection well completed with 2100’ of 5 ½” tubing set in 9 5/8” casing and was perforated with preliminary injection rates of 11500 BWPD. A decision to workover was taken as the injection rates was not satisfactory. Workover consisted of pulling the tubing acidizing the well and replacing the tubing with 7000 feet tubing. Post workover injection rates increased to 50000 BWPD. P17 and P19 was completed as injection wells as similar completion method.

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After 2 years P16 required workover to again increase its injection rates which was then increased to 84000 BWPD. P17 was left in the original state and P19 was re-drilled as producer (King. P.A, 1980, p21).

Completion Practices and Problems

Bottom hole assemblies are made in town to minimize time and problems at the wellsite. They are tested to 6000 psi and shipped to well site. This gets rid of the dangerous and time-consuming testing of separate assemblies is removed from the completions phase.

It has also proved advantageous to circulate tubing contents with diesel before setting the packer. It also eases the wireline work.

Completion fluid used have either been filtered, treated water from water injection system or diesel. Batoid coat B1400 is used as packer fluid to minimize corrosion. Perforations were done in underbalanced conditions, through tubing using 2 7/8” Hyper dome Scallops for both injection and production wells (King. P.A, 1980, p21).

Workovers on the field have been done because of several reasons, like, mechanical repair, well performance improvement, water shut-off, preparation of abandonment (King. P.A, 1980, p22).

Description of Surface Installation/ Equipment in Piper Field Alpha UK

Piper Field block was operated by the Occidental Petroleum Corporation in the North Sea sector of UK. The production of the field had been started from 1976 and was predicted up to 1994 with a production capacity of 700 MM BBLS, however, a sum of 55 successive wells were drilled in the original 36 slots and it was shutdown due to the tragedy occurred in July 1988. (ENGWALL, 2018)

In the field, natural flow of the fluid was supported by the reservoir pressure was only up to a percentage of 55, therefore to regulate the continues flow of offtake and to improve the recovery efficiency, external supportive equipment for artificial lift was employed which further helped the production to have an improvement up to 95%. Finally, electrical submersible pumping which was selected as the optimum method for artificial lift in the piper filed project. During the period the field produced around 112500 STBOPD through 27 active producers which was supported by the active combination of injectors and the natural aquifer. (ENGWALL, 2018)

The unit installation design consists of both downhole equipment and surface equipment. Surface protective equipment were implanted in the plant in order to protect the pumps/motors and to improve the running life. The production, gas compression, water treatment and other utilities facilities are placed in the level at +25m, drilling and the quarter packages located on the level of +33m. (ENGWALL, 2018)

From Exhibition, European Offshore Petroleum Conference And. (2018).


Following facilities were incorporated in the process cooling and water injection system.

  • 3 150 MBWPD submersible water pumps
  • 75 micron opening back washable filter screens for the primary filtration.
  • 240 MBWPD gas stripping towers for deoxygenation
  • Booster pumps with 150 MBWPD capacity to provide cooling water
  • 5-10-micron nominal rated back washable cartridge filters for fine filtering.
  • 3 Injection pumps which is parallel connected with 107 MBVPD capacity at 3600 rpm. (EUROPEAN OFFSHORE PETEROLEUM CONFERENCE AND EXHIBITION, 2018)


Using sea water exchangers, gas which is arrived from the separators is cooled scrubbed and compressed to 48 bar from 11.4 bar with the aid of three parallel connected centrifugal compressors. Then with combination of 6 reciprocal compressors in the first stage then gas is further cooled and compressed to 120 bar, 3900 H.P induction motors inherently balanced driven units at 327 RPM again the gas is cooled to 24oc through fresh water coolers and expanded via Joule-Thompson (J-T) valve to 52 bar. With some modifications, these compressors were commissioned to operate with a reliability around 93%. (EXHIBITION, EUROPEAN OFFSHORE PETROLEUM CONFERENCE AND, 2018)


The unit is equipped with two industrial type 23MW site rated 13.8kv 480-volt turbo alternators along with standby diesel fuelled 900 kw 480-volt turbo alternator. All the motors with H.P 1000 and above are operated in a range of 13.8kv and the motors with a range of 100-1000 H.P were in the 4.6 kv and all below 100 H.P operated on 440 volts. Apart from the three centrifugal gas compressors, all the prime movers are induction motors. Diesel fueled engine generators were used to power the drilling package moreover main generators and motors with rating 1000 H.P are water cooled. (EUROPEAN OFFSHORE PETEROLEUM CONFERENCE AND EXHIBITION, 2018)






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