Rogers, Clint (Smith Bits a Schlumberger Company) | Jangani, Reza (Smith Bits a Schlumberger Company) | Spedale, Angelo (Smith Bits a Schlumberger Company) | Sadawarte, Sagar (Smith Bits a Schlumberger Company)
The Mereenie development project is targeting oil and evaluating natural gas reservoirs in the lightly drilled Amadeus Basin. In 2012, an operating company started searching for methods to improve rate of penetration (ROP) drilling the 8¾? vertical hole section through the difficult Stairway and Pacoota sandstone formations. The lithology consists of very abrasive and hard siltstone/sandstone with UCS up to over 30,000 psi. The hole section starts at 500 m and generally requires 700 m of total wellbore to reach KOP at 1200 m. The section has historically been drilled with PDC and Roller Cone bits with mud as the circulating medium. Both types of BHAs produced unacceptably slow ROP and required multiple trips to reach TD. The operator required a new approach.
To accomplish the objective, the operator wanted to switch from mud to underbalanced drilling using an air percussion BHA equipped with a hammer bit. However, an analysis using a well records database showed that only short (10–30m) shallow surface intervals had been drilled in Australia with percussion air hammers mostly in mining applications in the 1980–90's.
To increase the chance for early success, the operator wanted to import the latest air hammer tools and drilling techniques from North America. The provider suggested taking lessons learned from the Northeast USA where air hammer drilling plays a major role in developing oil and gas reserves in the region. The two applications are similar with regards to formation characteristics and the drilling team concluded the provider's downhole tool technology, service culture and experience/expertise would be integral to project success. In Q4 2013 the provider drilled the fastest and deepest percussion air hammer run in Australia's Oil and Gas history at 24 m/hr, 700% faster than the previous ROP achieved with PDC or Roller Cone.
The Mereenie field, located about 185 miles west of Alice Springs in the Northern Territory of Australia, consists of a large gas cap surrounded by a narrow oil rim. The oil rim has been the predominant target, with the majority of oil produced from the Pacoota P3-120/130 sandstone reservoir. At approximately 4,500 to 5,000 ft, the reservoir exhibits permeabilities of 5 to 100 md. Pressure-transient analysis and production characteristics of early wells indicated increasingly high levels of near-wellbore damage, discovered later to be associated with fines migration and an extensive illite clay network. In an attempt to overcome this impairment, seven hydraulic fracturing treatments were performed between 1983 and 1987; however, postfracture results were disappointing. Extensive well testing, laboratory work, and reservoir/fracture modeling identified major problem areas associated with both the reservoir and the fracture treatments. During 1991-92, seven additional treatments were performed to achieve a tip screenout (TSO) to form a short, highly conductive flow path to bypass the damage. These resulted in a significant increase in production, an upgrade in the field's recoverable reserves, and additional development drilling.
The Mereenie field, discovered in 1964 and placed on production in late 1984, is a long, narrow, anticlinal structure some 25 miles long and 2 to 3 miles wide. The target reservoirs have been in the narrow oil rim (surrounding the gas cap) in the Pacoota sandstone formation, which is a predominantly thick quartzose sandstone interbedded with thin shale layers. Fig. 1 shows a log cross section through the field. Though production has been achieved from other horizons, the Pacoota P3-120/130 has exhibited the most consistent porosity and permeability. The average gross pay thickness for this reservoir is about 25 ft, with permeabilities of 5 to 100 md and porosities of 6% to 12%. While a reservoir of this quality has typically not been considered for hydraulic fracturing to stimulate production, the need arose from apparent near-wellbore damage occurring after limited production. Results from a 1988 study showed the primary source of damage to be migration and trapping of dislodged rock fragments and broken fibrous illite "hairs" within the major pore throats. To overcome this, hydraulic fracturing treatments were designed to achieve a highly conductive flow path through the damage. These treatments have resulted in significant improvements in both short- and long-term performance.
The Mereenie field is a large complex sandstone reservoir and the well tests have some peculiarities which, though not fully understood, have considerable bearing on the well test interpretation.
The first of these are diurnal pressure variations caused by gravitational effects which particularly affect interference tests. Secondly, because of the high gas-oil ratio, phase segregation in the well bore causes a hump in the Horner plot on some of the build-ups.
Thirdly, in one of the sands in one area of the field there is a marked discrepancy between drawdown and build-up results which is attributed to stress dependent permeability. Also core permeabilities in general do not agree with build-up permeabilities.
The Mereenie field is a long narrow anticlinal structure located in the Amadeus basin in the Northern Territory of Australia. Production comes from the Pacoota sandstone and is presently producing at a rate of about 4,000 STB of oil per day from 18 wells. There are 18 separate sand units in the Pacoota but only the P3-120/130 interval has Pacoota but only the P3-120/130 interval has consistent porosity and permeability throughout the field. This sand averages 10% porosity and 30 md permeability and 25 ft of net pay thickness. Of the permeability and 25 ft of net pay thickness. Of the other sands, the P1-80 sand has good reservoir characteristics only on the eastern nose of the anticline. The P3-190/230/250 sands have consistent porosity but sporadic permeability throughout the porosity but sporadic permeability throughout the field. The P1-280 sand has good reservoir characteristics only in the western half of the field. The other units have occasional shows of porosity but have not shown any permeability so far. porosity but have not shown any permeability so far. The reservoirs are large and complex and these complexities are reflected in the well tests characteristics and their subsequent interpretation. Tests that have been carried out include drawdown and build-up tests, four point modified isochronal tests, interference and pulse tests. These have contributed greatly to the formation evaluation and understanding of the reservoir.
However, some of the results are not fully understood. During this paper these are highlighted and various explanations are postulated.
THE MEREENIE RESERVOIR
In order to discuss the tests, an elementary knowledge of the Mereenie reservoirs is required, A structure map of the field at top Pacoota level is shown in Figure 1, and a stratigraphic correlation is shown in Figure 2. On the north and south flanks of the structure the formation dips are very steep, of the order of 15 degrees and 20 degrees, and the oil windows become very narrow. On the eastern nose the dips are shallower, of the order of 1 degrees in places and the oil windows spread out.
The geology of Mereenie has been discussed in more detail elsewhere but suffice it to say that it is a fairly tight sandstone reservoir of early Ordivician to late Cambrian age. The Pacoota reservoir is broadly split into four groups, the P1, P2, P3 and P4. These are further split into P2, P3 and P4. These are further split into individual sand members. There are six wells, EM6, EM8, EM24, EM25, EM26, and EM27 completed in the P1-80 reservoir which is classified as new oil. The P1-80 reservoir which is classified as new oil. The P1-80 reservoir averages 6 ft of net pay with average P1-80 reservoir averages 6 ft of net pay with average porosity of 11% and an average permeability of 50 porosity of 11% and an average permeability of 50 md. There are 20 wells completed in the various P3 reservoirs. Of these EM7, 16, 17, 18, 20, 21, 22, 23, 28 and WM7 are completed open hole in all of the P3 reservoirs. P3 reservoirs.
NATURAL GAS-A REVIEW OF ITS OCCURRENCE AND POTENTIAL IN AUSTRALIA AND PAPUA Abstract As a result of increased and improved exploration in recent years, significant oil and gas discoveries were made in 15 of the 25 main sedimentary basins in Aus- tralia and in Papua. Altogether 1,269 wells totalling 5,343,200 feet were drilled to 30th September, 1966; 47 wells were com- pleted for oil production and 93 for gas; of these, 23 oil and 2 gas wells are currently producing. The cost of this effort to the end of 1965 was $US. 414.33 million including $US. 90 million spent in Papua. Proved and probable gas reserves found to date are of the order of 7 trillion (million million) CU ft. Natural gas will make a significant contribution to the Australian primary energy consumption in com- petition with coal and petroleum products. Potential markets for gas are few, but they will grow and in- digenous natural gas may capture the share of the market presently dominated by petroleum products, including residual fuels. Gas reservoirs are predominantly sandstones, rang- ing in age from the Lower Ordovician (Amadeus Basin), through Middle Devonian (Adavale Basin), Permian (Perth, Cooper, Bowen Basins), Jurassic (Perth, Surat, Papuan Basins), Cretaceous (Papuan, Gippsland, Carnarvon Basins) to Tertiary (Gippsland Basin) ; limestone forms the reservoirs in the Tertiary of the Papuan Basin. The structures are essentially anticlinal ; some are modified by faulting. Stratigraphic traps in silty sands which have rapid permeability variations are common in the Surat Basin. Most of the reservoirs are in marine Sediments, but reservoirs are essentially non-marine in the Cooper, Surat, and Gippsland Basins. EXPLORATION AND DISCOVERIES (Fig. 1) The discovery of natural gas in Australia dates back to 1900 when a water well at Roma in Queensland by J. N. CASEY and M. C. KONECKI Bureau of Mineral Resources, Geology and Geophysics, Department of National Development, Canberra, Australia Résumé Grâce à l'accroisement et à l'amélioration de l'ex- ploration dans ces dernières années, des découvertes importantes d'huile et de gaz ont été faites dans 15 des 25 principaux bassins sédimentaires d'Australie et de Papua. En tout, 1269 puits totalisant 5.343.000 pieds ont été forés au 30 Septembre 1966; 47 de ces puits étant pro- ductifs d'huile et 93 de gaz; sur ce total 23 puits sont actuellement exploités pour l'huile et 2 pour le gaz. Le prix de cet effort à la fin de 1965 était de U.S.$414,33 millions dont U.S. $90 millions pour la Papua. Les réserves de gaz prouvées et probables à ce jour sont de l'ordre de 7 trillion de pieds cubes. Le gaz naturel apportera une contribution impor- tante dans la consommation d'énergie primaire en Aus- tralie, en compétition avec le charbon et les produits pétroliers. Le marché potentiel pour le gaz est actuelle- ment faible mais il va croître et le gaz naturel local peut capturer l