High-Pressure, High-Temperature Drilling: Data Management and Interpretation

Dissolution of high-pressure gas in drilling fluids and oil well cement slurries may cause problems when the gas is liberated. A literature survey on solubility data confirms that gas may be dissolved and liberated at typical well conditions. Formation gas dissolved in the drilling mud is liberated when the mud returns to the surface, but this is normally not a problem. It is not known whether dissolved gas in the cement slurries may create any problems. A new hypothesis is introduced, claiming that gas from the formation may enter into the cement slurry and eventually lead to a weaker cement and/or to fractures, enabling a continuous migration of gas to the surface. Laboratory experiments have been carried out on cement slurries. Thin sectioned samples of the hardened cement showed that more gas bubbles and fractures had indeed developed in the cements that had been exposed to pressurized gas before and during the hardening process.

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“…This is especially true for deep wells where the solubility is high. 1 For cement, two mechanisms are thought to act in parallel Lile el at.…”

Section: Introductionmentioning

confidence: 99%

Dissolved gas as a problem in oil well cements

Lile¹,

Justnes²,

Skalle³

et al. 1996

Advances in Cement Research

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Plumbing the depths of the Central Graben: towards an integrated pressure, fluid and charge model for the Central North Sea HPHT play

Winefield

Gilham

Elsinger

2005

PGC

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The integration ofdetailed seismic mapping, overpressurestudies,basinmodellingandnewdrilling hasp rovided newinsights into the 'plumbing's ystemo fthe deep,H igh-temperature, high-pressure(HPHT) playint he CentralGraben. Although overpressured istribution int he pre-Cretaceous section isbroadly related to depth, large-scalec ompartmentalization ofthe mainJurassic/Triassic reservoirs hasr esulted int he generation ofanumbero fd istinctp ressurec ells. Thesepressurec ells areb ounded bym ajor structuralfaults (e.g.Forties/MontroseHigh)orby' interpod'settingswherethe Jurassic/Triassic reservoirsequence thins over salt ridges. Evidence ispresented thatshows overpressureisakeycontrol on hydrocarbon retention inthisarea, withseveralstructuresknown to haveblown top seals or to be leaky(i.e.underfilled)atpresent. The commercial Shearwaterstructureisshown to be anexampleofthe latter,havingevidence for apalaeo-oilcolumn beforethe sealp resumably breached andthe trapr echarged withalatergas-condensatefi ll. The lengthofh ydrocarbon column inthe structureatpresent dayiscontrolled bythe aquiferpressureand, inturn,bythe shallowest point in the Shearwaterp ressurec ell. The overpressurea ndtrapfillingh istory hashad important implications for hydrocarbon migration,retention andthe resultant composition ofhydrocarbon accumulations inthispart ofthe HPHT area.Aconceptualmodelisp resented here.

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The Application of Petrophysical Data to Improve Pore and Fracture Pressure Determination in North Sea Central Graben HPHT Wells

Ward¹,

Coghill

Broussard

1994

All Days

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Pore and fracture pressure determinations are key considerations for the successful planning and drilling of North Sea Central Graben High Pressure High Temperature (HPHT) wells. Knowledge of these downhole pressure constraints can have a significant impact on drilling safety and economics. In this paper we present recent advancements to a previously presented methodology. Pore and fracture pressure is determined using wireline or MWD petrophysical data and an effective stress approach. The results have increased our understanding of overpressure generation mechanisms and hydrocarbon migration in this basin. Most traditional pore pressure estimation methods use a shale disequilibrium compaction model for their calculations. We assess these methods and propose that excellent results can be obtained by deriving porosity from density or deep resistivity data. This porosity, together with a lithology estimation from the gamma ray, are input into an Effective Stress Loading limb (ESL) model that calculates pore and fracture pressures through all major lithologies. Along the North Sea Central Graben axis there are two distinct pressure domains. These are separated by a low porosity (<5%) horizontal pressure seal within the Cretaceous Chalk Group. This seal occurs between 3.5-4km and is independent of stratigraphic level within the chalk. Above 3.5km, rapidly deposited Tertiary shales and Upper Cretaceous chalks are on the compactional loading limb. Here, moderate overpressures are generated by disequilibrium compaction. Below 4km, low porosity (5-10%) Mesozoic sediments are unloaded by fluid expansion mechanisms to produce extreme overpressures. The upper limit for the pore pressure is the fracture propagation pressure. When this is exceeded, hydraulic fracturing can occur and the fluids escape, allowing the fracture to close and pressure to build again. In this environment, primary hydrocarbon migration may be largely dependent on the rate of the hydraulic fracturing formed as a consequence of the extreme fluid pressures generated by fluid expansion. An understanding of these pressure generating mechanisms, together with improved porosity determinations, has led to more accurate pore and fracture pressure determinations. Implementing the results into well planning and drilling can help avoid many of the costly pressure related problems inherent to HPHT wells. Introduction Operators increasingly target deep HPHT prospects in many areas of the world. Accurate pore and fracture pressure determinations in these wells are key considerations. Optimurn mud weights and casing point selections are crucial to safe, efficient, and cost effective planning and drilling. Pressure related problems include well control incidents, lost circulation, differential sticking, reduced rates of penetration, and reservoir damage. These often lead to costly sidetracks, well abandonments, lost production, and even underground blowouts. The latter could lead to the expense of drilling a relief well and in extreme cases loss of rig and lives. Pressure related problems therefore represent a significant proportion of the high drilling costs associated with HPHT wells. In the Norwegian sector, average HPHT wells are four times as likely to have a well control problem, and incur an average of eight times the downtime of other exploration wells (Table 1). P. 53^

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High-Pressure, High-Temperature Drilling: Data Management and Interpretation

Cited by 3 publications

References 6 publications

Dissolved gas as a problem in oil well cements

Dissolved gas as a problem in oil well cements

Plumbing the depths of the Central Graben: towards an integrated pressure, fluid and charge model for the Central North Sea HPHT play

The Application of Petrophysical Data to Improve Pore and Fracture Pressure Determination in North Sea Central Graben HPHT Wells

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