A New Fracture Gradient Prediction Technique That Shows Good Results in Gulf of Guinea wells
- Aleruchi Boniface Oriji (University of Port Harcourt) | Joel Friday Ogbonna (University of Port Harcourt)
- Document ID
- Society of Petroleum Engineers
- Abu Dhabi International Petroleum Conference and Exhibition, 11-14 November , Abu Dhabi, UAE
- Publication Date
- Document Type
- Conference Paper
- 2012. Society of Petroleum Engineers
- 1.8 Formation Damage, 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties), 5.2 Reservoir Fluid Dynamics, 1.11 Drilling Fluids and Materials, 1.6.1 Drilling Operation Management, 5.6.1 Open hole/cased hole log analysis, 1.7 Pressure Management, 1.7.5 Well Control, 2 Well Completion, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 1.6 Drilling Operations
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One of the major challenges of drilling and completion of oil and gas wells is the uncertainty in the formation fracture gradient and the fracture pressure. It is not uncommon that many drilling companies have spent money, resources and time in drilling and completing wells that should have been simply and optimally done. Fracture gradient evaluation constitutes one of the essential parameters in the pre-design stage of drilling operations, reservoir exploitations and stimulations. Several calculation methods and computer models have been presented in the literature for different regions of the world. Most of these techniques were based on either parametric or empirical correlations, which required a prior knowledge of the functional forms or the use of empirical charts which were not very accurate.
This paper presents an innovative method of predicting formation fracture gradient for Gulf of Guinea region. A combination of "Mathew and Kelly?? correlation, "Hubbert and Willis?? correlation and Ben Eaton mathematical models were used in developing the simplified technique based on field data from the Gulf of Guinea. The model compared favorably with the existing fracture gradient results in the Gulf of Guinea with less than 1 % deviation from other correlations thereby saving the rigors and time in using tables, charts and other long techniques. Although the method was developed specifically for the Gulf of Guinea, it should be reliable for other similar areas provided that the variables reflect the conditions in the specific area being considered.
The exploitation and production of petroleum (oil and gas) involves drilling from the surface of the earth through several geological formations into the reservoir(s) where the crude oil is accumulated. During drilling, proper well control is needed where the hydrostatic pressure of the mud column is kept slightly above the formation pore pressure and slightly below the formation fracture pressure. The hydrostatic pressure is the pressure exerted by a column of a given mud in the drill string. Mathematically, it is evaluated as a function of the mud weight / density and the height of the column. The formation pressure is seen as the pressure exerted by the fluid(s) occupying the pore spaces of the formation under investigation. Fracture pressure is therefore the borehole pressure required to initiate fracture in the formation. Pore pressure (formation pressure) and fracture pressure determination are strong functions of the overburden pressure. In this quest, the overburden pressure is the pressure exerted on a formation due to the weight of all the younger formations (strata) above it. This pressure is actually the summation of the weight of the formation matrix, sediments plus the weight of the fluid entrapped in these formations. Formation pressure may be seen in three distinct existences depending on the magnitude of the hydrostatic pressure in the drill string. A formation is said to be over-pressured (abnormal pressure) if the formation pressure is greater than the hydrostatic pressure exerted by the mud column in the drill string, thereby creating a pressure differential by which the formation fluids flow into the wellbore. The second type of formation pressure that could be encountered is the "expected pressure?? known as normal pressure. Formation pressure is said to be normal if it equates or approximately equal to the hydrostatic pressure in the drill string. In this case, there is a balance in the pressure value between the formation and the well so that no fluid goes into the formation from the well (drill string) and no influx from the formation into the wellbore. The third type of formation pressure is called sub-normal pressure (under pressured). This occurs when the formation pore pressure is less than the hydrostatic pressure of the mud column in the drill string. When this happens, drilling fluids tend to move into the formation creating formation damage around the wellbore.
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