Formation Pore Pressure and Fracture Pressure Estimating from Well Log in One of the Southern Iranian Oil Field * Mohammadreza Zare-Reisabadi, Mehdi Bahremandi Research Institute of Petroleum Industry (RIPI), Tehran, Iran *mr.zare.r@gmail.com Abstract Estimation of the sub-surface pore pressures and fracture pressure is a necessary requirement to safely, economically and efficiently drill the wells required to test and produce oil and natural gas reserves. The purpose of this paper is to select the best pore pressure and fracture pressure estimation method for Ahwaz Oilfield. Ahwaz oilfield is one of the biggest southern Iranian fields in the Middle East. Petrophysical and mud weight data for four previously drilled wells in this field will be examined and reviewed. Two pore pressure and one fracture pressure estimation method will be reviewed and applied to the available data. The pore pressure estimation methods are Eaton and Equivalent Depth method. These methods are simple correlations that predict the formation pore pressure using the normal pressured compaction trend line, the observed sonic data, and formation overburden stress. The fracture pressure estimation method used in this study also developed by Ben Eaton. An appropriate MEM has been developed to provide the required data such as formation overburden stress, shear wave velocity and formation Poisson s ratio. After comparing between results and mud weigh, most suitable methods have been chosen as the pore and fracture pressure estimation strategy in aforementioned field. Keywords Pore Pressure; Fracture Pressure; Overburden Stress I. INTRODUCTION For a successful drilling design it is extremely important to know or estimate the pore pressure for a given area. Casing design and mud weight designs are planned according to the estimated pore pressure. If the mud weight is not adjusted for the correct pore pressure, unwanted events like kicks can occur, which may result in lost time, or even blowouts. A good estimation of pore pressure is also essential to avoid wellbore stability problems like borehole breakouts or stuck pipes. Avoiding problems related to pore pressure determination can save lives and money. The subject of many discussions and technical papers in the last years has been the estimation of the wellbore pressure gradients that are required to induce or extend fractures in subsurface formations. The subject merits this attention because of the frequently recurring problems that arise from an inability to predict fracture pressure gradients. Several methods for predicting fracture pressures have developed and refined. Ali Najibi Petroleum University of Technology, Ahwaz, Iran Encountered in several common types of operations in the oil industry are problems associated with the estimation of formation fracture pressure gradients. When wells are being drilled in both new and old fields, lost circulation is often a very troublesome and expensive problem. Complete loss of circulation has been disastrous in some cases. Many times, such disasters could have been avoided if techniques for calculating fracture pressure gradient had been employed in the well plans, and if casing strings had been set, and mud weight plans had been followed accordingly. In areas of abnormally pressured formations, the estimation of fracture gradients during the well-planning stage is extremely important. In fact, it is as important as the estimation of formation pressure gradients, which has received a great deal of attention in recent years. II. OVER PRESSURE AND ITS GENERATING MECHANISMS Overpressure is often also called abnormally high pore pressure. It is known as the excess pore pressure observed for the area. In this study it will be defined as any pore pressure which is higher than the hydrostatic water column pressure extending from surface to the drilling target. In the literature, there are many mechanisms proposed to explain the development of overpressure. It is important to differentiate the porosity changes with respect to these different mechanisms. Here undercompaction mechanism will explain because of its important in Iran especially in Gachsaran Formation. Undercompaction is also known as disequilibrium compaction. In this type of mechanism vertical loading stress (overburden stress) is the main agent on shaping the pore space and pore throat systems. Hydrostatically pressured (normally pressured) areas usually have a characteristic rate of compaction. The reflection of this characteristic rate of compaction on well logs is a trend. During compaction the fluid in the systems will flow into upper sediments under the influence of vertical stress (overburden) if there is sufficient permeability. As the fluid escapes grains continue to support the applied vertical stress [1]. Undercompaction is the most encountered overpressure mechanism around the world while drilling. Fluid expansion and fluid movement and buoyancy are encountered often less than undercompaction. The magnitudes of overpressure in these types of mechanisms are considered to smaller than undercompaction mechanism for some researchers. For others however it is considered to be larger in magnitude. Tectonics is the rarest encountered mechanism around the world;
however the magnitude of overpressure due to tectonics is higher than any mechanism generating overpressure. Independent of generating mechanisms, any overpressure encountered during drilling is important []. III. PORE-PRESSURE ESTIMATION METHODS This paper will discuss the methods which use well logging data for prediction and quantification of overpressure. Clay is the lithology which compacts the most under stress by changes in its pore structure, reducing its porosity [3]. The following well logging based; pore pressure estimation methods will use this fact with the assumption that sediments interbedded with clay will have the same pore pressure. Reference [4] divides pore pressure determination techniques into two categories: vertical and horizontal methods. Vertical methods assume that for a given porosity, there will be a unique effective stress. This is the basis for the equivalent depth method. Horizontal methods, however, use the assumption of empirical relationship between pore pressure gradient and the ratio of porosity indicators like well logs. Eaton s equation is an example of this category. Reference [5] added two classifications to Traugott s pore- pressure determination methods: direct and other methods. In this paper Eaton and Equivalent Depth method have been reviewed which are in horizontal and vertical category respectively. A. Equivalent Depth Method Reference [6] tried to solve the problem of estimating pore pressure without direct measurements. In his method he used resistivity and sonic log data trends and the points where the deviation start from these trend lines. He developed this method for the Gulf of Mexico using known reservoir pressure measurements and a hydrostatic gradient of.465 psi/ft. His method is known as the Equivalent Depth Method. This method can be summarized as: P =.465Z + 1.(Z Z ) (1) P = Z.535(Z ) () Where, P is pore pressure, Z N and Z A are normal pressure depth and abnormal pressure depth in ft respectively. An assumption of the overburden gradient being 1. psi/ft is used in this method as well. The idea behind these formulas is that in over pressured formations, the overburden below a pressure seal will also be supported by fluid present in the formation, which is trapped by a good seal. So the pore pressure calculated for a depth where it is known that there is overpressure is the sum of hydrostatic fluid column pressure to the observed top of overpressure and the difference of depths between total depth and top of overpressure depth multiplied by overburden gradient of 1.. B. Eaton's Method In 197 Reference [7] published a technique for pore pressure estimation. Eaton recognized that Hottman and Johnson s basic relationship is correct, but can be improved. Eaton also developed a similar equation that can be used with interval transit time data. This equation can be used for both sonic log and seismic data. It is as follows: P D = σ D σ D P () D t () t () Where P f is fluid pressure in psi, D is the depth of burial in ft, σ ob is overburden stress in psi, P F(n) is area-specific normal pore pressure in psi, Δt ob(sh) and Δt n(sh) are observed shale travel time and normal shale travel time in μs/ft in μs/ft respectively. Eaton s relationships described above were thought (at least at the time of development) to predict pore pressures to within.5 ppg equivalent mud weight for any geologic environment as long as care is taken to provide quality input data. By its nature this is an empirical equation to relate well log and pore pressure gradient. This equation could be used in the environments where sediment compacted rapidly. Under compaction is usually observed in these kinds of environments. So Eaton s equation is very useful to quantify pore pressure where sediments show under compaction. Eaton s correlation, based on offshore Louisiana data in moderate water depths, is one of the more widely used fracture pressure estimation techniques. His relationship can be summarized as: υ g = (1 υ) g g + g (4) Where g f, g ob and g n are fracture pressure gradient, overburden gradient and normal pore-pressure gradient in psi/ft respevtively. The bracketed Poisson s ratio term is in fact a matrix-stress ratio. Eaton took fracture pressures in the subject area and back calculated Poisson s ratios using measured pore pressures and the variable overburden curve. IV. FIELD APPLICATIONS The Ahwaz Field is located near the Ahwaz city. This field, one of the largest hydrocarbon bearing structures in the world, is a large northwest-southwest trending anticline with a subsurface area of 8 by 6.5 km. Fig. 1 shows the location of Ahwaz oilfield. In order to predict the pore pressure and fracture pressure profile of Ahwaz Oil Field, we collected all the available well logs data. The relative location of wells and their formation thicknesses have been shown in Fig.. A. Density Prediction Usually density logs are used for determination of the rock density. But, the density log is run in the reservoir section of wells not the whole interval. In 1974 Reference [8] conducted a series of controlled field and laboratory measurements of saturated sedimentary rocks and determined a relationship between P-wave velocity and density that has long been used in seismic analysis. (3) b a. V (5) Where ρ is in gr/cm3, and V is in m/s, a=.31, b=.5 Using density log and sonic log data in the reservoir section, the constant parameters of Gardner equation can be estimated for Ahwaz oilfield. Data of six wells has been used. Fig. 3 shows the relation between bulk density and P-wave velocity in Ahwaz oilfield. The following correlation was obtained for density estimation along the well A and B.
.376.577V (6) Where V is in ft/s and is in gr/cm3. Fig. 4 shows the accuracy of predicted density. B. Vertical Stress Gradient The overburden is the weight of the column of sediments. Although it is not measured directly, it can be easily computed as the integral over depth of the bulk density: v h gdh (7) Fig. 5 shows the vertical stress gradient versus depth in the Ahwaz oilfield. Fig. 6 shows that the data points have been fitted well with a following exponential function: ( h) ae b h ce dh v (8) Where σ v is in psi/ft, h is in ft, a=1.47, b=-1.514e-5, c=-.5847 and d=-9.141e-5 C. Ratio Prediction Due to absence of laboratory data in studied wells, direct calculation of Poisson s Ratio is impossible. But the Poisson's ratio is related to the sonic log with the physical equation [9]: 1 t s 1 tc V p t ( V s 1 tc Where ts and tc are shear and compressional transit time respectively, Vp and Vs are compressional and shear sonic velocity. The following equation related the sonic transit time in μs/ft to sonic velocity in ft/s: V t 1 1 6 (9) (1) Most of available sonic logs in Ahwaz oilfield include only the compressional or P-wave transit time. The DSI log data are available in well A. The DSI tools record both shear and compressional transit time. Fig. 7 shows the available shear velocity versus compressional velocity. Fig. 7 shows that the data points have been fitted well with a following power law function:.8386 s V p V.58 V p V, ft/s (11) Fig. 8 shows the prediction of shear velocity of well A by equation 11 and Fig. 9 shows the estimated Poisson s ratio. s s ) V. PREPARATION OF SONIC LOGS DATA USING CLAY DISCRIMINATION LINES As be mentioned later in the literature, the most compaction occurred in the clay formations. If we use all the sonic logs data, they will not specify the compaction trend clearly, especially in the Gachsaran Formation. So, for observing the compaction trend especially in Gachsaran formation, the lithologies which have the most clay can be used. For discrimination of lithologies which have the most clay in their structure, Gamma Ray Logs have been used. The data that have less value in gamma ray from clay discrimination line have been filtered and other data have been employed for pore pressure estimation. This procedure has been illustrated in Fig. 1. VI. NORMAL COMPACTION TREND (NCT) One of the prerequisite for pore pressure and fracture pressure estimation is filtered sonic logs. Figures (11.1 to 11.4) show the filtered sonic logs and their normal compaction trend and their equations. As be mentioned later, normal compaction trend is required for pore pressure estimation from Eaton's method. These figures illustrate that In Aghajari and Mishan Formations, the sonic data has a linear trend line which reveals that pore pressure is normal in these formations and in Gachsaran Formation, the sonic data deviates from normal compaction trend line which indicates abnormal pore pressure in this formation. VII. PORE PRESSURE AND FRACTURE PRESSURE ESTIMATION STRATEGY Sonic log, gamma ray, and daily drilling parameters such as mud weight are available data of aforementioned oil field. Considering these data base, among the available pore pressure estimation, only Eaton and Equivalent Depth method can be applicable in this field. Fracture pressure and pore pressure gradient for aforementioned Oil Field are shown in figures 1.1 to 1.4. As it is mentioned before, Eaton and Equivalent Depth method are applied in four wells. The results from those methods show that, pore pressure for Aghajari and Mishan Formation is close to each other. In addition for the Gachsaran Formation in the cases of well No. 1 and well No. Equivalent Depth method give smaller amount of pore pressure relative to mud weight and Eaton Method, so it can be concluded Equivalent Depth method underestimate in these cases. Regarding figures 1.1 to 1.4 Equivalent Depth method gives smaller amount of pore pressure relative to mud weight and Eaton Method. Equivalent Depth method can give an estimate for pore pressure, but the degree to which the fluid carries of the entire overburden load is unknown. It is because of the value of Biot constant considered unity in effective stress equation. VIII. CONCLUSIONS To estimate the pressure, results of both the Eaton and Equivalent Depth method were compared and the following conclusions are made: 1) According to the normal compaction trend lines and pressure which are calculated in this study, it can be
concluded that under compaction is a major mechanism in explaining high pore pressure in Gachsaran Formation. ) For Aghajari and Mishan Formation, both of Eaton and Equivalent ivalent Depth method give same results. 3) In the case of Gachsaran Formation, Equivalent Depth method tends to underestimate pore pressure. So, Eaton method is recommended to estimate pore pressure of Gachsaran Formation in this field. 4) To estimate pore and fracture racture pressure gradient with suitable accuracy, it is recommended to assume an amount of 1 psi/ft overburden gradient for Aghajari and Mishan Formation and 1.6 psi/ft for Gachsaran Formation. Fig.. The relative locations of studied wells REFERENCES 3.5 3.5 1.5 1 5 1 15 Velocity [ft/s] 5 Recorded density Predicted density Density [gr/cm3] 1.5 1.7 1.9.1.3.5.7.9 18 11 11 114 116 118 1 1 14 16 Fig. 4. Predicted and recorded density Fig. 1.location of Ahwaz Oil Field [1] 3 Fig. 3. Relation between density and velocity in Ahwaz oilfield Depth [ft] Density [gr/cm3] Mouchet, J.P. and Mitchell, A., Abnormal Pressures Pressur While Drilling, Manuels Techniques, Elf Aquitaine, Bouseens, France, 1989. [] Swarbrick, R.E., Osborne, M.J., Yardley, G.S., Comparison of Overpressure Magnitude Resulting from the Main Generating Mechanisms, Pressure Regimes in Sedimentary Basins and Their Prediction, A.R. Huffman, and G.L. Bowers, AAPG Memoir, Vol. 76, PP. 1-1,. [3] Schutjens, P.M.T.M., Hanssen, T.H., Hettema, M.H.H., Compaction Compaction Induced Porosity/Permeability Reduction in Sandstone Reservoirs: Data and Model for Elasticity-Dominated Dominated Deformation, SPE Reservoir Evaluation & Engineering, Vol. 7, No. 3, PP. --16, 4. [4] Traugott, M., Pore Pressure and Fracture Pressure Determination in Deep Water, Deep Water Technology Supplement to World Oil, 1997. [5] Bowers, G., State of Art in Pore Pressure Estimation, Report No.1, DEA Project 119, Knowledge Systems Inc., Stafford, Houston, Texas, 1999. [6] Ham, H.H., A Method of Estimating Formation Pressures From Gulf Coast Well Logs, Trans., Gulff Coast Association of Geological Societies, Vol. 16, PP. 185-197, 1966. [7] Eaton, B. A., The Effect of Overburden Stress on Geopressure Prediction from Well Logs, Journal of Petroleum Science & Engineering, Vol. 4, PP. 99-934, 197. [8] Gardner, G.H.F., Gardner, ner, L.W., and Gregory, A.R., Formation Velocity and Density- The diagnostic basis for stratigraphic traps, Geophysics, Vol. 39, PP. 77-78, 1974. [9] Chardac, O., Murray, M., Marsden, J. R., A proposed data acquisition program for successful geomechanics projects, SPE 9318 presented at the SPE Middle East Oil & Gas Show and Conference in Bahrain, 1-15 1 March 5. [1] Zare-Reisabadi, M.R, Shadizadeh, SR, Habibnia, Habibnia B. Mechanical Stability Analysis of Directional Wells: A Case Study in Ahwaz Oilfield. In: proceedings ceedings of SPE Annual Technical Conference and Exhibition. Abuja, Nigeria; 31 July-77 August 1. SPE 136989. y =.577x.376 R =.499.499 [1] 3.1
Sigma v [psi/ft].85.9.95 1 1.5 1154 Shear velocity [ft/s] 45 55 65 75 85 95 15 115 1155 4 1156 Depth [ft] 6 8 Depth [ft] 1157 1158 1 1159 1 116 14 Fig. 5. Vertical stress gradient estimation [1] 1161 Real Predicted Fig. 8. Predicted shear velocity by (11) 115 Poisson's ratio..5.3.35.4 1155 116 Fig. 6. Fit equation of vertical stress gradient [1] 1165 13 1 y =.58x.8386 R =.9191 Depth [ft] 117 11 S-wave velocity [ft/s] 1 9 8 7 1175 118 6 5 8 1 1 14 16 18 P-wave velocity [ft/s] Fig. 7. Relation between S-wave and P- wave velocity in Ahwaz oilfield 1185 Fig. 9. Poisson s ratio prediction
Clay Discrimination Line Gamma Ray (API) 1 3 4 5 6 Clay Transit Time ( µs/ft) 1 1 1 1 5 1 Depth (m) 15 5 3 Fig. 1. Application of Clay Discrimination lines for filtering of sonic data Fig. 1.. Application of Clay Discrimination lines for filtering of sonic data
Fig. 11.1. Filtered sonic log and its NCT in well number 1 Fig. 11.. Filtered sonic log and its NCT in well number
Fig. 11.3. Filtered sonic log and its NCT in well number 3 Fig. 11.4. Filtered sonic log and its NCT in well number 4
Well No. 1 Well No. Eaton's Method Mud Weight Equivalent Depth Method Fracture Pressure Eaton's Method Fracture Pressure Equivalent Depth Method Mud Weight Pressure Gradient (ppg) 5 1 15 5 Pressure Gradient (ppg) 5 1 15 5 5 5 1 1 Depth (m) 15 Depth (m) 15 5 5 3 Fig. 1.1. Pore pressure and fracture pressure profile from well number 1 Fig. 1.. Pore pressure and fracture pressure profile from well number
Well No. 3 Well No. 4 Eaton's Method Equivalent Depth Method Eat on's Met hod Equivalent Depth Met hod Fracture Pressure Mud Weight Mud Weight Fracture Pressure Pressure Gradient (ppg) 5 1 15 5 Pressure Gradient (ppg) 5 1 15 5 5 1 Depth (m) 15 Depth (m) 1 15 5 3 Fig. 1.3. Pore pressure and fracture pressure profile from well number 3 Fig. 1.4. Pore pressure and fracture pressure profile from well number 4