Clay Minerals Properties as Downhole Formation Pressure Indicator

Transcription

1 J. Chem. Chem. Eng. 5 (2011) Clay Minerals Properties as Downhole Formation Pressure Indicator Dmitry Kozhevnikov, Kazimir Kovalenko, Andrey Gorodnov and Ivan Deshenenkov * Well Logging Department, Gubkin Russian State University of Oil and Gas, Moscow , Russia Received: June 30, 2011 / Accepted: August 4, 2011 / Published: November 10, Abstract: The successful estimation of formation pressures (or formation pore gradient) is fundamental and the basis for many engineering works including drilling and oilfield development planning. Common log data are used for formation pressure calculation. Modern techniques for pressure prediction have several disadvantages, notably, incorrect account of the downhole nonsteady thermal field and clay mineral composition. We propose a way to overcome listed shortcomings: a technique for thermal field proper account while formation pressure estimation and a petrophysical model, which reflects relationships between clay minerals composition and rock properties, derived from log data. Key words: Formation pressure, clay minerals, overpressure, temperature effect, undercompaction, petrophysics, log data. 1. Introduction It is vital to the planning of drilling wells to have an estimate of the expected pressure regime to be encountered in the subsurface. Direct concerns are the safety of the personnel and equipment, in particular minimizing the associated risks. Furthermore, it facilitates more effective planning and ordering of the required material. With respect to the reservoir, the right drilling mud weight is important. If it is too low, a blow out might occur and conversely, if it is too high, the formation might be damaged by invasion of the drilling fluid. So, knowledge of downhole pressure constraints can have a significant impact on drilling safety and economics [1-3]. High technological and economic performance in drilling and deep wells development can be achieved in case of correct overpressure zones prediction and pressure value estimation. It requires the correct application of methods and evaluation procedures. Normal formation pressure is due to the presence of * Corresponding author: Ivan Deshenenkov, M. Sc., research field: petrophysics and rock physics. isd@post.com. fluids (water, hydrocarbons) in pore space of the rock matrix (hydrostatic pressure of fresh or salt water). It can be considered as an open hydraulic system where pressure can easily communicate through the formation pores. Overpressure is any geopressure that is different from the established normal trend for the given area and depth. The presence of hydrocarbons in reservoirs, the rate of sedimentation, deposition and compaction of sediments (especially clayey sediments) as well as tectonics activities (faults, salt diapirs, etc.) are main origins for the overpressure generation. If a quick sedimentation process does not give enough time for the interstitial water to escape, or, if the normal porosity compaction process is prohibited by not letting the fluids in the pore spaces escape, the rock matrix (shales) cannot increase its grain-to-grain contact; therefore its compaction is not completed and the shales are under compacted. In such pressure system fluids are not free to expel from the pores. The total overburden load continues to increase with sedimentation; the rock matrix can no longer carry its burden; the fluids in the pores of the rock begin to support part of the overburden, resulting

2 Clay Minerals Properties as Downhole Formation Pressure Indicator 991 in higher than normal fluid pressures [4]. Shaly rocks containing deposits with overpressure are less sealed and have higher porosity in comparison with normal pore pressure rocks. The most commonly used pore pressure estimation methods employ a shale undercompaction model. They utilize log data (resistivity, sonic, density) from a normal compaction trend determined in hydrostatic shales. Deviations from this trend are related to overpressures by various techniques (equivalent depth method, Eaton method, ratio method and other effective stress concepts [5-9]. Most of these measure a shale properties (physical and petrophysical), either directly or indirectly, as their fundamental input. The exactitude of the rock properties determination is therefore paramount to the accuracy of most pore and fracture pressure models. One of the applicable ways for formation pressure prediction is normal clay compaction trend technique, based on effective stress concept described above. There are several factors influencing on the accuracy of formation pressure estimation according this technique such as mineral composition of clays enclosing studied reservoir, downhole temperature, fracture gradient, quality of log data, etc.. This paper is devoted to temperature and clay minerals composition effect on formation pressure evaluation. 2. Normal Clay Compaction Trend Technique According to the normal clay compaction trend technique formation pressure is the sum of normal pressure and overpressure component. The following steps are necessary to estimate the formation pressures: the normal trend is established by plotting the logarithm of shale resistivity vs. depth, the top of the pressured interval is found by noting the depth the plotted points diverge from the trend (Fig. 1) then the pressure gradient at any depth is found as follows: (a) The ratio of the extrapolated normal shale resistivity to the observed resistivity is determined and plotted; Fig. 1 Clay compaction trend normalization to the temperature t 1 : 1-in studying sequence; 2-normalized to the temperature t 1 on the depth h 1 ; 3-overpressure zone; 4 and 5-normal clay compaction trend continuation in overpressure zone. (b) The equation for formation pressure estimation is applied [7]: n g( δ R δ w) av Δh ρ P lg R o = Pn +, h lg( 2 h / 1 a (1) ρ ρ ) + ( α( ρ) / 2.3) GΔh ρ R where P o is overpressure value, MPa; P n is normal pressure on the current depth, MPa; g is acceleration of gravity, 9.8 m/sec 2 ; n a ρ R, ρ R are rocks resistivities in normal pressure and overpressure zones accordingly, Ohm m; δ R, δ w are average rock and reservoir fluid densities for studied sequence, g/cc; G is geothermal gradient for a region; h ρ 1 h, ρ 2 are resistivities of the rock in the zone of normal pressure (upper part of the sequence); α (ρ) is a temperature correction coefficient. The main advantage of this technique is possibility of algorithm realization on PC in workflow mode. Factors determining changes in physical properties of pure clay rocks are variation of clay mineral composition and temperature. The impact of changes in clay mineral composition is essential up to the depth about m. Temperature makes significant contribution to the calculation of reservoir pressure at

3 992 Clay Minerals Properties as Downhole Formation Pressure Indicator all depths [10]. We propose a model for clay minerals type identification with standard log data and technique for correct account of the nonsteady thermal field while estimation of formation pressure. 3. Reservoir Rocks Petrophysical Model Both reservoir and non-reservoir rocks physical properties depend on clay mineral composition that reflects on logging data (density, hydrogen index, slowness, resistivity, etc.). Petrophysical model of the granular reservoir corresponds to water retention ability of the rock (so-called total water holding capacity of the rock). Results of our research show that there is a clear dependence between total water holding capacity and clay mineral composition. Fig. 2 gives an example of this dependence for fine-grained Western Siberia Jurassic sandstones with complex mineral composition. Thus, the knowledge of total water holding capacity connected with physical properties provides information about clay minerals in rock matrix and pore space. Physical properties of reservoirs with high value of the total water holding capacity differs to the lower ones. Fig. 3 illustrates relations between reservoir rock resistivity, effective porosity and total water holding capacity. Samples with high water holding capacity have low resistivity. So, changes in clayey cement mineral composition reflect on variation of bulk density, resistivity, absorption ability, wettability, etc., i.e. parameters that are measured with logs. Application of developed petrophysical model in log analysis techniques provides determination of clay minerals type [11]. 4. Thermal Field Influence on Formation Pressure Calculation Temperature correction is traditionally calculated according to the static geothermal gradient. Nevertheless, the real thermal field in the borehole can differ greatly from stationary geothermic data. Fig. 2 Clay minerals distribution for different water holding capacities of studied rocks. Fig. 3 The relation between rocks resistivity and effective porosity for different water-holding capacities. Authors investigate the thermal field formation in the vicinity of the borehole. Dynamics of the thermal field during drilling, well cleanout and well shutdown is studied. The temperature distribution over time after flushing out of well was surveyed within the radius of well logging methods study (Fig. 4). Temperature factor effect on the accuracy of formation pressure prediction with well logging data is determined. A modified normal clay compaction trend technique taking into account the nonsteady thermal field is developed. It involves the introduction of the correct temperature adjustment to electrical logging curves

4 Clay Minerals Properties as Downhole Formation Pressure Indicator 993 overpressure) were determined after drawing of normal clay compaction curve. Then pressures were calculated using developed technique. Results of pressure calculations are presented on the Fig. 5 as maps of formation pressure gradients values for Bazhenov sediments of Galyanovskoe oilfield. 5. Results and Discussion Fig. 4 Temperature variation over time in the radial direction after flushing out of well. R LLD, R LLS -radius of investigation of the deep and shallow lateral log. (lateral log, induction log) before the line of normal clay compaction tracing. Electrical logging diagrams lead to constant temperature (for example 20 o C). As a result, resistivity changes depend only on the value of the actual stress changing with depth. Temperature corrections are introduced using specially developed algorithm in log analysis software package. Then pure clays are determined in geological sequence with spontaneous potential log maximum data. Normal clay compaction trend is drawing usually at depth about meters according to electrical logging diagrams. Trend passes through minimal data of appropriate logs. Next formation pressures and overpressure coefficients are calculated with Eq. (1). Overpressure calculation algorithm was realized as a workflow. The implementation of improved normal clay compaction trend technique is carried out on data collected in sediments of Western Siberia Bazhenov formation. It was found that pressure gradient presents in formation, in other words pressure in the lower-lying formation is higher than in the cover one. Pressures for Bazhenov formation are calculated as average between pressures in underlying and overlying sediments. Requested intervals (above and below the zone of Modern techniques related with formation pressure prediction are analyzed. Their drawbacks are revealed. The normal clay compaction trend technique is improved with developed petrophysical model that differentiate rocks according to clay mineral composition of the cement and correct account of the downhole nonsteady thermal field in the vicinity of a Fig. 5 The map of pressure gradients in sediments of Bazhenov formation (Galyanovskoe oilfield).

5 994 Clay Minerals Properties as Downhole Formation Pressure Indicator borehole as well as in a radial direction. The example of algorithm practical realization on Bazhenov formation data shows validity of proposed approach. Algorithm is forced to predict formation pressure in workflow mode. Application of the research results in drilling and well planning may reduce risks and economical expenditures while deep wells construction and development. References [1] Holbrook, P. A. Petrophysical-Mechanical Math Model for Real-Time Wellsite Pore Pressure/Fracture Gradient Prediction. SPE paper presented at the 62nd Annual Technical Conference and Exhibition, Dallas, TX, Sept , [2] Leonard, R. C. Distribution of Sub-Surface Pressure in the Norwegian Central Graben and Applications for Exploration. In Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference, 1993, Parker, J. R., Ed.; The Geological Society: London; 1993; pp [3] Proehl, T. S. Pore Pressures, Fracture Gradients, and Drilling Economics. IADC/SPE paper 27493, presented at the IADC/SPE Drilling Conf., Dallas, TX, Feb 15-18, [4] Dobrinin, V. M.; Vendelshtein, B.Y.; Kozhevnikov, D. A. Petrophysics, Nedra Press: Moscow; 2004; pp (in Russian). [5] Buchan, R. High-pressure, high-temperature drilling: data management and interpretation, SPE/IADC paper 25764, Proc. Drilling Conf, Amsterdam, Feb 23-25, [6] Daines, S. R. Aquathermal Pressuring and Geopressure Evaluation. AAPG Bull. 1982, 66, [7] Dobrinin, V. M. Overpressure Prediction Methods, Nedra Press: Moscow; 1978; pp (in Russian). [8] Gaarenstroom, L.; Tromp, R. A. J.; de Jong, M. C.; Brandenburg, A. M. Overpressures in the Central North Sea: Implications for Trap Integrity and Drilling Safety. In Petroleum Geology of Northwest Europe, Proceedings of the 4th Conference, 1993; Parker, J. R., Ed.; The Geological Society: London; 1993; pp [9] Mann, D. M.; Mackenzie, A. S. Prediction of Pore Fluid Pressures in Sedimentary Basins. Mar. Petr. Geol. 1990, 7, [10] Ipatov, A. I.; Kremenetsky, M. I. Geophysical and Hydrodynamic Control of Oil and Gas Fields. Oil and Gas Press: Moscow; 2006; pp (in Russian). [11] Kozhevnikov, D. A.; Kovalenko, K. V. Macrodescription of Reservoir Residual Water Saturation. NTV AIS Karotazhnik 75, 2000 (in Russian).