Modular Dynamic Tester Research Articles

Detection of formation and dissociation of CO2 hydrates in fine-sands through acoustic waves

Natural gas hydrates in oceanic and permafrost sediments are considered a future energy resource. Injecting CO2 into these sediments is believed to aid in the safe and efficient extraction of CH4 and the geological sequestration of carbon. The effectiveness of this strategy can be ensured by assessing the formation of CO2 hydrates in the pores of these sediments at in-situ stress conditions by investigating their elastic properties (viz., compressional and shear wave velocities, elastic modulus, and shear modulus) by resorting to a suitable method such as seismic and/or acoustic logging. However, conducting such a study in field is seldom opted due to the requirement of expensive paraphernalia such as seismic equipment, pressure coring tools, logging while drilling tools, modular dynamic tester, etc. With this in view, efforts were made to synthesize CO2 hydrates in partially saturated fine-sands under triaxial conditions by employing the excess gas method. Ultrasonic wave transducers were employed in tandem to measure the compressional (VP) and shear wave (VS) velocities of the sample, both under formation and dissociation processes. These results have been utilized to propose hydrate formation and dissociation models which encompass three phases each. The rapid reduction in VP and VS observed during thermal dissociation indicates loss of cementation between the sand grains and hydrates, and commencement of hydrate dissociation at their interface. It has been demonstrated that the induction time for CO2 hydrate formation increases, and the water-to-hydrate conversion ratio decreases, with an increase in the initial volumetric water content. Further, the results generated in the present study were compared vis-à-vis those available in the literature for CH4 and CO2 hydrate-bearing sediments (HBS) and it has been found that both VP and VS of the CO2- and CH4- HBS are comparable for a given hydrate saturation.

Detection of Over Normal Pore Pressure Intervals by Using Well Logs

Pore pressure is very important parameter that impacting on drilling, production planning and operations. Drilling and production processes cannot be beginning if pore pressure is not estimated. There is a limit of difference between hydrostatic pressure of mud column and pore pressure during drilling to ensure that the layers are preserved from fracturing, as well as that kicking does not occur inside the well. Difference between pore pressure and bottom hole flowing pressure is a key for production process. Over (Abnormal) pressure intervals are causing many problems during drilling. In present study, pore pressure is estimated firstly as a hydrostatic pressure, and secondly, after determination of shale flag, two methods of Eaton slowness and Bowers original are used for detecting of over (Abnormal) pressure shale intervals. Compressional and density logs of three wells (X3, X4, and XD) located at Y oil field and producing from Asmari formation are used to perform the present study. Density log is linearly extrapolated to estimate bulk density from zero depth to last depth point at reservoir. Vertical stress is predicted for these three wells. The vertical stress gradients were 1.03, 0.99, and 0.93 psi/ft for XD, X3, and X4 wells respectively. Results are reveals that Bowers original better than Eaton slowness in detection of over (abnormal) pressure intervals where the last did not cut all shale intervals by compressional slowness shale base line that equal to 80 us/ft so, Eaton slowness method provided either very high over pressure in some shale intervals or subnormal pressure to other shale intervals and that inaccurate while Bowers original method approximately provided all shale intervals as over pressure in reasonable values. Modular dynamic tester measurements for pore pressure of these three wells are used for calibration. Maximum percent error between predicted and measured pore pressure of wells (X3, X4, and XD) are 1.2%, 0.89% and 3% respectively where these percent are very acceptable. Maximum over pressure values in Asmari formation zones at wells are as follows: 6328 psi at depth 3225 m in well X3, 7538 psi at depth 3080 m in well X4, and 6731 psi at true vertical depth 3067 m in well XD.

Application of a Modular Dynamic Formation Tester on a Wire Line to Refine the Filtration Characteristics of the Production Formations of the Magovsky Oil and Gas Condensate Field

An important task in monitoring the development of hydrocarbon fields is to obtain data on the filtration characteristics of reservoirs and the properties of fluids in reservoir conditions. When using standard logging in the complicated conditions of low-permeability formations, poorly consolidated rocks and eroded wellbores, it is very difficult to perform reservoir pressure measurements, sampling with a detailed analysis of fluid properties. A study was carried out in order to clarify the filtration properties of the rocks of the geological section by the method of hydrodynamic logging with testing of the formations by a tester on a MDT logging cable (modular dynamic tester). This problem was solved using the example of carbonate production formations of the Magovskoye oil and gas condensate field, which are generally characterized by a complex heterogeneous structure. An analysis of the effectiveness of using a modular dynamic reservoir tester made it possible to clarify the boundaries of permeable rock intervals with an assessment of their saturation. At the same time, working intervals of the geological section were established, which, with standard logging, were interpreted as dense rocks.

DETERMINATION OF PETROPHYSICAL PROPERTIES CUTOFF IN HETEROLITHIC RESERVOIRS IN MALAY BASIN

Thinly bedded sand-shale heterolithic are commonly found as a marginal reservoir in the Malay Basin. In the evaluation of heterolithic reservoirs, a key challenge is to determine the appropriate petrophysical properties cutoff. This study used the Modular Dynamic Tester (MDT) pressure tests to determine the appropriate petrophysical properties cutoff applicable to heterolithic intervals. Intrinsic permeability analysis and MDT mobility plots were used to determine the cutoffs for shale volume and total porosity. Subsequently, hydrocarbon pore volume thickness (with shale volume and porosity cutoff applied) was plotted against water saturation to determine the water saturation cut-off value. In this case study, the reservoir cutoffs applied are shale volume less than 60% and total porosity in excess of 12 %. The hydrocarbon pay cutoff was set at a water saturation less than 85 %.

Seismic reservoir characterization and pressure depletion of the Abu Madi Formation in the NW Khilala field, onshore Nile Delta, Egypt

The Late Messinian Abu Madi Formation represents the most prospective deep reservoir target in the Nile Delta. Hydrocarbon exploration in the Nile Delta over the last few decades has been targeted to understand the Abu Madi reservoir quality and distribution. The integration of rock physics, amplitude versus angle (AVA), seismic interpretation, seismic attributes, and seismic inversion could successfully determine the characteristics of the late Messinian Abu Madi Formation in the North West Khilala (NWKh) field, which is located in the central onshore part of the Nile Delta, Egypt. The NWKh field is located on the eastern margin of the Disouq concession close to producing the West Khilala (WKh) field, with highly heterogeneous reservoir parameters. The reservoir is classified as lacustrine turbidites deposited in semi-isolated Late Messinian Basins. The Abu Madi Formation can be subdivided into upper and lower sand members. It is very common that they are separated by an intraformational shale layer. AVA analysis performed on the top of the Abu Madi reservoir suggested a class 2p. Seismic data were inverted to delineate the overall lateral extent of the reservoir. The prestack inversion process was integrated with rock physics modelling of the wells to generate high-resolution multiple rock property models to characterize the reservoir and observe or investigate different pressure depletion trends. The pressure depletion of the lower Abu Madi in the North West Khilala field was investigated laterally and vertically by the relative/full spectrum inversion and formation modular dynamic tester (MDT) pressure data, respectively. This depletion is due to communication with the West Khilala field, which was produced from the Lower Abu Madi (LAM) sand interval in 2007.

4D Finite element modeling of stress distribution in depleted reservoir of south Iraq oilfield

The harvest of hydrocarbon from the depleted reservoir is crucial during field development. Therefore, drilling operations in the depleted reservoir faced several problems like partial and total lost circulation. Continuing production without an active water drive or water injection to support reservoir pressure will decrease the pore and fracture pressure. Moreover, this depletion will affect the distribution of stress and change the mud weight window. This study focused on vertical stress, maximum and minimum horizontal stress redistributions in the depleted reservoirs due to decreases in pore pressure and, consequently, the effect on the mud weight window. 1D and 4D robust geomechanical models are built based on all available data in a mature oil field. The 1D model was used to estimate all mechanical rock properties, stress, and pore pressure. The minimum and maximum horizontal stress were determined using the poroelastic horizontal strain model. Furthermore, the mechanical properties were calibrated using drained triaxial and uniaxial compression tests. The pore pressure was tested using modular dynamic tester log MDT. The Mohr–Coulomb model was applied in the 4D model to calculate the stress distribution in the depleted reservoir. According to study wells, the target area has been classified into four main groups in Mishrif reservoir based on depletion: highly, moderately, slightly, and no depleted region. Also, the results showed that the units had been classified into three main categories based on depletion state (from above to low depleted): L1.1, L1.2, and M1. The mean average reduction in minimum horizontal stress magnitude was 322 psi for L1.1, 183.86 psi for L1.2, and 115.56 psi for M1. Thus, the lower limit of fracture pressure dropped to a high value in L1.1, which is considered a weak point. As a result of changing horizontal stress, the mud weight window became narrow.

Permeability Estimation From stoneley Waves in Carbonate Reservoirs

Permeability is one of the petrophysical properties of oil and gas reservoirs and is defined as the ability of rock to transmit fluids through the porous media. After exploration of any reservoir, permeability information is necessary to optimize the well completion method, oil and gas production and field development. Permeability is determined by both direct and indirect methods. Direct methods are core analysis, well testing, and modular dynamic tester (MDT) and the indirect method is using well logging data such as nuclear magnetic resonance (NMR) and porosity. Determination of permeability from the Stoneley slowness is one of the indirect and continuous methods in the whole well-bore and has been chosen as the goal of this study. The result of this correlation has been plotted against other well logging data and there is a very good match between this result and other petrophysical properties. Due to the complex nature of permeability in carbonate reservoirs, most of the time there is not a good match between this parameter and other petrophysical properties. This study has been conducted on the data of a single well and correlation has been determined. The results show that in calculation of permeability from Stoneley waves, the effective parameters are porosity, lithology, Stoneley slowness and accuracy of the MDT tool. For more precise correlation in a reservoir or a specific geological area, more data from other wells or reservoirs are necessary.

Reservoir compartmentalization and fluid property determination using a modular dynamic tester (MDT): case study of an Algerian oil field

Compartmentalizing the reservoir and determining its initial properties are key steps in the development of an oil field. These steps are mainly performed to determine the number and types of fluids in the reservoir. They are also carried out to establish the initial reservoir pressure and reservoir potential. For each fluid zone, it is essential to identify the fluid present and its range. The oil reservoir examined in the present case study consisted of different zones with ambiguous fluid limits. Thus, the pressure gradients and variations in this reservoir were measured using a modular formation dynamics tester (MDT). This device can be employed to discriminate between formation fluids in real time. An analytical analysis of the measured pressure gradients allowed the reservoir compartments to be defined, taking into account the types of reservoir fluids present. The investigation also aimed to identify the initial reservoir conditions and establish the free water level (FWL) in each fluid zone. Thus, with similar setting, reservoir characterization and heterogeneity may constitute a key factor approach to be examined. The oilfield analyzed in this work, which is part of the Hassi Berkine basin in the Saharan platform (southeastern Algeria), has an anticlinal structure. From a sedimentological point of view, it consists of fluvial-continental deposits. Some erosional effects of the Hercynian unconformity influence the top of the Frasnian clays present. The main hydrocarbon reservoir is located in the Lower Triassic Clayey Sandstone (TAGI), the current name for the Triassic reservoir in the Sahara platform in the investigated area. The TAGI is divided into three levels: the upper TAGI (TAGI-U), middle TAGI (TAGI-M), and lower TAGI (TAGI-L). Data revealed several pressure gradients along the depth profile of each borehole section, implying significant changes in fluid properties. Substantial differences in pressure between oilfield boreholes (e.g., between the boreholes through TAGI-U+M and TAGI-L) were observed. The equivalent densities for the pressure gradients indicate that the fluid succession in the deposits is oil (TAGI-U+M), water (TAGI-M), and then oil again (TAGI-L). A stratigraphic barrier between TAGI U+M and TAGI-L was identified. By superimposing the pressure gradients observed in wells 1 and 2, two reservoir compartments were deduced. Furthermore, based on the pressure evolution with depth and the density record, two free water levels (FWL) in addition to the initial pressure were identified for the reservoir.

Numerical investigation for determination of aquifer properties in newly developed reservoirs: A case study in a carbonate reservoir

Aquifer strength is one of the main parameters in surface water separation facilities design. The material balance method is a common approach to calculate the aquifer strength and water influx in mature reservoirs which are in the second half of their lives. However, this method could not be used for green and newly developed reservoirs. In this type of reservoirs, the suitable vertically and laterally distance between aquifer and perforation intervals in the development wells is a main question which depends on future aquifer behavior. In this study, a methodology has been presented to estimate aquifer properties using water pressure data and also well testing data in a newly developed giant gas field in Middle East. The numerical sector model is used to match simulated water pressure data with actual MDT (Modular Dynamic Tester) data. The water relative permeability for each rock type and vertical-horizontal permeability relationship have been determined in history matching process. The tuned model can be used for the prediction of the aquifer performance and also the water production in future development wells.

PORE PRESSURE ESTIMATION IN HARD UNLOADING-OVERPRESSURE ZONE USING SINGLE COMPACTION EQUATION, CASE STUDY: LOWER KUTAI BASIN

Pore pressure estimation in hard-overpressure zone is very important in drilling activities. Correct and precise estimation are able to reduce the cost for drilling due to reduced non-productive time (NPT) and in increase in safety aspect while drilling. Pore pressure estimation is done by post-mortem analysis in exploration wells using validation points from pressure measurement data such as Drill Stem Testing (DST), Modular Dynamic Tester (MDT), and Repeat Formation Tester (RFT). A wireline logs data used for identification of the type of overpressure and predicts pore pressure magnitude in the shale section. Through the correlation between effective-stress and velocity, a single compaction equation was obtained for the Lower Kutai Basin with the value of : 5.097 * ? 0.854. By using this single equation, pre-drill pore pressure prediction activity will be more easy and could estimate pore pressure in hard-overpressure zone precisesly.

DETECTION OF HYDROCARBON, BY USING ADVANCED WELL LOG TOOLS FOR KAFR EL-SHEIKH FORMATION AT SAPPHIRE FIELD, OFFSHORE NILE DELTA, EGYPT

The present work is devoted to study the geologic setting, reservoir characterization and hydrocarbon detection with conventional and advanced well log methods for Kafr El-Sheikh Formation at Sapphire field, Offshore Nile Delta, Egypt. The used wells are Sapphire-Da, Db, Dc, De, Dh and Dq. By using open hole logging tools, advanced logging tool like Modular dynamic tester (MDT), Mud log during drilling and conventional core that analyzed carefully, to detect the clean sandstone and thin bedded sandstone of the study Location. These basic well log tools (Gamma Ray, Resistivity, Density and Neutron) reflectclean sandstone reservoir with good way, but can’t detectthin bedded sandstone reservoir, as a result of their low vertical resolution, this may miss several intervals charged with hydrocarbons during perforation and production from the field.So, we should run advanced tool like the Modular Dynamic Tester (MDT) and analyze conventional core, if found, and the hydrocarbons in Mud log to detect these missed intervals. Also by using the conventional cores and mud logging while drilling. The results had showed clean sandstone and thin bedded sandstone reservoirsthroughthe advanced well log tools, which identify more than 68% deep water reserve didn’t use beforethis should be takeninto consideration in the future wells, workover wells, excellent distribution of facies in both the static and dynamic models, to increase the hydrocarbon production and life time of producible wells. . The optimum location for forthcoming wells is south west of the field, because it has the best petrophysical parameters. It has high porosity, hydrocarbon saturation, and net to gross, in addition to low shale volume.

Seismic and petrophysical evidence of abnormal pore pressure in western Niger delta

A detailed pore pressure evaluation of Tango Field, western Niger Delta, was carried out with the aim of ascertaining depth to overpressure which enables proper well planning and designing in order to reduce cost of exploration and exploitation. The evaluation was carried out using both petrophysical data consisting of sonic, density and resistivity logs obtained in five wells drilled in the area and high resolution-seismic reflection data from which the average and interval velocities were computed. Crossplots were made for well logs data which were fitted with regression curves, and trend lines in order to establish overpressure patterns. Plots of overburden, fracture and hydrostatic gradients with leak off test (LOT), mud weights and modular dynamic tester (MDT) were made to validate the trends established from the crossplots. The results obtained show that normal compaction trends (NCT) were established for all the data used in the analysis and all the wells except well 5 which showed obvious deviations from these trends. Well 5 encountered overpressure at 8,000 ft which was considered earlier than anticipated, hence, it was abandoned. Top of overpressures for wells 2 and 4 were estimated between 9,000 ft and 12, 000 ft respectively. Porosity versus vertical effective stress from the plots confirmed the above depth to overpressure which reveals that the overpressures are primarily generated by disequilibrium compaction.

Overpressure zone under the Krishna–Godavari offshore basin: geophysical implications for natural hazard in deeper-water drilling

Accurate knowledge of pore pressure is fundamental to any safe and economic well construction. Here, we present results that are indicative of over pressure zones (OPZ) for five wells drilled under the Krishna–Godavari offshore basin (KGOB) at the Eastern Continental Margin of India (ECMI). OPZ in areas of crustal flexuring can act as potential geohazard while drilling. These wells locate at water depths of 515–1,265 m, where their penetrated-vertical-depth reaches up to 3,960 m in clastic sediments. pore pressure gradient (PPG) and fracture pressure gradient (FPG) are estimated from acoustic log for all five wells, while the Normal Compaction Trend (NCT) and pore pressure are calculated from Miller’s sonic equation. Top of OPZ is indicated by values that are higher than the NCT; departure from NCT is observed at depth intervals of 1,320–2,180 m, 1,700–3,960 m, 1,600–1,880 m, 1,420–2,609 m and 2,080–2,200 m for the respective Wells 1 through 5. The pressure data from Modular Dynamic Tester (MDT) agree well with the pore pressure values obtained from the logs. The Overburden Gradient (OBG), PPG and FPG values increase rather slowly with total depth in deeper-water of KGOB when compared to the wells located in shallow water depth. Consequently, the operating safety margin between PPG and FPG decreases as the water depth increases, and this clearly leads to an increase in the number of casing strings to reach the target depth. Certain basic conclusions on the potentiality of natural hazard for drilling operations are drawn on the basis of these results, but evidently, further studies are warranted to present a more composite picture of OPZ under KGOB.

Estimation of Near-Wellbore Alteration and Formation Stress Parameters From Borehole Sonic Data

Summary Highly depleted reservoirs exhibit sharply lower pore pressures and horizontal stress magnitudes than does the overlying shaly formation. Drilling through such depleted reservoirs can cause severe fluid loss and drilling-induced wellbore instability. Accurate and reliable estimates of horizontal stresses can provide an early warning of impending drilling problems that may be mitigated by appropriate drilling fluid design and drilling practices. We have developed a new multifrequency inversion algorithm for the estimation of maximum and minimum horizontal stress magnitudes using cross-dipole dispersions. Borehole sonic data for the case study presented in this paper was acquired by a cross-dipole sonic tool in a deepwater well, offshore Louisiana in the Gulf of Mexico (GOM). The logged interval spans 1,000 ft below the casing shoe. In addition, the Modular Dynamic Tester (MDT) (©Schlumberger) minifrac tests were performed at three depths in shale, thus yielding two minimum horizontal stress magnitudes. The borehole sonic data were suitable for the inversion of crossdipole dispersions at three depths in shale, as well as at a depth in a highly depleted sand reservoir. There was one depth in shale above the depleted sand where we could estimate the minimum horizontal stress magnitude with both the MDT minifrac tests and inversion of borehole sonic data. The results of the two techniques are consistent, providing encouragement for further validation of the multifrequency inversion of cross-dipole dispersions to estimate horizontal stresses. Even though the overburden stress is expected to increase with depth, both the maximum (SHmax) and minimum (Shmin) horizontal stresses obtained from the inversion of borehole sonic data are significantly smaller in the depleted sand than in the overburden shale. However, both the horizontal stress magnitudes increase again in the shale below the depleted sand. Such rapid variations in horizontal stress magnitudes cause large fluctuations in the safe mud-weight window. This challenge in drilling through the depleted sand was successfully handled by using special drilling fluid to mitigate seepage losses and the differential sticking in the depleted sand and overlying shale. We have also performed dipole radial profiling (DRP) of formation shear slownesses using the measured cross-dipole dispersions at three depths in shale and one in highly depleted sand. Analysis of radial profiles in the two orthogonal directions indicates plastic yielding or stiffening of rock in the near-wellbore region. While plastic yielding increases the shear slowness, stiffening would reduce the shear slowness.