25th - 26th September, 2019
The symposium program is available to download here. You can read abstracts of the symposium also here.
Now we accept pre-registration. Please read instraction in Symposium Program and send pre-resigration rorm within the program, or word file here. The dead line of pre-registration is 9th September.
The 25th Formation Evaluation Symposium of Japan will be held at Japan Oil, Gas and Metals National Corporation - Technology & Research Center (JOGMEC-TRC), Chiba on September 25-26, 2019. All persons involved in oil, gas, geothermal, geo-engineering industry and scientific drillings are invited to submit abstracts of papers for presenting at the symposium.
The special session for this year's JFES symposium is "low carbon emission energy".
It appears obvious that the market expectation for the energy that has lower impact on environment is expanding, while the demand on fossil fuel is still sustains. On the occasion of the 25th anniversary of JFES, the symposium provides petrophysicists, geologists and engineers with an opportunity to share the knowledge and experience between the two energy sectors apparently opposes each other under the special session. In addition to the related topics such as methane hydrate, CCS and geothermal technology, the symposium would cover a wide area of formation evaluation, including reservoir characterization, geophysics and geomechanics applications, scientific drilling and new tool/new technology.
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The needs of the world electricity, especially in Indonesia, is increasing along with population growth, consumerism, and technological advances. Furthermore, to fulfill the needs of electrical energy in Indonesia, which still relies heavily on fossil energy use might cause many losses, especially to the environment. Geothermal energy is one of the renewable energy and the right choice in today's global sustainable development due to low carbon emissions. Indonesia has 40% of all geothermal potential in the world with potential resources of 11,073 MW, reserves of 17,506 MW, and the total energy of 28.579 gigawatts (GW). Geothermal energy potential in Indonesia is widespread in areas that traversed by the ring of fire or areas with active volcanic activity, one of them is Mount Tangkuban Perahu in West Java. The surface geothermal potential has known from surface manifestations which appear in the form of fumaroles, hot spring, mud pools, steaming ground, sinter, kaipohan, and hydrothermal alteration. If there are surface temperature anomalies, could be identified as manifestations. It is possible to identify areas that have the potential of geothermal energy based on their surface relief through remote sensing. Identification of anomalies obtains through the processing of Landsat 8 satellite imagery using thermal bands 10 and 11 with Thermal Infrared (TIR) sensors. Remote sensing is very effective in identifying manifestations and potential of geothermal energy because it can cover data on a wide area, time, and cost efficiency. In addition to fluid manifestations, remote sensing can also identify the distribution of minerals in areas to estimate the reservoir characteristics of a geothermal system. This study aims to estimate the geothermal reservoir characteristics in Mount Tangkuban Perahu area that used as an initial consideration in geothermal exploration and further geothermal research in other areas. The methods use in this research are Split-Window Algorithm (SWA) to find the distribution of manifestations, calculations of Radiative Heat Flux (RHF) to obtain an estimation of geothermal resource potential, and Supervised Classification Method (SVM) to identify the distribution of the minerals. The results will provide information about surface temperature and heat losses based on anomalous manifestations, estimation of power electricity resource, lineament, and a conceptual model of Mount Tangkuban Perahu geothermal system.
This study is aimed to discuss the feasibility of a new utility of the combination of mini-frac test and acoustic emission (AE) monitoring for the identification and delineation of pre-existing fault/fracture with exceptionally high permeability in the vicinity of the well. In particular, geothermal field exploration often targets such natural fault/fracture zone, because of the high permeability expected based on the assumption of open fracture aperture, which is favorable for large amount of steam production. However, the drilling success rate is only around 30 percent, which could be resulted from the limited spatial resolution of conventional geophysical exploration method used in geothermal development, such as gravity, resistivity and magnetic method. More accurate exploration method for permeable fault/fracture delineation is required.
Mini-frac test has been widely conducted in the oil, gas and/or geothermal field, which is mainly aimed to measure some kinds of initial state in the target formation, such as in-situ stress and pore pressure, usually before the massive hydraulic fracturing operation. Furthermore, if AE was monitored during the mini-frac test, the spatio-temporal hypocenter distribution could potentially help to estimate the dynamic behaviors of fracture extension or pressure diffusion. However, a relationship between the spatio-temporal hypocenter distribution and the existence of high permeable fault zones is not clearly understood. For an instance, aseismic zones show high permeable fault zones or not. This is because complex factors such as pumping rate, pumping volume, fluid-flow capacity of the path from well to the permeable fault zones and fluid-flow capacity of the permeable faults themselves are mutually affected.
Hence in this study, parameter sensitivity test on some sets of pumping parameters and geological parameters is conducted by using a numerical fracturing simulator “SHIFT”. The simulation model was constructed based on actual field data acquired at the Hijiori Hot Dry Rock (HDR) site, Japan, and also some uncertain parameters are carefully tuned by matching the simulated fracturing pressure to the actual pressure response observed while the hydraulic fracturing operation conducted at the site. Consequently, the numerical simulation test suggested that the pressure diffusion arrival at the target fault with a certain rage of permeability could be detected by drastic pressure drop and a series of AE events occurrence along the fault. These observations could make it possible to identify the pre-existing exceptionally permeable fault/fracture structures.
Although the reservoir simulation is widely utilized to predict geothermal reservoir performances, the results of the simulation are sometimes different from those actually observed in field operations due to non- equilibrium conditions and poor modeling of fracture system. For example, the recharge water sometimes reaches producing wells much earlier than predicted by reservoir simulation. Therefore, in this research, we attempted to develop a numerical simulator that can deal with the non-equilibrium vaporization of water and condensation of steam for predicting geothermal reservoir performances more accurately. We also attempted to construct the model which can rigorously express the main flow paths such as faults and/or large scale fractures.
First, we developed a three-dimensional simulator that can predict the flow behavior of geothermal fluids in the non-equilibrium state. Conventional geothermal simulators solve the only material balance equation for all the water molecules regardless of the phase condition. On the other hand, in the simulator developed in this research, water molecules in the liquid phase are distinguished from those in vapor phase, and the two material balance equations are derived for water and steam separately. These equations have the terms to express the molecular transportation from steam to water and vice versa. Non-equilibrium vaporization and condensation of water molecules are expressed by adjusting the kinetic rate of transportation of water molecules across phases.
Next, we expanded the functions of the above simulator, incorporating two types of double porosity models, Kazemi and MINC, and EDFM (Embedded Discrete Fracture Model), to reproduce the fluid flow preferentially through fractures and faults. EDFM is the discrete type of fracture model assuming non- neighboring connections with regular grid, and is useful to calculate the flow through narrow paths even if their apertures are small and/or their directions are not parallel to the grid surface.
After verifying the simulator functions, we investigated how the non-equilibrium condition and fracture properties affected the geothermal reservoir performances, especially those with recharging water. Case studies revealed that the non-equilibrium condition hastened the movement of the water injected as recharge water through fractures, which resulted in the water breakthrough earlier than predicted by conventional (equilibrium type) simulators. Case studies also suggested that it was crucial to appropriately estimate fracture properties through the history matching by using ILHS method because fracture is a main path for fluid flow. Finally, we concluded that this simulator could successfully handle the fluid flow through faults/fractures which improved the reliability of prediction.
In order to develop, test, and improve technologies and techniques for the creation of sustainable EGS (Enhanced Geothermal Systems), FORGE (Frontier Observatory for Research in Geothermal Energy) project has been led by U.S. Department of Energy. Since the abundant datasets for both geology and geophysics are available, we can prepare the conceptual 3-D geologic model by integrating them. In this study, we report the preliminary results of numerical simulation on the hydraulic stimulation response at this candidate site. We first design the discrete fracture network for the region of 1200 × 800 × 800 m volume, which includes approximately 2000 fractures. Then we explore the responses during hydraulic stimulation via the “SHIFT” based simulator. A series of stimulations are performed in six stages/zones along the horizontal well and both low (5 kg/s) and high (80 kg/s) injection rates are specified in order. In our simulations, the ratio of stimulated (slipped / sheared) fractures volume to total volume of pre-existing fractures are evaluated to be 1~2%. On the other hands, this parameter has been evaluated to be 10~20% by U.S. group, who adopt DEM (distinct element method) based simulator. Such a large discrepancy may be attributed to whether the propagation of newly created fractures is adequately taken into consideration or not.
Our previous studies on fracturing in granite at 200°C to 450°C under triaxial stress condition revealed that infiltration of low viscosity supercritical water stimulates preexisting fractures and creates dense fracture networks which is favorable for enhanced extraction of geothermal energy (Watanabe et al., 2017, Geophys. Res. Lett.; Watanabe et al., 2019, Sci. Rep.). Presently, fracturing experiments have been carried out at similar conditions to examine feasibility of supercritical CO2 adoption having low viscosities, for application at various geothermal conditions.
Fracturing experiments were conducted on cylindrical Inada Granite samples at 200°C and 450°C, with a range of differential stress, where supercritical CO2 was injected at 1 ml/min. At 200°C, 90MPa axial stress and 40MPa confining stress were applied. Meanwhile at 450°C, 90Mpa axial stress with 40MPa or 25MPa confining stress were applied. As a result, 50MPa breakdown pressure was observed at 200°C. At 450°C, 47MPa and 16MPa of breakdown pressure were observed for the experiment with 40MPa and 25MPa confining stress respectively. As the theory predicted that in the case of nonpenetrating fluid, breakdown pressure will be approximately twice the magnitude of confining stress, these low breakdown pressures indicated fluid penetration. Furthermore, borehole pressure profiles suggested that pore pressures were close to borehole pressure. In addition, X-Ray CT on the samples revealed that complex fracture patterns were developed.
It has been discovered that in this study, stress state at breakdown events are close to Griffith’s Fracture Criterion. The low viscosity of supercritical CO2 has allow stimulation of preexisting fracture so that the rock failed in accordance to Griffith theory, in which fracture generated in various direction involving extensional, extensional-shear, and shear modes. Hence, favorable complex fracture patterns were generated.
This experimental results demonstrate the possibility of supercritical CO2 use to replace water in fracturing application at wide range of geothermal conditions, due its capability to return low breakdown pressure, induce dense fracture network, as well as to sequester CO2 to some extent at the same time.
As for CCS (Carbon dioxide Capture and Storage) reservoir survey to select optimum location, capability and capacity of CO2 gas storage of subsurface aquifer formations are major properties of concern. Target intervals extend from permeable reservoir rocks to top seal formations. As reservoir generally covers extended aquifer area, accurate formation evaluation is indispensable by referring well data in existing nearby wells for judging to select candidate field.
Well log interpretation conducted for the representative well drilled at offshore Japan will be introduced as a case study. The wells were drilled in 1990s for surveying potential of deeper hydrocarbon accumulation, and sufficient suite of conventional logs and geological information are available. The CCS target reservoir zones consist of sandstone, volcanic tuff and silty mudstone deposited as turbidites at different stage and sedimentary environment in the regional post lifting stage.
Followings are the contents of preliminary well survey: (1) facies and depositional environment, (2) shale and grain matrix properties, (3) shaly sand or thin-bed sand analysis and porosity, (4) permeability, (5) net reservoir, and (6) well tying with seismic reflection. Proposals for new data acquisition are to be included for future test wells.
Many logging services and methodologies have been applied to evaluate gas (or CO2) in formation in past decades. Measurements of resistivity, acoustic, thermal or epithermal neutron porosity, neutron capture, bulk density and NMR are mostly used, which some of them are for open hole only, some can be run in cased hole but with limitations due to down hole environments or formation properties.
In recent years a new formation property, the fast neutron cross section (FNXS), was introduced in the industry. It is an independent measure of the formation’s ability to interact with fast neutrons, which physically is proportional to the total atom numbers in unit volume of formation. It can be measured in cased or open hole, sensitive to gas and effective for differentiating gas or CO2 from rock matrix or liquids filled in pore, such as oil and water.
In this paper we firstly reviewed the approaches often used for gas evaluation and introduced FNXS briefly. With a forward formation model simulating shaly tight sand, we analyzed the effectiveness and sensitivity of FNXS to gas, as well as the effect on saturation resulted by possible error of porosity or shale volume. Field case studies were presented in the paper, showing 3 ways to interpret gas in formation with help of FNXS: quick look of FNXS overlaid with other logs, cross-plotting in chart and quantitative gas volume calculation with linear volume models. The feasibility of FNXS monitoring CO2 in EOR or CCS projects was also discussed.
Petrophysical formation property evaluation is the essential for any type reservoir characterization workflow including methane hydrate (MH) reservoir. The conventional workflow is sometimes hard to be applied on MH formation because of the unique characteristic of MH deposition formation. Archie’s law with resistivity measurement has been widely used and NMR based method is another well-known approach for MH saturation evaluation. There are always uncertainty coming from the limited vertical resolution and the quality of measurement due to hole condition. Thus, we have attempted to evaluate MH saturation in the study area using the other approaches. 1) Formation resistivity derived from borehole image log to understand MH saturation in high resolution 2) Formation sonic log based on the rock physics model.
A part of the MH formation consists of fine-grained, thinly bedded, silty sandstones and siltstone which were deposited in a turbidite setting in the study area. The conventional resistivity log is affected by the thickness of layers, which is lower than the vertical resolution of measurements. To overcome this challenge, we derived high-resolution formation resistivity log from the processed borehole image log and succeeded to reasonably evaluate MH saturation of each layers. The result showed higher MH saturation in thinly bedded formation and consistent result in the relatively thick formation comparing to the result from conventional resistivity log.
Acoustic property of MH is faster than the formation fluid, because MH is deposited in the state of ice-like hydrocarbon under in-situ condition. Thus, sonic well log shows relatively fast where MH is deposited. The several rock physics models had been proposed for MH formation in the past study (e.g. Lee and Collet, 2009). In this study, we used Simplified Three-Phase Biot-type Equation (Lee, 2008) and succeeded to evaluate MH saturation using sonic log. The built rock physics model will be a key input for the further seismic scale rock physics study.
This study was conducted as a part of the activity of the Research Consortium for Methane Hydrate Resources in Japan [MH21 Research Consortium] as planned by the Ministry of Economy, Trade, and Industry (METI), Japan.
We have developed a tool to drill core samples which is recording in-situ stress information around a bottom of a borehole. When the core is cut from the bedrock, it is released from the in-situ stress and expands slightly in the radial direction. Using this principle, the in-situ stress can be determined from the elliptical shape of the core cross section (Funato & Ito, 2017). However, the difference between major and minor axes of the ellipse only provides the difference between the maximum and the minimum in-situ stress, and the magnitude of each cannot be determined. This is because the core diameter d0 before expansion is unknown. To solve this problem, we proposed the coring procedure using the "Dual core-bit tool" so that the shape before expansion is retained in part of the core. That is, after digging a groove (outer groove) in the borehole bottom by the outer core-bit, cut a smaller diameter core by the inner core-bit in a same way as a normal coring. As a result, the shape before expansion remains in the upper part of the core, and the shape should expand due to stress relief in the lower part deeper than the outer groove. According to this concept, we made a prototype of the dual core-bit tool and conducted the first field test at Kamioka mine in Gifu, Japan. This paper describes the mechanism of the tool and the results of the field test.
In situ rock strength with depth under the ground/seafloor is a critical parameter for various studies in resources exploration, geology and seismology. The measurements on rock/core samples, however, have been hardly done with success due to the lack of drilled cores and sufficient knowledge about the in situ conditions such as pressure and temperature. We proposed a new indicator of the strength, equivalent strength (EST) developing previous mechanical parameter (Mechanical specific energy: Teal, 1964) from the oil industry, which is converted only from drilling performance parameters; drillstring rotational torque, bit depth and drillstring rotational per minute. The data processing was applied to the data taken from the advanced drillship Chikyu in her challenging scientific expeditions under International Ocean Discovery Program (IODP) and exploration drilling in the Indian National Gas Hydrate Program (NGHP). The depth profiles of the EST in these expeditions indicate that the rock strength does not simply increase with depth and that EST changes according to strata and structure. For example, EST significantly increases at the hydrate-bearing zones, suggesting EST can be an indicator of cemented structure such as hydrate-bearing zone. In order to correlate EST with conventional strength unit, drilling experiments using a high-speed friction tester were performed in the laboratory.
Stainless-steel drill bits fitted to the apparatus were manufactured, and a standard rock (Indian sandstone) was drilled at a rotational speed of 0.001 to 0.2 RPM under normal stress of 0.2–1.0 kN (equivalent to 1.6 to 8.1 MPa). Drilling torque and penetration speed at each condition were measured. The mean EST calculated based on the recorded drilling data was 90.5 MPa, which is comparable to the uniaxial rock strength of the standard rock, 106.8 MPa. No significant influence of rotation speed on EST was found in the experiments. The drilling experiments were conducted on several types of sediments likewise the sandstone, and it was confirmed that EST showed a good correlation with strength of each specimen.
In these days, low salinity water flooding (LSWF), which injects the water of low salinity ranging from 1,000 to 5,000 ppm (LSW) into a reservoir, is attracting attention as one of the enhanced oil recovery (EOR) technologies. Since this method is environmentally friendly and its capital and operation costs are lower than those of other EOR methods, a variety of research has been attempted to elucidate LSWF. Decisive theory, however, has not been established yet due to the complexity of LSWF. So, we tried to develop the numerical simulator that enables to reproduce the LSWF process, aiming at the rigorous investigation of the mechanisms of LSWF through numerical simulation.
Prior to developing the simulator, we focused on some mechanisms proposed on LSFW, especially on the cation exchange as one of the main contributors. In sandstone reservoirs, as LSW is injected into a reservoir, the concentration of cations in water phase decreases, and then the cations, especially Ca2+ combining with polar-oil, originally adsorbed on the clay minerals begin to be replaced with H+. Along with the detachment of Ca2+, polar-oil is also detached from the clay surface and the rock wettability changes from oil-wet to water-wet. Furthermore, the increase in differential pressure was observed during LSWF in the past core-flooding experiments, which may have been caused by wettability alteration and fine/micro-emulsion migration. On the contrary in carbonate reservoirs, crude oil is directly attached on the rock surface because it is positively charged. Along with LSWF, the adsorption of SO42- ion is promoted and hence ionic bonds between crude oil and rock surface are cut off, which results in the recovery of additional oil.
We developed the pseudo multi-compositional simulator, which can deal with 1-dimensional, 3-phase (oil, water and solid) and 19-component (non-polar oil, polar oil, sand, H2O, NaCl, CaCl2, MgCl2, H2CO3, CaCO3, MgSO4, H+, Na+, Ca2+, Mg2+, OH-, SO42-, Cl-, HCO3-, CO32-) problems, for accurately predicting the oil recovery by LSWF in both sandstone and carbonate reservoirs. The functions to calculate chemical reactions (ionization), adsorption/desorption of ions, diffusion of cations and fine migration were also incorporated. After developing this simulator, we verified the functions of this simulator comparing the simulation results with analytical solutions and/or those by commercial simulator. Then the results of past core-flooding experiments were successfully reproduced using this simulator. This study revealed that the cation exchange, wettability alteration and mineral dissolution were the key mechanisms in LSWF.
Low-salinity EOR has emerged as a cost-effective and an environmentally friendly EOR technique. However, there is no consensus about the definitive mechanism of the EOR effects even though a lot of researchers have been trying to clarify (e.g. Austad et al., 2010), because the dominant mechanisms might strongly depend on the properties of oil, water and rocks. And also, there are only a few papers referring how to conceptually evaluate the feasibility of low-salinity EOR in the full-field scale based on the laboratory and simulation studies. Therefore, this paper presents the case study of the field application of low-salinity EOR for the clastic reservoir integrating laboratory tests, field-scale reservoir simulation and facility design.
In the laboratory tests part, three coreflood experiments by tertiary low-salinity water (LSW) injection were conducted with the stock tank oil, the reservoir cores and the synthetic waters. Consequently, 2~17% of additional recovery factor (RF) were achieved with the differential pressure (DP) comparing to the secondary high-salinity water (HSW) injection. In terms of chemical reactions, divalent cation concentration in effluent was lower than that of injected water while monovalent cation concentration increased in all cases. Besides, pH increased by one unit comparing to that of injected water with appearance of emulsions. These experiments and the pore size distribution by NMR suggest that the emulsification is the key to clarify the EOR effect in this reservoir.
At the first step of the simulation study, the LS relative permeability curves acquired from coreflood experiments were assigned to the black-oil reservoir model, on which the EOR effect such as RF and DP during the tests were reflected guided by the permeability distribution. Besides, the water treatment capacity of the desalination plant proposed by Takahashi et al., 2018, which is composed by reverse osmosis (RO) and nano-filter (NF) membrane in parallel, were considered as the simulation constraint. As the results, 3.5% of RF was achieved comparing to the HS case in the secondary recovery, but only 0.4% of RF over the HS case was increased with the constraint of water treatment capacity. This result suggests that install of the desalinating system to the existing platform, the extension of platform and facilities such as water intake system is significantly important.
This paper will provide not only the EOR mechanism by LSW from the unique point of view but also the conceptual feasibility study of this EOR technique for the offshore fields.
As the development of directional drilling technology, more and more appraisal and development wells in South China sea are drilled with high inclination which can reduce the rig mobilization cost, maximize the trajectory footprint in reservoir and improve the project CAPEX. At the same time, the formation pressure measurement plays an important role in the reservoir description and completion design. Because the formation pressure acquisition takes stationary time, the conventional cable-conveyed technology cannot fully meet the operation requirement. Therefore FPWD (Formation Pressure While Drilling) technology is developed to fit for the needs from such high inclination wells.
FPWD technology essentially takes probe, setting piston, precise pressure gauge built into a collar which can be compatible with all other LWD (logging while drilling) tool. When taking the pressure measurement, the setting piston can push the whole tool to contact the borehole wall and create a fully sealing volume between tool and formation pore. Then the probe draws the fluid to create the pressure re-equilibrium which will be recorded by the pressure gauge. Formation pressure is then derived from the pressure recording there. In order to minimize the stationary time and reduce risk, the semi-artificial-intelligence approach within tool is also developed to automatically choose acquisition parameters within preset time limit.
With the enabling of formation pressure measurement from FPWD technology, various applications have been tried in high inclination appraisal and development wells in South China sea. It includes reservoir energy depletion profile determination, fault sealing determination and artesian gas injection optimization etc. FPWD provides the critical information for the reservoir description and production enhancement in South China sea.
A brownfield adjustment project was initiated by China National Offshore Oil Corporation (CNOOC) in 2014 to improve the production and further increase its reserve recovery from Huizhou 25-8 oilfield and Xijiang 24-3 oilfield in the South China Sea, also known as the Xijiang 24-1 District joint development project.
New development wells were drilled targeting at the remaining less than 5m thin oil column or pursuing highly heterogeneous sand bodies. The re-development and exploiting of these targets present operational challenges with increasing complexity. Not only the horizontal well needs to be optimally placed within complex target zone, the lateral also needs to be placed as close as possible to the reservoir top to keep it away from the unknown current fluid contact. Real-time evaluation of the horizontal section is needed to steer the well following better sand quality when formation properties changes laterally. Considering all the challenges presented, the team must ensure each well can achieve the target productivity index to attain technical and economic success.
Multiple cases will be discussed in the paper based on 34 wells drilled since the launch of this joint development project. Several key outcomes that have been observed will be highlighted, including: -Selection of logging tools to address well specific challenges
Based on the well performance result obtained from this re-development project, the implementation of the best practices in operation is the key enabler to effectively place the trajectory in the best place to drain the remaining hydrocarbon that lead to maximizing the late-life value of a mature oilfield.
High angle development wells in West Africa were drilled through complex channel systems to drain undeveloped reserves. This paper reviews the application of advanced geosteering technology, with potential depth of investigation of more than 30 meters, to map reservoir channels and contacts, coupled with conventional LWD to effectively map and skewer the channels to potentially double or triple well productivity.
Extensive pre-job modeling is performed from existing offset well log data, coupled with expected geological structure, and surface seismic. The model accounts for well trajectories, reservoir conductivity contrasts, bottom hole assemblies (BHA) and tool acquisition frequencies. The model indicates the extent that Deep Directional Resistivity (DDR) technology can successfully map in Real Time (RT) in multiple, structurally complex channel sands. This data combined with conventional LWD and Formation Pressure While Drilling transforms the data into a multidimensional model allowing mapping of the reservoir.
This study shows the transformation of a seismic cross section, showing two bright amplitude targets transform into a stacked sandstone channel complex while drilling in real time with the application of DDR. The channels were mapped up to 27m TVD away, where seismic uncertainty is + / - 20m.
Integration of reservoir pore pressure measurements indicated differential depletion between sands, defining vertical pressure baffles and adding a further dimension to the reservoir map while supporting the multidimensional channel model as defined by the DDR.
The results reduced reservoir structural uncertainty, enabling enhanced understanding of the reservoir body to improve producibility and understand depletion profile. A key highlight of the study was the use of a recently developed, more advanced DDR inversion that significantly increased reservoir resolution and thin layer delineation.
Precise landing operation is critical for horizontal well placement. Conventionally, the operators rely on the real-time logging while drilling which used to confirm the markers above target formation according to offset wells correlation, combine with surface seismic data to predict the depth of target zone, optimize the trajectory plan and ensure accurate landing.
However, few offset wells information, no clear markers above target formation, poor quality seismic data, uncertainty of lateral sand body distribution and unstable disturbance layers above target zone etc. further increase the risk of landing operation.
This paper will feature the successful landing using innovative logging while drilling technology. This innovative solution reduces uncertainties of structural depth and formation properties by forecasting the formation boundaries using ultradeep resistivity measurement and upgraded inversion method. The how-to- execute of the well placement will be detailed through the description of the case encountered.
The operator has observed the outstanding result from the application of the innovative technology during landing operation:
The successful implementation of the ultra-deep high definition reservoir mapping while drilling measurements leads to improve drilling efficiency, reduce cost and mitigate drilling risk for landing operation. In addition, the ultradeep mapping capability of the service can help delineate the reservoir profile with more accurate models and help to understand the complex subsurface conditions.
For directional wells in a Jurassic formation, the 6-inch production sections that are normally drilled in the Marrat reservoir require several separate wireline logging (WL) runs and associated borehole conditioning trips for complete petrophysical interpretation and completions design.
As planned well inclinations increase to maximize sweep, the need for deploying WL tools via drill pipe poses significant challenges due to the high risk of losing the bottom hole assembly (BHA) in the hole due to differential sticking. Over time, logging while drilling (LWD) tools became preferable for the gas team, where the tools are either run with the actual drilling BHA or on a dedicated wiper trip after the section has been drilled to total depth (TD). Utilizing LWD tools in this application also reduces well delivery times and costs. A comprehensive logging solution was required to drill the 6-inch reservoir section of a study well. The complex LWD string consisting of gamma ray, resistivity, neutron porosity, azimuthal density, azimuthal sonic, and nuclear magnetic resonance (NMR) tools was deployed on a motorized rotary steerable system (MRSS) BHA. In addition, a prototype high-resolution acoustic imaging and caliper tool, designed to be run in both water and oil-based mud (OBM), was also utilized in the same BHA. The acquired logging data was utilized for enhanced formation evaluation. Fracture and borehole breakout interpretation from image data played the key role in successful completion design.
This ultimately led to Kuwait’s first successful “Hexa Combo” LWD drilling run and the world’s first LWD imaging tool run in OBM in this hole size with 13.3 ppg OBM with a maximum downhole temperature of 275°F.
The onshore Nakajo oil and gas field in Niigata Prefecture is composed of three different types of hydrocarbon accumulations: non-associated natural gas, natural gas dissolved in water (GDW), and black oil. The natural GDW is produced together with formation water as gas in solution (GIS) under in-situ condition. While the formation water is lifting to surface, the natural gas is separated from the water. With this reason, well log response from GIS sandstone was believed to be almost the same as normal sandstone which does not contain any hydrocarbon.
In the recent in-fill well drilling campaign for GDW reservoir, the full suite of wireline logging was carried out. With a success of good quality data acquisition, an advanced sonic and borehole image analysis was conducted. As a result, gas-effect like sonic log response such as significant P-wave slowness slowing down and unchanged S-wave was newly observed in GIS sandstone formation, while other logs such as Neutron and Density did not show any hydrocarbon response. In addition, the sonic velocity radial-profiling analysis result indicated slow P-wave formation property radially continuing from near wellbore into the formation. Based on these observations and following desktop study, we successfully to reach the conclusion that gas-water 2 phase fluid model is a reasonable assumption rather than a single-phase fluid of GIS formation. These new findings on sonic log response in GDW reservoir will introduce us to the further rock physical study in Nakajo oil and gas field.
Running Pulse Neutron logs in Malaysia has previously been plagued by high uncertainties, especially in brown fields with complex multi stacked clastic reservoirs. Together with a wide range of porosities and permeabilities, the acquired logs quite often than not, tend to yield inconclusive results. In addition, the relatively fresh aquifer water (where salinity varies from 10k to 40k ppm) makes reservoir fluid typing and distinguishing between oil and water even more challenging. Again, the inconsistencies and uncertainties of the results tends to leave more questions than answers. Confidence in utilizing pulse neutron logging, especially to validate fluid contacts for updating static and dynamic reservoir models decreased to very low levels within the study teams. Due to this fact, the Petrophysics team took the initiative to conduct a 3-tool log-off in one of their wells with the objective of making a detailed comparison of 3 pulse neutron tools in Malaysia’s market today. The main criteria selected for comparisons were consistency of the data, repeatability and statistical variations.
With recent advancement in Pulse Neutron (Multi Detector) tool technology, newer tools are being equipped with more efficient scintillation crystals, improving the repeatability of the measurements as well as the number of Gamma Ray (GR) count rates associated with the neutron interactions. In addition, the newer tools have now up to 5 detectors per tool, with the farthest detector from the supposedly being able to “see” deeper into the formation, albeit at a lower resolution.
With these new features in mind, the log-off was conducted in a single well with a relatively simple completion string (single tubing, single casing), logged during shut-in conditions only, and the logs were acquired directly one after the other (back-to-back) to avoid bias to any particular tool.
Both Sigma and Spectroscopy measurements acquired to compare the capabilities of each tool. Due to the relatively fresh water salinity, the Carbon-Oxygen ratio from the Spectroscopy measurements used to identify the remaining oil located in the reservoirs, while the Sigma measurements determine the gas-oil or gas-water contact, if present.
This paper will illustrate the steps taken by PCSB to compare the raw data and interpreted results from the 3 pulse neutron tools. A comparison from all the tools is discussed in length, and consequently compared to the current understanding of the reservoir assess. The points from these comparisons will then show why one of the tools is favorable than the rest.
Existing methodologies for deriving permeability from microresistivity images rely on porosity transforms. However, because the relationship between porosity and permeability in carbonates is not well defined, it is necessary to identify alternative methodologies to help improve permeability estimates in carbonates.
This paper discusses a new workflow using downhole logging while drilling (LWD) tools that can provide a porosity independent estimation methodology for permeability indicator based on microresistivity images. In a microresistivity image, voids of rock encountered during drilling in a water-based mud (WBM) system are filled with conductive fluid and displayed as darker-conductive pixels. The introduced method identifies and determines a number of all conductive pixels from a histogram based on microresistivity values of a high- resolution image.
This method calculates a cutoff value for the above histogram using an invasion indicator derived from omnidirectional laterolog resistivity measurements of mud filtrate. A conductive pixels ratio is then calculated from a combination of the cutoff value and the histogram. The method also normalizes the continuous ratio to formation tester measured fluid mobility values and provides a qualitative permeability indicator.
This method compares other sources of log-derived permeability values, such as values from acoustic Stoneley waves and nuclear magnetic resonance (NMR) data of the same or offset wells, to the permeability indicator to fine-tune the method. It also includes partitioning of a horizontal section based on the derived permeability profiles and petrophysical attributes because the determination of lateral permeability variations is important to optimize the stimulation and completion design.
Additional investigations are desirable to better understand the applicability of this method with the integration of existing field knowledge, production data, and offset well data.
Permeability is a measure of the rock’s ability to allow the fluid flow. This rock ability is not only related to the pore throat size and distribution, which is absolute permeability or intrinsic permeability; but also, it manifests the flow ability of different fluids to move through the pore space, which is effective permeability. When to evaluate productivity during exploration stage, the general practice is often focus on the intrinsic permeability estimation from LWD logs or Wireline logs, or core analysis, but effective permeability and its inter-relationship to intrinsic permeability has been overlooked; the result therefore can lead to the big error for production prediction in the early stage of life cycle, especially in complex reservoir system, such as heterogeneity and low permeability formations etc., consequently impact the decision-making process of completion schemes, and development plans.
Hydrocarbon exploration offshore South China Sea successfully explored Lufeng A and C structures in Lufeng Sag in the Pearl River Mouth Basin (PRMB); and this demonstrates the breakthrough in the exploration of deep area of Paleogene System; it further proves the huge exploration potential of the Paleogene System in the PRMB. Under the joint control of tectonic-depositional process in the deep formations of Lufeng sag from a seismic interpretation example, many fault intersection patterns, unconformity and deformations are the main characteristics of the reservoir architecture, and the reservoir size varies from small one to big one across, and reservoir heterogeneity is predisposed to be strong. To optimize the operating and capital expenditure, joint development with existing platforms is the main strategy for the new blocks, therefore the productivity evaluation during the exploration phase needs more accuracy, so that the well capacity could be mapped to the suitable platform for later development; this requirement brings permeability as one of key controlling factors of productivity to the fore.
This paper delivered a new workflow of permeability evaluation, that is to integrate resistivity ratio clusters, logging facies and lithofacies classification based on open-hole logs and core data to identify rock types and build an intrinsic permeability model; then use wireline formation tester (WFT) mobility, WFT flowing mobility and WFT pressure- transient-analysis (PTA) to quantify effective permeability, and establish a relationship between intrinsic permeability and effective permeability; Lastly, delivered improved reservoir quality index (RQI) and productivity index (PI) for the formation evaluation in an exploration well. The result was used not only to optimize the drill stem test, but also it showed the solid match with DST, and provided the general practice in this field for later well correlations.
Evaluation of petrophysical parameters like porosity and water saturation in shaly sand reservoirs is a challenging task in comparison to clean sand reservoirs. Logging derived porosity in shaly sands requires shale correction. Archie’s formula cannot be used in shaly sands for the determination of water saturation, therefore many water saturation models were proposed to get accurate water saturation of shaly sand reservoirs. In this paper, three water saturation models were used; two empirical models (Simandoux and total shale) and one theoretical model (effective medium model). Shale corrected density log was used in all models. The use of computer-generated algorithm, fuzzy log neural network is of increasing interest in the petroleum industry. This paper presents artificial neural network (ANN) as an effective tool for determining porosity and water saturation in shaly sand reservoir using well logging data. ANN technique utilizes the prevailing unknown nonlinear relationship in data between input logging data and output petrophysical parameters. Results of this work showed that ANN can be supplement or replacement of the existing conventional techniques to determine porosity and water saturation using empirical or theoretical water saturation models. Two neural networks were presented to determine porosity and water saturation using GR, resistivity and density logging data and adapted cut off for porosity and water saturation. Water saturation and porosity were determined using conventional techniques and neural network approach for two wells in a shaly sand reservoir. Neural network approach was trained for porosity and water saturation using the available well logging data. The predicted porosity and water saturation values have shown excellent matching with the core data in the two wells in comparison to the porosity and water saturation derived from the conventional techniques. This work has clearly shown that the developed neural network (ANN) can accurately determine porosity and water saturation when compared to the used conventional techniques, especially when experimental core values of shaly sand reservoirs are used. The developed correlation works well in predicting the mode of shale affecting logging data used as inputs and during output analysis.
Understanding the electrofacies properties and identifying their major categories is a key step in reservoir characterization. Describing the accurate electrofacies is vital in constructing representative reservoir models which are need to define the optimum development plans and strategies. Electrofacies classifications is commonly conducted manually or with the use of some graphing approaches but recently different machine learning techniques and algorithms have been adopted to categorize electrofacies. In this paper, two machine learning techniques were implemented to identify electrofacies in a well from a giant carbonate reservoir in south of Iraq.
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