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Reservoir quality is one of the important geological factors controlling the development of tight oil in the Honghe oilfield, Ordos Basin, northwestern China. Analyses of core, well logging, mud logging and geophysical data as well as thin sections (casting and fluorescence) were combined with testing methods (such as grain size analysis, constant-rate mercury injection, and scanning electron microscopy) to characterize the micropore–throat development in reservoirs of the eighth member of Yanchang Formation in the oilfield. From the perspective of sedimentation and diagenesis, the mechanisms causing reservoir quality difference were explored and a method for characterizing reservoir quality difference and distribution was proposed. The results show that complex and diverse pore–throat configurations and multi-scale throat development are the microscale manifestations of reservoir quality differences in the member. Three types of pore–throat combinations are recognized, including intergranular pore-wide lamellar throat, intergranular and intragranular pore-wide lamellar throat, and intergranular/clustered micropore-wide lamellar throat. Different diagenesis processes and intensities under the control of sedimentary conditions determine the differential development of the reservoirs. Diagenetic facies are the indicators of reservoir quality. Diagenetic facies with chlorite cementation-moderate dissolution indicates reservoirs with the most ideal physical properties for hydrocarbon accumulation, while that with moderate calcite and kaolinite cementations are usually observed in reservoirs with less ideal physical properties. Reservoirs with the worst physical properties often correlate with diagenetic facies with strong calcite cementation and compaction facies. A multi-level constrained method under the control of sedimentation and diagenetic facies is proposed for characterizing tight reservoir quality difference in the member. The spatial distribution of sedimentary elements is analyzed through sedimentary configurations, the diagenetic facies distribution is constrained by sedimentary elements and the reservoir quality distribution is predicted with constraint of diagenetic facies. It suggests that the high-quality reservoirs in the member occur vertically in the middle of thick channel sandstone, while poor reservoirs occur in the upper or lower parts of the channel sandstone due to intensive compaction and cementation. Laterally, the quality of reservoirs enhances along the channels with a change in shape to lens or strips along the middle and downstream sections.

Effect of depletion rate on wellbore stability due to production of oil from hydrocarbon-bearing reservoirs is important and can result in a reduction of the reservoir pore pressure. A reduction in the reservoir pressure, in turn, results in a change in the stresses acting within the reservoir. If these changes are not well analyzed and applied in future calculations, we may be unsuccessful in some cases such as drilling infill wells or extended wells, forecast of sand production and optimum flow rate, preventing of casing collapse, etc. Therefore, knowing the stresses around the well at every stage of production is fundamental to the next calculations. In this paper, we recognized these changes in near-wellbore stresses using data from logging (image log, dipole sonic, full set log, mud log), production data, information from kick, blow out, loss etc. and determined it using Techlog software and theoretical calculations. Three wells of two huge oilfields of SW Iran were investigated after depletion or production for long years. In each well, state of stresses were calculated in cases of safe drilling mud weight using log data and theoretical equations. At the end effect of depletion rate on wellbore stability was investigated in these three wells.

The overall development of the top of the gas reservoir of the Dengying Formation, Upper Sinian in the Anyue Gas Field of the Sichuan Basin, has been deployed, and the inner Dengying Formation is the next potential succession layer. However, the high-quality reservoirs of inner Dengying Formation are undeveloped and cannot be identified on the seismic profiles, which restricts its deepened understanding, exploration and development. In this paper, the logging and seismic response characteristics of high-quality reservoirs were analyzed using the mud logging and well logging data of the Anyue Gas Field, and a seismic response model for high-quality reservoir was established by means of seismic forward modeling. Then, the target processing was carried out for the problem of weak effective signals. Finally, the plane distribution of high-quality reservoirs of inner Dengying Formation and the favorable exploration areas were predicted. And the following research results were obtained. First, there are two types of high-quality reservoirs inside the Dengying Formation, i.e., concentrated vug type and independent cave type. Vertically, the independent cave reservoirs are mainly distributed within 100 m above the mudstone floor of the third Member of Dengying Formation. Horizontally, karst zones are developed along the bed. Laterally, they are scattered and beaded. And the scale is small. Second, seismic response of high-quality reservoirs inside the carbonate rocks is characterized by single-peak concealed “beaded” reflection, whose peak energy is relatively weak and can be easily covered by the noise of seismic data. Third, deep-seated weak signal recovery and processing technology can be used to deal with the weak seismic response of high-quality cave reservoirs, improve the amplitude preservation and S/N ratio of seismic data, and obtain the beaded reflections on seismic profiles so as to realize effective identification of high-quality cave reservoirs. In conclusion, the deep-seated weak signal recovery and processing technology is proved to be operable because the achieved results conform to the drilling data and the seismic forward modeling conclusions. In addition, high-quality cave reservoirs are developed at the bottom of the fourth Member of Dengying Formation, and they are locally distributed in a large scale. Therefore, it's one of the favorable succession layers for the following natural gas exploration and development of the Anyue Gas Field. Keywords: Sichuan Basin, Anyue Gas Field, Late Sinian, Inner Dengying Formation, High-quality reservoirs, Cave, Beaded reflection, Multiple wave, Weak signal recovery, Succession layer series

The rate of penetration (ROP) plays a major role in drilling optimization, which makes it an important area of investigation. In this work, sensitivity and statistical analysis were carried out using a big set of data gathered from over 800 wells in the Basra oil fields, Iraq. The main objective of this investigation is to assess the effect of mud weight (MW) on ROP and to provide a method for estimating the recommended range for operational mud weight based on the rock hardness. The collected data for the drilling intervals from the drilling reports for over 800 wells in the Basra oil fields, Iraq, were categorized as weak, medium, hard, and very hard, based on the unconfined compressive strength (UCS), depth, and lithology. Statistical and sensitivity analyses were conducted and correlation coefficients (CC) were developed to describe relationships between rock hardness, ROP, and MW from field data. This methodology combines data from mud logging, daily drilling reports, and geological information to investigate the relationship between ROP and MW for different rock types and strengths. Several previous studies focused directly on MW, where the effect of MW on bit conditions, and thus the ROP was clearly demonstrated. However, these studies did not take into consideration the rock hardness or lithology. There is also a strong discrepancy between results from different studies, where some studies showed an inverse relationship between MW and ROP, while other studies showed it was a direct relationship. In this study, field data have been gathered (more than 800 wells) to further investigate the relationship between MW and ROP, and how it varies with rock hardness. The results showed that MW has an inverse relationship with ROP for the weak formation with a CC of −0.57, suggesting that the MW should be maintained as minimum as possible when drilling through the weak formation. On the other hand, MW showed a direct relationship with ROP for medium, hard, and very hard formations with CC of 0.31, 0.4, and 0.42 respectively. Hence, MW has to be maintained as high as possible to maximize ROP for medium, hard, and very hard formations. Large-scale collection and interpretation of field data were collected to demonstrate the effects of MW on ROP with varying rock hardness and lithology. While field data of this scale is inherent of interest, this analysis also investigates relationships previously unexplored and extends understanding of how MW effects ROP.

The Chang 81 Member, Yanchang Formation in Huanxian area, Ordos Basin, China, is a tight sandstone dominated reservoir with low porosity and low permeability. The contribution of pore fluid to well logging response is greatly reduced, and the resistivity of oil layer and water layer are close, which bring great difficulties to the fluid identification and logs interpretation. In this paper, we first analyzed the genetic mechanism of the low-resistivity oil pay layer in terms of reservoir petrological characteristics, irreducible water saturation and formation water salinity. The high content of clay and complex pore structure resulting in high irreducible saturation which leads to additional conductivity; and the formation water salinity has great difference in this area. In order to reduce the influence of the formation water salinity difference on the fluid identification, we separated the study area into normal oil pay region and low-resistivity oil pay region based on the relationship between formation water salinity and formation resistivity. Then, double apparent formation water resistivity difference method, fluid identification factor cross-plot method, full hydrocarbon mud logging and well logging hybrid method and the normal distribution method were established in two different regions, respectively. The comparison of different fluid identification methods show that full hydrocarbon mud logging and well logging hybrid method is the best method for fluid typing of oil layer, oil-water layer and water layer. Double apparent formation water resistivity difference method is not effective to distinguish the oil-water layers from the water layers and oil layers, and the normal distribution method is not applicable for distinguishing the low-resistivity oil pay. In the case study, the above methods are together used to identify the fluids of the reservoirs, and the application result indicates that comprehensive analysis of multiple methods can effectively improve the accuracy of fluid typing.

Determination of petrophysical parameters from surface measurements of drill cuttings, rather than well logs, has long been a subject of interest in the petroleum industry. Analysis of cuttings is presently included in mud logging workflows, although the methods employed tend to be labor-intensive and inefficient with an emphasis on qualitative lithological and mineralogical descriptors. Nuclear magnetic resonance (NMR) has the potential to deliver rapid formation evaluation at the rig site for near-real-time completion decisions. Despite numerous efforts to demonstrate NMR cuttings analysis, dating back to the 1980s, the technique has yet to achieve commercial success. We suggest this failure is due not to the physics of the measurement, which is understood, but rather to inadequate sample preparation. By centrifuging brine-saturated cuttings from conventional formations under a per-fluorinated oil, and using multinuclear NMR to measure liquid volumes, we obtain accurate porosity and permeability values independent of other measurements. Our robust workflow removes the inconsistencies associated with manual sample preparation. We present two case studies and the important requirements for handling actual drill cuttings.

By means of chemical combination between the Polydimethylsiloxane (PDMS) layer and Polyethersulfone (PES) layer, a kind of PDMS/PES composite membrane was prepared for separation of the light hydrocarbon components from the drilling mud. Meanwhile, its separation performance of the light-hydrocarbon components from the drilling mud was investigated and evaluated quantitatively. Results showed that the prepared PDMS/PES composite membrane had good mechanical performance, and it was resistant to corrosion of the water-based drilling mud. The PDMS/PES composite membrane can work stably at 5 MPa and 393 K. The responding time of the membrane to sudden change of the hydrocarbon gas content was less than one minute. For either single phase flow or gas-liquid two-phase flow, a high flow rate was recommended to avoid non-ideal flow patterns and to increase mass transfer in the feed channel of the membrane cell. Results in this work could be helpful for further application of the membrane technology in geological mud logging.

It is proved that the Wufeng-Longmaxi formation in Sichuan Basin is the key shale gas layer in China. Although the breakthrough of shale gas exploration had been gotten in it, the enrichment mechanism of it has not been well studied. To understand the enrichment mechanism of it, we will take the biggest total gas content layer (BTGC layer) and main production layer (MP layer) drilled in well HD-1 for example. A series of experiments were conducted on core samples, including total organic carbon (TOC) content, X-ray diffraction (XRD), scanning electron microscope (SEM), focused ion beam scanning electron microscope (FIB-SEM) and Micro-CT. Meanwhile, the aid tests (such as mud logging data, reservoir physical test, field desorption experiment data, mud gas logging data) were integrated to study the difference of the two sections in gas storage and transmission capacity too. The results show that although the field desorption gas content of BTGC layer is bigger than MP layer, the TOC of BTGC layer (3.45%) is smaller than it in MP layer (4.15%). The MP layer is dominated by the quartz with average value 87.3% which is obviously bigger than it in BTGC layer 37.5%. Although the helium porosity in BTGC layer (2.98%) is bigger than MP layer (2.68%), the permeability of it(0.005878mD) is smaller than MP layer(0.013950mD). Except the organic pores, to a certain type, the pores in the MP layer are bigger than them in BTGC layer, such as interparticle pores, dissolution pores, micro fractures. The connected pores are dominated by the pores in mm-scale and micro-scale. The difference of the enrichment mechanism in the two layers is dominated by the difference of pore structure. The MP layer provides a migration pathway to the gas enriched from nearby shale layer in km-scale. If the permeability and the overpressure of the layer are big enough, the shale gas would be exploited without hydraulic fracturing. In BTGC layer, the pores are scatted in the shale and isolated from each other. The gas storage ability of this type is commonly good, with high field desorption gas content, but it must be exploited with hydraulic fracturing for its low permeability. It is need to pay attention to the high permeability layer in shale strata in the further exploration of shale gas.

Cuttings transport becomes critical important when horizontal directional drilling (HDD) technology has been used more often in long distance and large diameter oil and gas pipeline construction in rocks. Front reaming (FR) and one way drilling mud return (OWDMR) were not new in oil and gas well drilling, but they were rarely used in HDD industry compared to the traditional back reaming (BR) and two way drilling mud return (TWDMR). FR and OWDMR technologies, when they were used in HDD, were designed mainly for highly non-leveled HDD projects to overcome some difficulties such as the recycling of drilling mud. Along with these technologies is that the cuttings need to travel longer distance to the ground surface. In addition, the effect of the drill rod rotation on the cuttings transport does not exist because hole bottom mud motor is usually used in FR. To find a solution for this problem, the cuttings transport mechanism was analyzed based on the drilling mud hydraulics, and then, an equation of cuttings transport distance was derived. It found that the average drilling mud velocity in the annulus and the consistency index of drilling mud are the two most important factors related to the cuttings transport distance. To help with the cuttings transport, a new MMH drilling mud system, which provides a high consistency index and a low flow index, was used in rock HDD projects, instead of the common Bentonite-water drilling mud system.

The drilling mud loss risk is a major problem for horizontal directional drilling (HDD) projects when it was drilling in fractured rock stratum. The existing theoretical calculation methods for the maximum allowable drilling mud pressure in HDD borehole are particularly designed for soils, so they are not suitable when rocks are encountered. The maximum allowable drilling mud pressure was analyzed in this study for a fracture zone of a maxi-HDD project crossing Yangtze River. The geotechnical investigation disclosed multiple layers of soils and rocks: the upper part two sand layers and the lower part one sandstone layer. The fracture zone in the sandstone layer was investigated by digital panoramic borehole camera technique, so that the detailed fracture orientations and locations can be identified. The maximum drilling mud pressure for the upper part two sand layers was calculated using Delft equation. At the same time, the evolution of drilling mud pressure in the fracture zone was studied using numerical modeling method. Combing with the calculation results of both Delft equation and numerical modeling, the maximum allowable mud pressure at the fracture zone of the HDD borehole was obtained. The numerical modeling found that the persistent fracture system in the fracture rock mass has very low resistance to the drilling mud pressure propagation, so a low drilling mud pressure needs to be used when it was drilling/reaming in the fracture zone. The effects of fracture aperture, the drilling mud viscosity, and fracture roughness on the mud pressure evolution were also analyzed.

Mud logging system presents the most promising tool for exploring oil and gas resources, which relies on the multi-component analysis of gases to evaluate the hydrocarbon reservoirs. Higher detection efficiency, especially relating to the high-throughput analysis, can offer an important means to enhance the oil and gas recovery of hydrocarbon reservoirs. However, fewer technologies can measure both hydrocarbon and non-hydrocarbon gases in a timely manner. In the present work, a method based on data driven Raman spectroscopy (DDRS), which allows simultaneously accurate analysis of 12 hydrocarbon and non-hydrocarbon gases, has been proved. By developing a data driven strategy that incorporates higher-density discrete wavelet transform (HDWT) and template oriented frog algorithm (TOFA), the spectral resolution of Raman spectroscopy was significantly improved in both time and frequency domains to extract the target gas information from the Raman spectra, facilitating the detection of hydrocarbon reservoir. Theoretically, it is considered that the DDRS represents a promising tool for extracting the quantitative information from multi-component gases in the presence of dominantly uncontrolled variance. Our work has tested and refined the DDRS by performing a comprehensive analysis of three gas mixtures established to yield challenges representative of those encountered in a common mud logging analysis. The DDRS compared favorably with the gas chromatography (GC) method. The satisfactory results indicated that the DDRS has the capability to continuously detect 12 hydrocarbon and non-hydrocarbon gases in real time, which could be extended to online multi-component analysis of any other gas and fuel systems.

To control the human factor risk for oil and gas drilling industry, the types of work activities involved in drilling were identified, the major accident risk types of human errors were selected, the probability and severity levels of the risks associated with each activity were quantified, and the human factor risk levels of major work activities involved in drilling processes were calculated. Quantitative results demonstrate that the highest risks during the drilling process include being struck by an object, injury by machine, and overexertion; conversely, the lowest risks include exposure to harmful substances or environments and fire and explosion. The highest risk activities are associated with, for instance, penetration drilling, the trip in and out, and the hoisting and lifting operations. Conversely, the relative lowest risk activities include auxiliary operations, well logging and mud logging, equipment inspection and maintenance. The total risk value of all main drilling activities is 11.3947 S/w-h. Twelve risk control measures were selected, and the Delphi method was taken to quantify the human factor risk mitigation capacity resulting from the selected risk control measures. The results demonstrate that the human risk control measures exist in three tiers of effectiveness, with each tier being separated by nearly an order of magnitude. The types of most risk mitigation are risk codes, such as injury by machine, fall from height, and contact with harmful material. The most minimal risk mitigation types include muscle strain and fire and explosion. Finally, these data will be valuable for drilling companies to strategically allocate limited resources to their safety management plan, and they can evaluate the expected effectiveness resulting from risk control measures.

Demand of the oil and gas energy is increasing very drastically. Conventional hydrocarbon reservoirs contain below the sealing cap rock (shale) and easily move towards wellbore are at the depletion stage. Therefore, drilling engineers in collaboration with mud engineers, geologists and geophysicists are looking for innovative materials to drill unconventional hydrocarbons reservoir which are distributed at the basin scale and cannot approach easily. Geo-thermal energy wells and most of unconventional reservoirs are occurred at high pressure high temperature (HPHT) conditions. Conventional micro-macro organic drilling mud additives with heat insulator in nature can minimize efficiency while drilling HPHT wells. Oil-based muds (OBM) are strictly restricted due to high toxic level and poor emulsion stability at HT. However, this review suggests that addition of macro size organic particles and inorganic nanoparticles can enhance rheological performance, reduce filtrate loss volume and improve shale inhibition characteristics of environmental friendly water-based mud (WBM). Despite an impressive amount of experimental work has been done over drilling additives and their effect over rheological and shale inhibition, taking into account their literature review are rare. In addition, there is no review work of the knowledge gained to date. This work will hope fully trigger further development and new research topics in the area of drilling muds system.

High-yield gas layers, low-yield gas layers and (gas bearing) water layers of Upper Paleozoic coexist in the Shilijiahan zone in the northern Ordos Basin, but gas–water distribution characteristics, laws and influence factors are not understood well, so the exploration and development of natural gas in this zone are restricted. In this paper, statistical analysis was carried out on the data of Upper Paleozoic formation water in this zone, e.g. salinity, pH value and ion concentration. It is shown that the formation water in this zone is of CaCl 2 type. Then, the origin, types, controlling factors and spatial distribution characteristics of formation water were figured out by using core, mud logging, well logging and testing data, combined with the classification and evaluation results of geochemical characteristics of formation water. Besides, the logging identification chart of gas, water and dry layers in this zone was established. Finally, the occurrence and distribution laws of reservoir fluids were defined. The formation water of CaCl 2 type indicates a good sealing capacity in this zone, which is favorable for natural gas accumulation. It is indicated that the reservoir fluids in this zone exist in the state of free water, capillary water and irreducible water. Free water is mainly distributed in the west of this zone, irreducible water in the east, and capillary water in the whole zone. The logging identification chart has been applied in many wells in this zone like Well Jin 86. The identification result is basically accordant with the gas testing result. It is verified that gas and water layers can be identified effectively based on this logging identification chart.

Petrophysical evaluation from laboratory and well logging data, such as gamma ray, Nuclear Magnetic Resonance (NMR) and resistivity has been used to identify and evaluate oil zones in reservoirs. Gamma ray log is able to predict lithologies along the well, and X-ray Diffraction (XRD) and X-ray Fluorescence (XRF) techniques also provide important lithological laboratory information. The NMR log directly estimates the porosity of the rock. Resistivity log identifies the water region, but cannot provide information about oil saturation. However, the application of unconventional techniques, such as Electron Spin Resonance (ESR), can be of great relevance in the well logging, adding information about lithologies, oil quality and saturation. The ESR technique, which can directly estimate the oil saturation inside the rock, can also provide important information about the origin and formation of rocks. This technique could be an advance for the oil industry, helping to understand the geothermal processes suffered by the rocks and identifying important regions of the reservoir. Thus, in this work, we studied carbonate rock (limestone and dolomite) samples with and without oil, by ESR technique. Firstly, the effectiveness of ESR in the differentiation of carbonates (calcitic and dolomitic) without oil was tested, through the analysis of manganese ion impurity, which promotes the replacement of calcium and magnesium ions in calcites and dolomites. The samples had a typical manganese ESR signature. The hyperfine parameter, A, was homogeneous for both limestone and dolomites. The zero-field split parameter, D, showed variability, as reported in the literature. The studies were carried out at X-band frequency. The analysis by XRF and XRD provided information on the chemical and mineralogical composition of the carbonates, which were added to the ESR data for application in a correlation matrix, by which it was identified that the components CaO and MgO were directly related to the intensity of the ESR signal and the concentration of CaO was inversely related to the concentration of Al2O3 and SiO2. In one limestone rock sample was incorporated oil, with 25° API and moderate biodegradation level, to identify by ESR, the oil presence inside this rock. The technique was able to identify the oil and its saturation in the rock through the detection of free radical signal, g = 1.9951. The innovative application of the ESR technique to identify oil in varying saturation, in carbonate rock samples from the Illinois Basin (USA), was successful. These results demonstrated that this technique in addition to being accurate, non-destructive and relatively low cost, could be used in mud logging operations providing results for lithological characterization, oil identification and its saturation inside the reservoirs.

The problem of lost circulation is a direct consequence of the presence of fractures or high permeability. Lost circulation material (LCM) is used to treat the loss that occurs or proactively strengthen the wellbore of the potential loss zones. The polyacrylamide (PAM)/Polyethylenimine (PEI) cross-linkable polymer gel is proven to work best in zone-sealing and plugging applications. In addition to their thermal stability, the fact that these gels are flexible gives them the advantage of deforming and sealing-off multiple and complex near wellbore fractures. The primary objective of this study is to investigate the gelation kinetics of the PAM/PEI cross-linkable polymer to be used in drilling fluids formulations to enhance wellbore stability and strength. Different combinations of polymers and crosslinkers were evaluated; potential polymers were screened for gelation kinetics and gel strength in typical drilling mud formulations. The gelation time of the polymer-based drilling mud formulation is determined in salt-free and in saline systems. The results on rheological properties and gelation kinetics were used to prepare a gelling mud formulation using PAM/PEI cross-linkable polymer as LCM. The produced gel was thermally stable under high-temperature-high-pressure reservoir conditions, which will result in enhanced wellbore strengthening. This paper was made possible by an NPRP Grant # NPRP10-0125-170240 from the Qatar National Research Fund (a member of Qatar Foundation ). The statements made herein are solely the responsibility of the authors. Scopus

Biostratigraphy is a key upstream activity. Drilling operations use biostratigraphic data derived from core samples extracted via boreholes (mud logging) in order to guide drilling processes and verify models of basin geology. Current manual data analysis relies on the existence of sufficient numbers of biostratigraphers to be available to fulfil industry needs. However, due to factors such as retirement, and that the number of people being trained in the requisite taxonomic skills has declined sharply over the last couple of decades; the available pool of expertise is dwindling. It is clear that if the high cost of drilling operations is taken into account, the current situation is untenable and in many ways represents a perfect storm. This pessimistic situation can be radically changed by augmenting human expertise using automated species identification tools based on artificial neural network technology. DAISY [Digital Automated Identification System], a proven system of this sort, could revolutionise commercial biostratigraphy operations by enabling microfossil identification to be undertaken by technicians. This would yield immediate benefits for the industry as it would permit routine work to be performed quickly and accurately by less skilful, cheaper and therefore more available staff; freeing biostratigraphers to concentrate on non-routine, more complex tasks. The feasibility study presented here indicates that DAISY can consistently identify microfossils to species, with repeatable, high levels of accuracy. Crucially, it can also act as a permanent repository for taxonomic knowledge, which is currently lost when experienced personnel retire. There might also be additional environmental and social benefits if this technology is widely adopted within the oil and gas sector: as DAISY technology is generic, it can easily be re-targeted to interpret seismic data or even to estimate the impact of upstream exploration activities on abutting ecosystems.

Basin hydrodynamic assessment methods are being applied to Australia's developing coal seam gas (CSG) to liquefied natural gas (LNG) export developments in the Queensland's Bowen and Surat basins. Technical challenges include the need to predict the cumulative impacts of CSG production on formation pressure in adjacent Great Artesian Basin aquifers and assess to what degree, if any, there may be fugitive methane liberated from the reservoir but not captured by production wells. Both these challenges require an understanding of the distribution of aquitard hydraulic sealing performance. We use hydrocarbon systems analysis to illuminate basin scale geological seal performance of the low permeability strata and provide baseline data on hydrocarbons in groundwater. We collected indicators of hydrocarbons including: 1) drill stem, wireline and production test sample analysis, 2) staining, fluorescence, and streaming hydrocarbon occurrences from drill cuttings and core, and 3) mud log gas detector data. This data was allocated to stratigraphic horizons, mapped and compared to the geographic/stratigraphic location of source rocks, conventional and unconventional reservoired hydrocarbons, and aquitard/sealing strata and faults. We found asymmetric trapping of conventional hydrocarbon reservoirs with eastern basin leakage and western basin preservation. Indications of some thermogenic gas in the Walloon Coal Measures exist yet maturity indicators are sub-thermogenic, suggesting that although much of the Walloon Coal Measures gas is biogenic, thermogenic gas may have previously migrated into the Walloon Coal Measures from elsewhere. Stratigraphically below the Walloon Coal Measures, hydrocarbon migration indicators are often clustered along lineations such as the Moonie-Goondiwindi and Burunga-Leichhardt fault systems. At the top of the Walloon Coal Measures, hydrocarbon migration indicators are clustered along the northeastern subcrop edge of the basin where the muddy strata at the top are either thin or eroded suggesting vertical leakage occurred to the overlying Springbok Sandstone aquifer. Whilst we can see where seals are either more, or less effective, at this stage we cannot make a quantitative assessment of background methane flux to surface or potential future proportional allocation of methane flux to natural vs anthropogenic causes.

Located in the Sichuan Basin, the Yuanba Gasfield is the deepest marine sour gas field among those developed in China so far. Its biohermal gas reservoir of the Upper Permian Changxing Fm is characterized by ultra depth, high content of hydrogen sulfide, medium–low porosity and permeability, and small reservoir thickness. Economic evaluation on it shows that horizontal well drilling is the only way to develop this gas reservoir efficiently and to reduce the total development investment. At present, the petroleum engineering technology for this type of ultra-deep sour gas reservoir is less applied in the world, so an ultra-deep horizontal well is subject to a series of petroleum engineering technology difficulties, such as safe and fast well drilling and completion, mud logging, well logging, downhole operation, safety and environmental protection. Based on the successful development experience of the Puguang Gasfield, therefore, Sinopec Southwest Petroleum Engineering Co., Ltd. took the advantage of integrated engineering geology method to carry out specific technical research and perform practice diligently for 7 years. As a result, 18 key items of technologies for ultra-deep sour gas reservoirs were developed, including horizontal-well drilling speed increasing technology, horizontal-well mud logging and well logging technology, downhole operation technology, and safety and environmental protection technology. These technologies were applied in 40 wells during the first and second phases of productivity construction of the Yuanba Gasfield. All the 40 wells have been built into commercial gas wells, and the productivity construction goal of 3.4 billion m 3 purified gas has also been achieved. These petroleum engineering technologies for ultra-deep sour gas fields play a reference role in exploring and developing similar gas reservoirs at home and abroad.

Offshore drilling in basins with a significant basaltic component poses a number of complications to drilling operations. These include slow and variable rates of penetration (ROP), drilling fluid losses, drill bit or string sticking, overpressured formations, wellbore spalling and collapse. In this contribution we investigate features of large igneous province (LIP) volcanic facies that may directly contribute to drilling complications. Combining borehole and field based examples we identify highly vesicular brecciated lava flow tops and hydro-volcanic facies as a major potential cause of catastrophic drilling fluid losses. The risk for drilling losses is generally higher in the upper parts of thick volcanic successions where hydrothermal secondary mineralization and alteration may be less pervasive. We demonstrate how these facies may be identified early by integrating real time mud logging data with characteristic drill cuttings and LWD (logging while drilling) wireline data as it becomes available. We highlight the potential of basaltic formations to maintain porosity and permeability to greater depths than is typical for sediments due to the high compressive strength of crystalline basalt frameworks. The heterogeneous sub surface distribution of key volcanic facies commonly includes intimate mixing and layering of hard and dense with soft and weak volcanic rock which may promote complex in-situ stresses to develop during burial compaction. Where this occurs, wellbore stability predictions such as the fracture and wellbore collapse gradients for volcanic sequences may deviate from those expected in basin equivalent sedimentary sequences. Examples of swelling volcanic clay horizons, unstable volcaniclastic sequences, and intrusion related ledge effects are used to characterize the main causes of drill bit and string sticking. A greater understanding of drilling complications encountered within prospective areas containing volcanic sequences is needed if better pre-drilling risk assessment, cost prediction, real-time identification and mitigation is to be achieved.

With the consumption of conventional hydrocarbon reserves and advancement in drilling technology, recently there is a high interest in gas hydrates in the world. Due to lack of experience and sensitive nature of gas hydrates, drilling in gas hydrate reservoirs were considered as risky. However, recent drilling data in gas hydrates shows that successful drilling operations in gas hydrate reservoirs are possible with some special measurements such as specially designed drilling fluid and cement slurry etc. In this study, open-hole riserless drilling, drilling with riser in marine environment, logging while drilling, drilling fluid, cement and coring systems used in hydrate exploration are explained.

The Yuanba giant gas field in the Sichuan Basin produces from Upper Permian Changxing heterogeneous reef-shoal reservoirs. It is an ultradeep tight gas reservoir with burial depth of 7000 m. This paper proposes an integrated methodology incorporating the reservoir geology description, petrophysics characterization, seismic response analysis, forward seismic modeling, pseudo-acoustic inversion, and reservoir architecture imaging to identify the geologically complex reef-shoal reservoirs and predict the distribution of the producible reservoirs. The facies of reef cap, reef core, reef base and shoal are first identified based on observations and interpretations of cores, thin sections, mud logging, wireline logs, and formation microscanner images (FMIs). High-energy shoals, reef cores, and reef caps are the most favorable reservoir microfacies. Seismic responses of reef-shoal reservoirs are then investigated through forward modeling and well-seismic calibration. Four reef belts are identified based on seismic reflections and edge detection by seismic paleogeomorphologic features. Reservoir distribution and quantitative properties are predicted using the facies-controlled postattack seismic inversion technique through the correlation between reservoir properties and seismic attributes, which is aided by pseudo-gamma acoustic inversion to exclude the shale-bearing non-reservoir and pseudo-neutron acoustic inversion based on its good relationship with porosity. The reef reservoir thicknesses range from 10 m to 130 m, and the thickest reservoir is located in the northwestern Yuanba gas field. Finally, 3-D visualization is used to characterize the spatial variation of the interior architecture, connectivity, and distribution of a good reservoir in the reef system. The accuracy rate of prediction for reservoirs and non-reservoirs reaches 88% using this method. The technique has also been successfully used for the deployment of development wells and well trajectory optimization, and the rate of encountering the predicted reservoirs is 100%. This study provides a practical approach to identify and predict the tight carbonate gas reservoir with similar petrophysical responses of density and acoustic to non-reservoirs in the complex carbonate system.

The Dengying Formation is an important stratum of exploration in the Gaoshiti-Moxi structure belt in the Sichuan Basin. Therefore, this study combines core, thin section, mud logging data and geochemical analysis (C, O and Sr isotopes) with seismic section data to investigate the basic characteristics and genesis of the Dengying Formation reservoir. Observations indicate that the reservoir rocks mainly consist of sand crumb dolomites, algae laminated dolomite and breccia. The reservoir space is dominated by porous dissolved holes, dissolved pores (or holes) along the direction of algal laminae, intra-grit holes and residual “grape lace” holes. The reservoir has the characteristics of low porosity and medium-permeability. There are three types of reservoir: porous reservoir, fractured porous reservoir and cave reservoir. The reservoir was formed by the common action of deposition, diagenesis and tectogenesis. Sedimentation is the basis and presupposition for reservoir development, but the effective reservoir is mainly controlled by the algal flat microfacies; Furthermore, compaction, cementation and filling are the main causes of reservoir density; Recrystallization is the basis for the formation of porous reservoir; Supergene dissolution is the key to reservoir formation; Buried dissolution also promotes the formation of a high quality reservoir. The fractures formed by tectogenesis significantly improve the permeability of the reservoir and contribute very little to porosity. The reservoir gradually evolved and formed under the control of various geological and diagenetic activities. This study provides important information and references for oil and gas exploitation and development in central Sichuan.

The return of drilling fluid (drilling mud) in large diameter horizontal directional drilling (HDD) boreholes is a very important issue related to mud pressure, cuttings transport and pull back force, but this problem has not been fully solved in previous research due to the complexity and uncertainty of downhole conditions. The calculation methods of mud pressure loss in the borehole annulus are briefly introduced and the equation using a Power Law model is adopted to study the drilling mud return. A typical reaming hierarchy of a large diameter HDD project has been used to study the return direction of drilling mud and volumes of drilling mud return to the exit and entry points. The research results disclosed that the drilling mud can return to both exit and entry points at the same time, with a large majority of the drilling fluid returning to the exit point if the reamer is closer to the exit point, and vice versa. A parametric study has been conducted to find out the effect of changing parameters in the calculation equation on the drilling fluid return. The drilling mud return for those boreholes with the exit point and entry point located at different elevations has also been discussed. Finally, different types of reamers and other factors such as borehole collapse and borehole shape were taken into the consideration of drilling mud return.

Resistivity logging is one of the most important ways of identifying and estimating the saturation level of gas hydrates in permafrost and ocean regions. in practical drilling operations, resistivity loggings, especially shallow lateral resistivity logging in gas hydrate bearing sediments (ghbs), are likely to be affected by drilling mud invasions. here, we use available data from site measurements to construct a two-dimensional model for hydrate reservoirs around the borehole sh2, a hole that was drilled during the first expedition in shenhu area of south china sea to examine and drill into gas hydrates. we then use this model to investigate the characteristics of drilling mud invasions and the effect of drilling mud properties (e.g., temperature, density, and salinity) on resistivity logging using a numerical simulation. this simulation and associated calculations indicate that shallow lateral resistivity logging is significantly affected by variations in drilling mud temperature, which leads to hydrate dissociation and the formation of secondary hydrates. increasing drilling mud salinity accelerates hydrate dissociation, and has a greater effect on shallow lateral resistivity logging than the free gas produced during drilling and any potential mud density influence, which is generally dependent on the depth at which the drilling mud invasion occurred. this means that future drilling operations should focus on ensuring that the temperature, salinity, and density of drilling muds remain within a reasonable range in order to minimize the effect of mud invasions on resistivity logging data. (c) 2014 elsevier b.v. all rights reserved.

In the Yingdong Oil/Gas Field of the Qaidam Basin, multiple suites of oil-gas-water systems overlie each other vertically, making it difficult to accurately identify oil layers from gas layers and calculate gas-oil ratio (GOR). Therefore, formation testing and production data, together with conventional logging, NMR and mud logging data were integrated to quantitatively calculate GOR. To tell oil layers from gas layers, conventional logging makes use of the excavation effect of compensated neutron log, NMR makes use of the different relaxation mechanisms of light oil and natural gas in large pores, while mud logging makes use of star chart of gas components established based on available charts and mathematical statistics. In terms of the quantitative calculation of GOR, the area ratio of the star chart of gas components was first used in GOR calculation. The study shows that: (1) conventional logging data has a modest performance in distinguishing oil layers from gas layers due to the impacts of formation pressure, hydrogen index (HI), shale content, borehole conditions and invasion of drilling mud; (2) NMR is quite effective in telling oil layers from gas layers, but cannot be widely used due to its high cost; (3) by contrast, the star chart of gas components is the most effective in differentiating oil layers from gas layers; and (4) the GOR calculated by using the area ratio of star chart has been verified by various data such as formation testing data, production data and liquid production profile.

Various information sources in petroleum exploration and exploitation, such as seismic, well logging, mud logging and drilling data, are the comprehensive reflection of the same geological body underground and have a strong correlation with each other. A multi-dimensional heterogeneous space model is presented for a range of geological characteristic parameters prediction, such as formation pore pressure, formation drillability, rock strength, lithology and so on. Then the model is applied to the formation drillability prediction with the parameter of seismic layer velocity, acoustic velocity, formation density, shale content, drilling pressure, rotary speed, hydraulic horsepower, bottom hole differential pressure, rate of penetration and formation depth. Firstly, Kernel principal component analysis (KPCA) is used to extract the feature of the parameters, and then Quantum Particle Swarm Optimization-Support Vector Machine (QPSO-SVM) is utilized as the information fusion algorithm. The comparison of the prediction results with the results of backpropagation neural network (BP-NN) indicates that this method is better than BP neural network in a variety of performance and has the advantages of higher accuracy and better generalization ability. In addition, the stronger robustness and more reliable result can be obtained from the multi-source information fusion prediction in contrast with the single source prediction. The experimental results show that the model constructed is effective to predict the formation drillability, and its accuracy reaches as high as 95%.

The need to increase productivity and to reduce drilling damage favors the use of underbalanced drilling (UBD) technology. In highly depleted reservoirs, extremely low-density fluids, such as foams or aerated mud, are used to achieve circulating densities lower than the pore pressure. In such cases, the induced modification of the in-situ stresses has to be supported mainly by the rock, with little contribution from the drilling fluid pressure. The application of underbalanced drilling depends on the mechanical stability of the drilled formation, among other factors. In general, poorly consolidated, depleted formations are not suited for that technology. In this paper, twenty three UBD worldwide cases have been analyzed; two of which are from Egyptian fields and the others are from Iran, Algeria, Kuwait, Oman, Texas, Mexico, Indonesia, Canada, Libya, Middle East, Qatar, Saudi Arabia and Lithuania. From these analyses, the reasons of failure or success have been stated. The reasons of success included depleted reservoirs and highly fractured carbonates formation while, the reasons of failure include overpressurized shale, highly tectonic stress areas, and downhole failures. The main attractive application of this technology was proposed to be only in the reservoir section, and the target was to prevent the reservoir damage and hence increase the productivity and recovery factor. A proposed underbalanced drilling program is developed based on these analyses to be used in the three main regions in oil and gas producing Egyptian fields. The aerated mud was selected as a drilling fluid to drill the reservoir section in Western Desert and Gulf of Suez region whereas the single phase fluid was selected as a drilling fluid in the Nile Delta region.

1. IntroductionThe Lusi mud volcano in Sidoarjo, East Java, was first noticed bylocal villagers at 5 am on the 29th May 2006. It started to erupt150 mfromtheBanjarPanji-1gasexplorationwell(Fig.1)twodaysafter the Yogyakarta Earthquake (5:54 am 27th May 2006), hasdisplaced 13,000 families and led to13 fatalities. The trigger for themud volcano has been the subject of significant debate (Davieset al., 2007, 2008; Manga, 2007; Mazzini et al., 2007; Tingayet al., 2008).The Sawolo et al. (2009) paper assesses and then dismisses thepossibility that there was a subsurface blowout (breakdown of thestructural integrity of the well) caused by a kick in the well (aninflux of water or gas from surrounding formations) whichoccurred on the 27th and 28th May 2006. For the subsurfaceblowout to have occurred, the pressure of the fluid (drilling mud,water, gas) in the unprotected section of the well has to exceed themaximum pressure the well can tolerate, which is estimated bya pressure test known as a leak-off test (LOT). To reach thisconclusion Sawolo et al. (2009) estimate what we deem to be anunrealistically high leak-off pressure (LOP) and unrealistically lowpressure within the borehole during the kick.Here we counter the main arguments made by Sawolo et al.(2009), pointing out inaccuracies, incorrect interpretations anddeviations from the daily drilling report (the factual account ofdaily operations). We also take this opportunity to describe for thefirst time direct evidence that the well was the cause of the mudvolcano. Lastly we show that their claim of an earthquake trigger isnot supported by the mud log data they present.2. What pressure could the well tolerate?The estimated LOP proposed by Sawolo et al. (2009) is 16.4 ppg(19.27 MPa/km) measured at 1091 m (1 ppg¼1.175 MPa/km). Indetermining the leak-off pressure (LOP), industryaccepted practiceis to take the inflexion point on a pressure build-up curve (Bell,1996; Enever et al., 1996; Addis et al., 1998; Jorgensen andFejerskov, 1998; Okland et al., 2002; Raaen et al., 2006; van Oortand Vargo, 2008). Based upon the pressure versus time plot(their figure 11), using this method the leak off was 15.8 ppg(18.57 MPa/km). The rationale stated by Sawolo et al. (2009) fornot interpreting the LOP by the conventional method is thatinterpreting leak-off pressure is less reliable when using oil-basedmuds and they suggest that the ‘fracture closure pressure’ shouldbe used instead.The fracture closure pressure (FCP) is generallyconsidered to beequaltotheminimum principalstressmagnitude andthus equaltothepressurerequiredtoopenanypre-existingfractures.Hence,theFCPcanbeanaccuratevaluetouseasformationstrength.However,the 16.4 ppg (19.27 MPa/km) value suggested by Sawolo et al.(2009) as the ‘fracture closure pressure’ is in contravention of alltechniques for estimating FCP. FCP is determined by carefullymonitoring the pressure decay in the well after the pumps areturned off (Enever et al., 1996; Jorgensen and Fejerskov, 1998;Raaen et al., 2006). The FCP can then be estimated from the pres-sure decay curve by a variety of methods, with the double tangentor root time methods most commonly used (Enever, 1993; Raaenet al., 2006). These techniques all require the pressure decay tobe monitored for a long duration after the pumps are shut-in(generally >10 min; Enever et al., 1996; Jorgensen and Fejerskov

Motivated by Mud Logging data processing in petroleum exploitation, the detection of changes in data line direction is studied in this paper. Because of noise corruption to all measured variables, the classical regression model is not suitable. After an appropriate formulation of noise corrupted data line, the problem of noise covariance matrix estimation is first considered, then a numerically efficient generalized likelihood ratio test is derived for direction change detection. This detection method, applied to Mud Logging data processing, is now integrated in INFACT, an industrial software for petroleum exploitation.

For several decades, wells drilled in Sudan Block 6 have experienced serious hole-instability problem related to drilling fluids due to the highly reactive and dispersive shales existing in the Aradeiba and Abu Gabra formations. The problem included washed out hole sections combined with tight hole, as well as serious sloughing shale. Frequent wiper trips were frequently required and logging of the wells was not usually successful. Previously, several conventional inhibitive water-based drilling fluids such as KCl/polymer, KCl/lime/polymer, and KCl/PHPA have been used in this area, but with only marginal improvements in hole stability and drilling performance. Recently, a newly formulated KCl/sodium silicate system, which overcome the fatal drawbacks of the silicate-based mud systems used previously and characterized by the perfect rheological properties and filtration control, was developed and applied to provide the necessary inhibitive character. The first trial well was drilled with this kind of drilling fluid in Sudan Block 6 and the following benefits were observed: (1) Excellent integrity exhibited by drilled cuttings for shale formations; (2) Stable borehole kept with lower mud weight; (3) Reduced wiper trips; (4) In-gauge borehole shown from caliper logs. Later on, five more wells were drilled with the KCl/sodium silicate drilling fluids in this area. It was found that this kind of drilling fluid could fully meet the demands of drilling operations in this area. Case studies were presented in this paper in terms of wiper trip, inhibitive character of cuttings, hole conditions and mud weight. This newly formulated silicate-based drilling fluid is currently applied in Block 3/7 and Block 6, Sudan widely.

Despite the use of inhibitive water-based mud (KCl), high pump rates to obtain good hole cleaning and relatively high mudweight, problems with cavings, pack-offs and lost circulation persisted when drilling Tertiary shale formations in the Heidrun field offshore Mid-Norway. A study was therefore initiated, including extensive data collection (logging and coring of the shale) and subsequent core testing, data analysis and evaluation of field experience. The study showed that the major problem zone was not the low-density zone as anticipated. However, the core revealed a fractured and crushed zone, which was eventually found to be the main source of the problem. The study has resulted in a new strategy. An improved borehole stability model has been established, and the mud and operational strategies have been revised. The mudweight has been reduced, the salt content of the mud has been reduced and good hole cleaning is obtained through a low-viscosity mud, which is kept close to turbulent flow. Furthermore, if possible, wells are now planned without steering in these formations. If steering cannot be omitted, 3-D rotary steerable systems are utilized. An economic evaluation of the study was also performed, showing a substantial benefit/cost ratio. So far, the cost reduction for an average well is close to 20 MNOK (ca. 2.5 million USD). With more than 50 wells left to drill in the field, the potential for cost-saving is large. Additionally, there is a huge and non-quantified effect from accelerated production.

In the Kuparuk River Unit 2D-15 well, on the North Slope of Alaska, a 60 m-thick stratigraphic interval that lies within the theoretical pressure-temperature field of gas-hydrate stability is inferred to contain methane hydrates. This inference is based on interpretations from well logs: (1) release of methane during drilling, as indicated by the mud log, (2) an increase in acoustic velocity on the sonic log, and (3) an increase of electrical resistivity on the electric logs. Our objective was to determine the composition and source of the gas within the shallow gas-hydrate-bearing interval based on analyses of cutting gas. Headspace gas from canned drill cuttings collected from within the gas-hydrate-bearing interval of this well has an average methane to ethane plus propane [C1/(C2+ C 3)] ratio of about 7000 and an average methane δ13C value of −46% (relative to the PDB standard). These compositions are compared with those obtained at one well located to the north of 2D-15 along depositional strike and one down-dip well to the northeast. In the well located on depositional strike (Kuparuk River Unit 3K-9), gas compositions are similar to those found at 2D-15. At the down-dip well (Prudhoe Bay Unit R-1), the C1/(C2 +C3) ratios are lower (700) and the methane δ13C is heavier (−33%). We conclude that the methane within the stratigraphic interval of gas hydrate stability comes from two sources— in situ microbial gas and migrated thermogenic gas. The thermal component is greatest at Prudhoe Bay. Up-dip to the west, the thermogenic component decreases, and microbial gas assumes more importance.

Drilling by the Ministry of Works for geothermal steam has been carried out in New Zealand almost continuously since 1950. Production hole drilling on the Wairakei project ceased in 1965 and since that date emphasis has been on investigation drilling in other areas along the broad thermal belt which passes through Wairakei in a NNE direction. Light rotary rigs are used for consolidation grouting, workovers and for drilling shallow (up to 2000 ft) monitor bores. Light oil rigs have continued to be used for drilling production bores to 2500 ft and investigation bores to 4600 ft with improved techniques and equipment. A new medium depth oil rig was obtained in 1968 with a nominal depth rating of 7500 ft. Ancillary equipment included a comprehensive instrumentation system, remote blow-out preventer controls and centrifugal mud distribution pumps. Additional mud storage is provided and a layout has been designed based on past experience. Two holes have already been drilled to approximately 7500 ft to examine production fields at depth. Details of drilling strings, casing programmes and wellheads are fully covered and information given on drilling bit performances. Mud properties have been improved with the use of lignosulphonate thinners and the local non swelling bentonite continues to give a useful and economical drilling fluid. Quantities used and costs of bentonite and additives are included. Hole deviation has been further attempted on one hole and completed satisfactorily. Electric down-hole perforating equipment is now in use and has virtually replaced the bullet gun formerly used for perforating casing for production and testing purposes. Downhole electric logging has been carried out but has been found to be of little value with the present equipment limitations. All drilling operations including cementing and other services continues to be carried out entirely by Ministry personnel.

Since the first exploratory drilling of AR-1 hole in 1960 twelve holes have been drilled in Matsukawa geothermal area, that is, six wild-cat holes and six production holes of 325–1500 meter depth. It was found from the result of the above drillings that most of the hot water and the steam of that area exist in the fractured zone lying near the boundary between Yamatsuda formation and Tamagawa welded tuff at the depth of about 1000 meters. Therefore, further drilling is being carried out aiming at that zone. The problems met on drilling technique are many. Some have already been solved, and some not yet. Characteristics of the area are that the wells are comparatively deep geothermal wells, rocks are hard, temperature is high and mud escape occurs frequently. Different drilling rigs were used according to the depth of 500, 1000, or 1500 meters. Chromnite mud comparatively stable in high temperature was used for the circulated fluid. As regards a rock bit, the ones of hard type were adopted all over. Pure water was used in case of mud escape. Above are the points devised in our plant for the improvement of the drilling technique of geothermal wells. Unsolved problems will also be solved in near future.

Owing to high thermality in areas where harnessing of endogenous steam takes place, an accurate choice of the type of circulating mud proves necessary in order to maintain the drilling fluid properties when temperatures exceed 140 °C. Along with high temperature effects, an analysis is made of alterations of mud constituents because of the most frequent contaminations due to the presence of clays, anhydrites and gypsum. High temperatures undoubtedly favour the alteration of some products in mud and speed up particular chemical reactions. This brings about the flocculation of solid matter and the consequent variation of rheological properties. Different kinds of mud and additives suitable for high-temperature operations have been investigated. An account is given, finally, on the costs of drilling muds in different operational conditions. The frequent fractures and cracks of geological formations under examination are borne in mind, and the problem of circulation losses is accordingly dealt with in order to indicate filling-up systems of current use.