Mud Logging Data Research Articles

Petro-physical analysis of well logs for reservoir evaluation: a case study of Well 1 and 2 of the ‘Ictorian’ field in the Niger Delta Basin

This study presents the log analysis results of a suite of conventional wireline logs including gamma ray, density, neutron, and resistivity from two wells in ‘Ictorian’ Field located in the Niger delta with the aim of evaluating hydrocarbon prospect of the field. Results obtained showed presence of hydrocarbon in eleven (11) reservoirs from well 1, and four (4) reservoirs from well 2. Well 1 and 2 both had hydrocarbon reservoir bearing gas. Well 1 had Gas Water contact at 2497m and 2964m, while well 2 had Gas water Contacts at 1739m and 2510m. Effective porosities had values ranging from 26-16% in well 1. In well 2, effective porosities had values ranging from 22-17%.The values obtained show that the analysed reservoirs have good permeability. The calculated values indicate that porosity, permeability values from the hydrocarbon bearing reservoirs are good enough for commercial accumulation in the Niger Delta. It is recommended that for field optimization mud logging data and core data analysis should be integrated as part of the evaluation exercise.Keywords: Reservoir, petrophysical properties, reservoir quality, wireline logs

Productivity evaluation method of tight sandstone reservoir based on the logging curve

Strong heterogeneity, poor pay reservoir connectivity, and complex micro-pore structure are the reasons behind the high difficulty and low accuracy in the productivity evaluation of tight sandstone gas reservoirs. This paper utilized various well logging and mud logging curve data, summarizes the typical curve type, and made use of a mathematical method to form quantitative characterization. Additionally, a logging curve evaluation method is proposed based on the test of production capacity. The total hydrocarbon curve can be divided into six types as shown by the results: box shape, half box shape, upright triangle, inverted triangle, sawtooth shape, single peak, etc. The above is closely related to the level of oil and gas in the reservoir layer. Six types of total hydrocarbon curve can be quantified by amplitude, relative centroid, relative sawtooth, variance, and the parameter value of the autocorrelation function. The box-shaped total hydrocarbon gas logging curve is full and has a large scale. The half box-shaped total hydrocarbon gas logging curve peak scale is significantly smaller than that of the reservoir thickness. The triangularly-shaped total hydrocarbon gas logging curve may either be an upright or inverted triangle. The sawtooth-shaped total hydrocarbon gas logging curve has high and low tendencies that show a number of spikes. Single peak-shaped total hydrocarbon gas logging curve is small with a single peak. There is a good relationship between the six kinds of total hydrocarbon gas logging curve and the tight sandstone gas reservoir production capacity. The high and middle gas pay layers are mainly box-shaped and triangular, whereas the lower production layer is half box-shaped, triangular, and has a zigzag pattern. However, the low gas pay layers mainly possess a sawtooth pattern, while the non-production layer is mainly single peak in shape. The comprehensive interpretation of the total hydrocarbon gas logging curve and log resistivity curve can more accurately distinguish the production capacity of tight sandstone gas reservoirs. Finally, the quantitative model is used for automatic interpretation. Through data verification and analysis, it is found that the coincidence rate of the production gas pay layer is 80.95%, whereas the coincidence rate of production capacity is 78.05%. It is proven by practice that the gas formation capacity of tight sandstone gas reservoirs can be predicted based on the logging and mud logging well curve shapes.

A machine learning approach to predict drilling rate using petrophysical and mud logging data

Predicting the drilling rate of penetration (ROP) is one approach to optimizing drilling performance. However, as ROP behavior is unique to specific geological conditions its application is not straightforward. Moreover, ROP is typically affected by various operational factors (e.g. bit type, weight-on-bit, rotation rate, etc.) as well as the geological characteristics of the rocks being penetrated. This makes ROP prediction an intricate and multi-faceted problem. Here we compare data mining methods with several machine learning algorithms to evaluate their accuracy and effectiveness in predicting ROP. The algorithms considered are: artificial neural networks (ANN) applying a multi-layer perceptron (MLP); ANN applying a radial basis function (RBF); support vector regression (SVR), and an hybrid MLP trained using a particle swarm optimization algorithm (MLP-PSO). Data preparation prior to executing the algorithms involves applying a Savitzky–Golay (SG) smoothing filter to remove noise from petrophysical well-logs and drilling data from the mud-logs. A genetic algorithm is applied to tune the machine learning algorithms by identifying and ranking the most influential input variables on ROP. This tuning routine identified and selected eight input variables which have the greatest impact on ROP. These are: weight on bit, bit rotational speed, pump flow rate, pump pressure, pore pressure, gamma ray, density log and sonic wave velocity. Results showed that the machine learning algorithms evaluated all predicted ROP accurately. Their performance was improved when applied to filtered data rather than raw well-log data. The MLP-PSO model as a hybrid ANN demonstrated superior accuracy and effectiveness compared to the other ROP-prediction algorithms evaluated, but its performance is rivalled by the SVR model.

Sedimentary lithofacies characteristics and sweet-spot interval characterization of the Sinian Doushantuo Formation in Upper Yangtze Platform, South China

ABSTRACT The Sinian Doushantuo Formation is the oldest shale gas reservoir discovered in the world, which contains good shale gas shows as the Eyangye-1 and Zidi-1 wells in the Yichang Region of western Hubei province, China. The shales in the Doushantuo Formation feature considerable thickness (135 m), high gas content (4.83 m3/t) and high fragile mineral content (up to 75%). Due to the influences of the sedimentary environment, the shale reservoirs here have high dolomitic content (54%) and abruptly changes in vertical lithofacies. Moreover, the characteristics of the shale sweet-spot differ significantly from that in the Wufeng Formation and Longmaxi Formation in southeast Sichuan Basin. A high-resolution sequence stratigraphic correlation was performed on the shales of the Doushantuo Formation at the Eyangye-1 well, Zidi-1 well, Zidi-2 well and some outcrop profiles in Yichang area for the identification of their sedimentary microfacies characteristics. A comprehensive comparative analysis was made by incorporating the elemental geochemistry, wireline and mud logging data of the well to further identify the sweet-spot interval therein. With the analysis of Eyangye-1 well, the sweet-spot interval of the Doushantuo Formation is 3360−3408 m, of which sedimentary microfacies is deepwater reduced environment with many pyrite laminaes, and the TOC is high to 3.42%, the Ro is 3.3%, the organic and matrix pore are well developed and the aperture more than 50 nm, the porosity is 2.7%, the desorption gas content average is 2.16%, and the main mineral is dolomitic (54%) and siliceous quartz (21%). Additionally, these parameters combined with previous studies will shed light on evaluating and characterizing the layers therein, also provide referential geological data for the following exploration and development activities of this shale system.

Comparison of Oil Well Productivity Evaluation Methods Based on Different Data

Accurate prediction of well productivity is important to take proper engineering measures, and it has an important value on the increased cost of oil and gas exploration and development. Variety of different reservoir evaluation methods for well productivity based on different data, such as seismic data, mud logging data, well logging data, well testing data, formation test data etc. was compared in this paper, and the scale, scope and implications of the methods evaluation were also described. This provides a theoretical basis for comprehensive reservoir productivity assessment research, and can be a guidance for comprehensive evaluation of reservoir productivity based on variety of test data.

Construction of a 3D Geomechanical Model for Development of a Shale Gas Reservoir in the Sichuan Basin

SummaryCurrently, there is large-scale shale gas exploration and development in the Sichuan Basin, western China. Caused by high tectonic stress and presence of fracture systems at various scales in the lower Silurian Longmaxi reservoir formation, hydraulic fracturing in shale gas reservoirs in the Sichuan Basin has encountered many difficulties, such as placing sufficient proppant, poor-production performance for some wells, and ambiguity as to the factors controlling the production of reservoirs. It has been recognized that lack of geomechanical understanding of the shale gas reservoirs is a major obstacle to effectively addressing these difficulties.A 3D full-field geomechanics model was constructed for the Changning shale gas reservoir in the Sichuan Basin through integrating seismic, geological structure, log, and core data by following a newly formulated work flow. The 3D geomechanical model includes 3D anisotropic mechanical properties, 3D pore pressure, and the 3D in-situ stress field. Through leveraging measurements from an advanced sonic tool and core data, the anisotropy of the formation was captured at wellbores and propagated to 3D space guided by prestack seismic inversion data. The 3D pore-pressure prediction was conducted with seismic data, and calibrated against pressure measurements, mud-logging data, and flowback data. A discrete-fracture-network (DFN) model, which represents multiscale natural-fracture systems, was integrated into the 3D geomechanical model during stress modeling to reflect the disturbance on the in-situ stress field by the presence of the natural-fracture systems.The 3D pore-pressure model was used to calculate more-reliable estimates of gas in place in the shale gas reservoir, and the geomechanical model was used to reveal the root cause of difficulties of proppant placement in this tectonically active and unevenly fractured shale gas reservoir.The paper presents the highlights and innovations in constructing the 3D geomechanical model for the shale gas reservoir, and explains how the 3D geomechanical model is used to address technical challenges encountered during drilling and completion. Also, it demonstrates that a reliable 3D geomechanical model, with proper characterization of anisotropy, pore pressure, and natural fractures, provides a critical opportunity to improve the development in this shale gas reservoir.

Coalbed methane accumulation conditions and enrichment models of Walloon Coal measure in the Surat Basin, Australia

The coal measure of Middle Jurassic Walloon Subgroup is the main reservoir of coalbed methane (CBM) reservoirs in the Surat Basin, Australia, and it is a set of typical low-rank, high-yield coal measure. To figure out the CBM accumulation conditions and enrichment models of this coal measure, its distribution characteristics, source rock characteristics, reservoir characteristics and preservation conditions were investigated based on mud logging, experimental and testing data. Then, based on the analysis results of gas origin and gas bearing property of this coal measure, 3 CBM development areas in northeastern Surat Basin were analyzed and compared in terms of its gas enrichment model, and favorable conditions for CBM accumulation and enrichment of Walloon coal measure (WCM) was summarized. It is indicated that tectonic movements, groundwater conditions and macerals provide favorable conditions for gas generation of Walloon coal. The roof, floor and interbed of this coal measure are lithologically tight, presenting a good sealing capacity. Besides, the Walloon CBM reservoir is a mixed origin gas reservoir with the secondary biogenic methane as the dominant component formed in a monocline structure jointly sealed by hydrodynamic force and lithology. CBM enrichment is controlled by 3 factors, i.e., local structure, methane generating capacity of coal bed and underground hydrodynamic force, and it can be divided into 3 models, i.e., anticline model, syncline model and slope model, among which, the CBM enrichment degree of the former two models is higher. Finally, different from other CBM reservoirs, the Walloon CBM reservoir satisfies four favorable conditions in CBM accumulation and enrichment, including dual-carbon source, efficient methane generation, moderate hydrodynamic force and double sealing.

Pore structure of shale and its effects on gas storage and transmission capacity in well HD-1 eastern Sichuan Basin, China

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.

Drilling rate prediction from petrophysical logs and mud logging data using an optimized multilayer perceptron neural network

Rate of penetration (ROP) enhancement serves as a key factor in reducing drilling time and hence drilling costs. ROP enhancement requires identification of the parameters affecting this rate. However, the large number of effective parameters, which are further immersed in noise, makes it difficult to present a highly accurate and comprehensive model. In the present research, in order to predict the drilling ROP in one of the vertical wells drilled into the Karanj Oilfield, a hybrid model composed of a multilayer perceptron (MLP) neural network together with either a particle swarm optimization (PSO) algorithm or a cuckoo optimization algorithm (COA) was used. For this purpose, first petrophysical logs and drilling data were denoised using the Savitzky–Golay filter. Then, the 'plus-l-take-r' method was used to select superior features. Feature selection results indicated that an increase in the number of input parameters tends to reduce the error associated with the estimator model; however, the error reduction rate was seen to be negligible for models with five or more input parameters. Therefore, five parameters were considered as input parameters in MLP-COA and MLP-PSO hybrid models: rotary speed, weight on bit, shear wave slowness, compressional wave slowness, and flow rate. A comparison of errors and coefficients of determination in the training phase of the two models indicated that MLP-COA model tended to converge way faster and more accurately. The small difference in generated error using this model between training and testing phases indicated the high reliability and generalizability of the model. Comparing the results of the model trained with raw and denoised data against the same set of selected features clearly showed the positive effect of the denoising step on the accuracy of the model. Validation of the proposed model via the multilinear regression method was indicative of the superior performance of the MLP-COA model, so that it could be confidently stipulated that this model can be used to estimate the ROP at other vertical wells near the studied well. Further, provided the required information is available, this method can predict the ROP to high accuracy in vertical oil and gas wells.

Effects of near surface lithology on velocity modelling and time–depth relationships in the Cooper–Eromanga–Lake Eyre Basin

Structural closures on the western flank of the Patchawarra Trough in the Cooper–Eromanga Basin are truly low relief; drilling opportunities regularly target hydrocarbon columns of similar magnitude to the uncertainty of depth prediction. Improving the accuracy and precision of depth prediction will reduce risk for drilling opportunities, and improve drilling success rates. A detailed study of the near surface geology (surface to ~500 m depth) of the western flank of the Patchawarra Trough has been undertaken to better understand the effect of observed geological variations of the near surface on depth prediction at deeper target levels. The stratigraphic interval investigated includes the top of the Eromanga Basin and the entire Lake Eyre Basin, which is sparingly studied and routinely overlooked in the statics and velocity modelling process. This study analysed recently acquired cased-hole sonic logs in conjunction with gamma logs and mudlog data to map out the observed geological variations, and construct a 3D velocity model of the near surface. Variations of layer thickness and seismic velocity were input into Monte Carlo simulations to investigate sensitivities of each formation on two-way travel time and depth prediction. This investigation has found that velocity variations of the Weathered Winton Formation, and thickness variations of the Namba Clastics have the greatest impact on imaging of structures at depth. Independently, these have the potential to completely conceal or create structures in the time domain. Continued efforts in improved understanding of the near surface will subsequently lead to enhanced imaging of structures, which can then be used in the mapping of structural closures in petroleum exploration and development.

Genetic types and sedimentary model of sandbodies in a shallow-water delta: A case study of the first Member of Cretaceous Yaojia Formation in Qian'an area, south of Songliao Basin, NE China

Abstract Based on outcrop, core, logging and mud logging data, and modern deposition analog, the sandbodies genetic types and spatial distribution in different facies belts of the shallow water delta in the first Member of Cretaceous Yaojia Formation (K2y1) of Qian'an area in Changling sag of southern Songliao Basin were analyzed, and the sedimentary model of shallow water delta was established according to deposition process. Active channel sandbodies, point bar sandbodies and bifurcation bar sandbodies in distributary channels and complex sandbodies formed the main sandbodies in the delta plain, while terminal distributary channels and mouth bar sandbodies formed the main sandbodies in the delta front. The delta prograded gradually under the construction of river mouth and reconstruction of river erosion, the early delta front evolved into delta plain and was reformed by distributary channels, and new delta fronts were formed at the river mouth ahead constantly. Under the control of the above deposition process, the size of main distributary channels in delta plain-delta front declined, while mouth bars developed increasingly. The sandbodies of different genetic types formed framework of river-dominated shallow water delta. The point bar and active channel sandbodies in main distributary channels of the delta, with the best reservoir quality, are lithologic reservoir targets in future exploration.

Occurrence and distribution characteristics of fluids in tight sandstone reservoirs in the Shilijiahan zone, northern Ordos Basin

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 CaCl2 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 CaCl2 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.

Real-Time Pore Pressure Detection: Indicators and Improved Methods

High uncertainties may exist in the predrill pore pressure prediction in new prospects and deepwater subsalt wells; therefore, real-time pore pressure detection is highly needed to reduce drilling risks. The methods for pore pressure detection (the resistivity, sonic, and corrected d-exponent methods) are improved using the depth-dependent normal compaction equations to adapt to the requirements of the real-time monitoring. A new method is proposed to calculate pore pressure from the connection gas or elevated background gas, which can be used for real-time pore pressure detection. The pore pressure detection using the logging-while-drilling, measurement-while-drilling, and mud logging data is also implemented and evaluated. Abnormal pore pressure indicators from the well logs, mud logs, and wellbore instability events are identified and analyzed to interpret abnormal pore pressures for guiding real-time drilling decisions. The principles for identifying abnormal pressure indicators are proposed to improve real-time pore pressure monitoring.

The geology of offshore drilling through basalt sequences: Understanding operational complications to improve efficiency

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.

Characteristics and genesis of the (Sinian) Dengying Formation reservoir in Central Sichuan, China

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.

Correlation of Penetration Rate with Drilling Parameters For an Iraqi Field Using Mud Logging Data

This paper provides an attempt for modeling rate of penetration (ROP) for an Iraqi oil field with aid of mud logging data. Data of Umm Radhuma formation was selected for this modeling. These data include weight on bit, rotary speed, flow rate and mud density. A statistical approach was applied on these data for improving rate of penetration modeling. As result, an empirical linear ROP model has been developed with good fitness when compared with actual data. Also, a nonlinear regression analysis of different forms was attempted, and the results showed that the power model has good predicting capability with respect to other forms.

How do permeable fractures in the Triassic sediments of Northern Alsace characterize the top of hydrothermal convective cells? Evidence from Soultz geothermal boreholes (France)

The thermal regime of the Upper Rhine Graben (URG) is characterized by a series of anomalies near Soultz-sous-Forêts (France), Rittershoffen (France), and Landau (Germany). These temperature anomalies are associated with groundwater circulation in fractures and faults distributed in the Cenozoic and Mesozoic sedimentary cover associated with and connected to fractures originating deep within the Paleozoic basement. The present study helps to understand the convective cell structure in order to optimize geothermal borehole trajectories. The work concentrated on a detailed interpretation of the geophysical and geological logs from Soultz geothermal wells mainly from the topographic surface to the Triassic formations, at between 800- and 1,400-m depth above the deep granitic basement. The analysis of drilling mud logging data and geophysical well logging data from the deep Soultz geothermal wells (GPK-2, GPK-3, GPK-4) reveals the occurrence of nine fracture zones situated at depths greater than 900 m in the limestones of the Muschelkalk (Middle Trias) and the sandstones of the Buntsandstein (Lower Trias). Based on indications of total or partial mud losses, these fracture zones have been classified as permeable or impermeable. Permeable fractures between circa 900-m depth and 1,400-m depth are connected to a large-scale fault and control the top of the convective cells. There is no indication of permeability in the formations above the Keuper layer, and the uppermost part of the sedimentary cover acts as a cap rock, insulating the convective regime in the Triassic sediments and the granitic basement.

Quantitative calculation of GOR of complex oil-gas-water systems with logging data: A case study of the Yingdong Oil/Gas Field in the Qaidam Basin

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.

Infra-Cambrian play in Punjab Platform, Pakistan, with reference to Bikaner-Nagaur Basin, India

Infra-Cambrian play is established in the Bikaner-Nagaur Basin after the Baghewala-1 heavy oil discovery (628 MMBO) in 1991. On similar grounds, the Infra-Cambrian from Punjab Platform (PPF) is studied in this paper using published and unpublished data of drilling wells and seismic sections with an aim to establish petroleum play in Punjab Platform where no discovery has been made until now. The equivalent source, reservoir, and cap rocks are encountered in the drilled wells of Punjab Platform. Interpreted seismic sections of the study area are reinterpreted to observe the structural style which is capable of trapping the hydrocarbon migration. Seismic sections indicate that the Punjab Platform remained unfolded at Infra-Cambrian level in contrast with Bikaner-Nagaur Basin where folding and faulting were observed. It is predicted that the maturity in Punjab Platform prior to the Permian and any pre-existing structural closure has reached to early oil generation. The source rock evaluation at shallow locations in Punjab Platform indicates thermally immature which is considered as a major reason for failures of wells. But at deep wells, the conditions are different which may give prospective results in the area if further exploration is enhanced. Long-distance migration of hydrocarbons from Sulaiman foredeep (SFD) seems not possible due to the structural style between SFD and PPF; however, a local sourcing may have charged the Infra-Cambrian reservoirs in Punjab Platform. A correlation is established of sedimentary sequence from Recent to Infra-Cambrian down to basement of Indian and Pakistan PPF using well logs, seismic, and mud log data. Based on petrophysical properties such as water saturation, porosity, permeability, and aerial distribution of Infra-Cambrian reservoirs, the PPF seems favorable for the production of hydrocarbons in Punjab Platform, Pakistan, if further exploration is carried out.

Geological features and exploration potential of Permian Tiaohu Formation tight oil, Santanghu Basin, NW China

Abstract Based on seismic data, logging, mud logging and lab testing data, the geological features and exploration potential of Permian Tiaohu Formation tight oil were studied in Santanghu Basin, Hami Area, Xinjiang. The tight sedimentary tuff characterized as high porosity and low permeability is developed in the second member of Tiaohu Formation in Santanghu Basin, and its granularity is fine, nano-scale pores and throats account for 88.3%, its permeability is lower than 0.5×10−3 μm2. Because of high brittleness, the reservoir rocks are easy to be fractured, and its oil saturation and crude oil density are high. The oil in tight sedimentary tuff is mainly from the underlying Permian Lucaogou Formation high-quality source rocks with a 100−500 m interval between source rocks and reservoirs. The crude oil generated in source rocks migrated up to the second member of Tiaohu Formation along faults and fractures characterized as other-sourced charging and source-reservoir separating. Tight oil distribution is mainly controlled by Lucaogou Formation source rocks and second member of Tiaohu Formation sedimentary tuff reservoirs. The area of “sweet spots” in the second member of Tiaohu Formation of Malang-Tiaohu Sag is about 203 km2, and the oil resource is predicted to be 2.4×108 t.