Fluid property identification of the Lower Cretaceous reservoirs with complex oil-water contacts in Deseo Basin,Chad

Recently,exploration breakthroughs have been made in the Lower Cretaceous sandstone reservoirs in the Doseo Basin,but the identification of reservoir fluid property is difficult due to variable reservoir lithology,complex oil-water contact within and faint responses of the oil zone,which causes the lower accuracy of reservoir fluid property identification with conventional mudlogging and wirelogging techniques.Applying the geochemical logging,fluorescent logging,mud logging and cutting logging technology,in combination with formation test data,this paper distinguishes the crude oil types,analyzes the logging response characteristics of oil zone after water washing,and establishes the interpretation charts and parameter standards for reservoir fluid properties.The crude oil can be divided into two types,namely viscous-heavy and thin-light,based on total hydrocarbon content and component concentration tested by mud logging,features of pyrolysis gas chromatogram and fluorescence spectroscopy.The general characteristics of oil layers experienced water washing include the decrease of total hydrocarbon content and component concentration from mud logging,the decrease of S1 and PS values from geochemical logging,the decrease of hydrocarbon abundance and absence of some light components in pyrolysis gas chromatogram,and the decrease of fluorescence area and intensity from fluorescence logging.According to crude oil types,the cross plots of S1 versus peak-baseline ratio,and the cross plots of rock wettability versus fluorescence area ratio are drawn and used to interpret reservoir fluid property.Meanwhile,the standards of reservoir fluid parameter are established combining with the parameters of PS and the parameters in above charts,and comprehensive multiparameter correlation in both vertical and horizontal ways is also performed to interpret reservoir fluid property.The application in the Doseo Basin achieved great success,improving interpretation ability of fluid property in the reservoir with complex oil-water contact,and also provided technical reference for the efficient exploration and development of similar reservoirs.

“Component flow”conditions and its effects on enhancing production of continental medium-to-high maturity shale oil

Based on the production curves,changes in hydrocarbon composition and quantities over time,and production systems from key trial production wells in lacustrine shale oil areas in China,fine fraction cutting experiments and molecular dynamics numerical simulations were conducted to investigate the effects of changes in shale oil composition on macroscopic fluidity.The concept of“component flow”for shale oil was proposed,and the formation mechanism and conditions of component flow were discussed.The research reveals findings in four aspects.First,a miscible state of light,medium and heavy hydrocarbons form within micropores/nanopores of underground shale according to similarity and intermiscibility principles,which make components with poor fluidity suspended as molecular aggregates in light and medium hydrocarbon solvents,such as heavy hydrocarbons,thereby decreasing shale oil viscosity and enhancing fluidity and outflows.Second,small-molecule aromatic hydrocarbons act as carriers for component flow,and the higher the content of gaseous and light hydrocarbons,the more conducive it is to inhibit the formation of larger aggregates of heavy components such as resin and asphalt,thus increasing their plastic deformation ability and bringing about better component flow efficiency.Third,higher formation temperatures reduce the viscosity of heavy hydrocarbon components,such as wax,thereby improving their fluidity.Fourth,preservation conditions,formation energy,and production system play important roles in controlling the content of light hydrocarbon components,outflow rate,and forming stable“component flow”,which are crucial factors for the optimal compatibility and maximum flow rate of multi-component hydrocarbons in shale oil.The component flow of underground shale oil is significant for improving single-well production and the cumulative ultimate recovery of shale oil.

Study on the Impact of Massive Refracturing on the Fracture Network in Tight Oil Reservoir Horizontal Wells

Class III tight oil reservoirs have low porosity and permeability,which are often responsible for low production rates and limited recovery.Extensive repeated fracturing is a well-known technique to fix some of these issues.With such methods,existing fractures are refractured,and/or new fractures are created to facilitate communication with natural fractures.This study explored how different refracturing methods affect horizontal well fracture networks,with a special focus on morphology and related fluid flow changes.In particular,the study relied on the unconventional fracture model(UFM).The evolution of fracture morphology and flow field after the initial fracturing were analyzed accordingly.The simulation results indicated that increased formation energy and reduced reservoir stress differences can promote fracture expansion.It was shown that the length of the fracture network,the width of the fracture network,and the complexity of the fracture can be improved,the oil drainage area can be increased,the distance of oil and gas seepage can be reduced,and the production of a single well can be significantly increased.

Genesis and distribution of oils in Mahu Sag,Junggar Basin,NW China

Based on the geological and geochemical analysis of potential source rocks in different formations and the classification of crude oil types,combined with the hydrocarbon generation thermal simulation experiments,the source,genesis,and distribution of different types of oils in the Mahu large oil province of the Junggar Basin are investigated.Four sets of potential source rocks are developed in the Mahu Sag.Specifically,the source rocks of the Permian Fengcheng Formation have the highest hydrocarbon generation potential and contain mainly TypesⅡandⅠorganic matters,with a high oil generation capacity.In contrast,the source rocks in other formations exhibit lower hydrocarbon generation potential and contain mainly TypeⅢorganic matter,with dominant gas generation.Oils in the Mahu Sag can be classified as three types:A,B and C,which display ascending,mountainous and descending C_(20)-C_(21)-C_(23)tricyclic terpenes abundance patterns in sequence,and gradually increasing relative content of tricyclic terpenes and sterane isomerization parameters,indicating an increasing oil maturity.Different types of oils are distributed spatially in an obviously orderly manner:Type A oil is close to the edge of the sag,Type C oil is concentrated in the center of the sag,and Type B oil lies in the slope area between Type A and Type C.The results of oil-source correlation and thermal simulation experiments show that the three types of oils come from the source rocks of the Fengcheng Formation at different thermal evolution stages.This new understanding of the differential genesis of oils in the Mahu Sag reasonably explains the source,distribution,and genetic mechanism of the three types of oils.The study results are of important guidance for the comprehensive and three-dimensional oil exploration,the identification of oil distribution in the total petroleum system,and the prediction of favorable exploration areas in the Mahu Sag.

Factors influencing oil recovery by surfactant-polymer flooding in conglomerate reservoirs and its quantitative calculation method

This study aims to clarify the factors influencing oil recovery of surfactant-polymer(SP)flooding and to establish a quantitative calculation model of oil recovery during different displacement stages from water flooding to SP flooding.The conglomerate reservoir of the Badaowan Formation in the seventh block of the Karamay Oilfield is selected as the research object to reveal the start-up mechanism of residual oil and determine the controlling factors of oil recovery through SP flooding experiments of natural cores and microetching models.The experimental results are used to identify four types of residual oil after water flooding in this conglomerate reservoir with a complex pore structure:oil droplets retained in pore throats by capillary forces,oil cluster trapped at the junction of pores and throats,oil film on the rock surface,isolated oil in dead-ends of flow channel.For the four types of residual oil identified,the SP solution can enhance oil recovery by enlarging the sweep volume and improving the oil displacement efficiency.First,the viscosity-increasing effect of the polymer can effectively reduce the permeability of the displacement liquid phase,change the oil-water mobility ratio,and increase the water absorption.Furthermore,the stronger the shear drag force of the SP solution,the more the crude oil in a porous medium is displaced.Second,the surfactant can change the rock wettability and reduce the absorption capacity of residual oil by lowering interfacial tension.At the same time,the emulsification further increases the viscosity of the SP solution,and the residual oil is recovered effectively under the combined effect of the above two factors.For the four start-up mechanisms of residual oil identified after water flooding,enlarging the sweep volume and improving the oil displacement efficiency are interdependent,but their contribution to enhanced oil recovery are different.The SP flooding system primarily enlarges the sweep volume by increasing viscosity of solution to start two kinds of residual oil such as oil droplet retained in pore throats and isolated oil in dead-ends of flow channel,and primarily improves the oil displacement efficiency by lowing interfacial tension of oil phase to start two kinds of residual oil such as oil cluster trapped at the junction of pores and oil film on the rock surface.On this basis,the experimental results of the oil displacement from seven natural cores show that the pore structure of the reservoir is the main factor influencing water flooding recovery,while the physical properties and original oil saturation have relatively little influence.The main factor influencing SP flooding recovery is the physical and chemical properties of the solution itself,which primarily control the interfacial tension and solution viscosity in the reservoir.The residual oil saturation after water flooding is the material basis of SP flooding,and it is the second-most dominant factor controlling oil recovery.Combined with the analysis results of the influencing factors and reservoir parameters,the water flooding recovery index and SP flooding recovery index are defined to further establish quantitative calculation models of oil recovery under different displacement modes.The average relative errors of the two models are 4.4%and 2.5%,respectively;thus,they can accurately predict the oil recovery of different displacement stages and the ultimate reservoir oil recovery.

Formation conditions and exploration direction of large natural gas reservoirs in the oil-prone Bohai Bay Basin, East China

The Bohai Bay Basin is a typical oil-prone basin, in which natural gas geological reserves have a small proportion. In this basin, the gas source rock is largely medium-deep lake mudstone with oil-prone type Ⅱ2-Ⅱ1 kerogens, and natural gas preservation conditions are poor due to active late tectonic movements. The formation conditions of large natural gas fields in the Bohai Bay Basin have been elusive. Based on the exploration results of Bohai Bay Basin and comparison with large gas fields in China and abroad, the formation conditions of conventional large-scale natural gas reservoirs in the Bohai Bay Basin were examined from accumulation dynamics, structure and sedimentation. The results show that the formation conditions of conventional large natural gas reservoirs in Bohai Bay Basin mainly include one core element and two key elements. The core factor is the strong sealing of Paleogene "quilt-like" overpressure mudstone. The two key factors include the rapid maturation and high-intensity gas generation of source rock in the late stage and large scale reservoir. On this basis, large-scale nature gas accumulation models in the Bohai Bay Basin have been worked out, including regional overpressure mudstone enriching model, local overpressure mudstone depleting model, sand-rich sedimentary subsag depleting model and late strongly-developed fault depleting model. It is found that Bozhong sag, northern Liaozhong sag and Banqiao sag have favorable conditions for the formation of large-scale natural gas reservoirs, and are worth exploring. The study results have important guidance for exploration of large scale natural gas reservoirs in the Bohai Bay Basin.

Oil source and accumulation in the overthrust belt in the Ke-Bai region,Junggar Basin,west China

The region around the Karamay-Baikouquan （Ke-Bai） overthrust belt is the richest in hydrocarbon accumulation in the Junggar Basin. Previous research has indicated that oil in the region came from the Fengcheng Formation in the Mahu Depression to the northeast of the region, but the oil distribution around the Mahu Depression is remarkably uneven. Large amounts of oil have been found in the Ke-Bai overthrust belt to the west of the depression and only some small oilfields have been discovered in the eastern margin of the depression. This uneven distribution revealed that the oil source of the Ke- Bai region might not be from the Mahu Depression. The oil type distribution and the oil migration pattern revealed in this paper showed that there may be another oil source under the Karamay overthrust. Based on geochemical data, the oil was classified into two types from the sterane and terpane characteristics. Type A oil was mainly distributed in the Huwan area and blocks V and VIII of the Karamay Oilfield in the southern part of the region, while type B oil was mainly distributed in the Baikouquan Oilfield in the northern part of the region. In addition, oil migration pathways and direction were determined by the values of diasterane / regular sterane and C30 moretane / C30 hopane ratios. It is shown that the oil of Huwan area on the hanging wall of the overthrust was mainly charged along the overthrust fault surfaces and then migrated to the west, whereas the oil in blocks V and VIII on the foot wall of the overthrust came from the Mahu Depression in the east. As a result, there may be at least two hydrocarbon source kitchens in the study area. The hydrocarbons in the blocks V and VIII on the footwall of the overthrust belt and in the Baikouquan Oilfield mainly came from the Fengcheng Formation in the Mahu Depression, and the hydrocarbons in the Huwan area on the hanging wall of the overthrust belt may come from another hydrocarbon source kitchen below the overthrust. This recognition indicates that there is substantial exploration potential in the deep Carboniferous strata on the hanging wall of the overthrust belt.

Novel Tetracyclic Terpanes in Crude Oils and Source Rock Extracts in Pearl River Mouth Basin and Their Geological Significance

Novel tetracyclic terpanes X and Y namely C24-des-A-oleanane and C27 tetracyclic terpane were detected in crude oils and source rock extracts in Zhu 1 depression in Pearl River Mouth Basin by GC-MS analysis technology. These compounds are similar to oleanane in the structure, and their relative abundance in m/z 191 partial mass cbromatogram has a good correlation with oleanane. Here compounds X and Y are considered to be derived from the des-A degradation of oleanoid precursor. The ratio of X/（X-I-C24） and Y/（Y-I-C24） increase with the increasing inputs of terrigenous organic matter in crude oils. Wenchang Formation middle-deep lacustrine source rocks with planktonic algae organic matter inputs and oil generating from it contain low abundance of compounds X and Y, while Enping Formation coal measures source rocks with terrigenous higher plants organic matter inputs and oil generating from it usually have higher compounds X and Y. In general when two terrigenous compounds C19 tricyclic terpane and bicadinane-T are high in crude oils, there are also a corresponding high abundant compounds X and Y. Relative abundance of compounds X and Y is closely related to the source of organic matter and it can indicate the input of terrigenous organic matter.