Thin Reservoir Research Articles

Major advancement in oil and gas exploration of Jurassic channel sandstone in Well Bazhong 1HF in northern Sichuan Basin and its significance

In January 2023, Well Bazhong 1HF in the northern Sichuan Basin obtained high-yield industrial oil flow of over 100 cubic meters from the Jurassic channel sandstone for the first time, realizing a major breakthrough. In order to provide more support for further oil and gas exploration in this area, this paper analyzes the sedimentary and reservoir characteristics of the Jurassic Lianggaoshan Formation in Bazhong region of northern Sichuan Basin and their control factors based on the exploration achievements of Well Bazhong 1HF. Then, oil and gas reservoir characteristics and oil and gas sources are comparatively analyzed. Finally, the key technologies for the exploration of channel sandstone oil and gas with multi-stage vertical superimposition, lateral migration, thin reservoir and strong heterogeneity are researched and developed, and the next oil and gas exploration direction in the Lianggaoshan Formation of northern Sichuan Basin is pointed out. And the following research results are obtained. First, in the second member of Lianggaoshan Formation (“Liang 2 Member” for short) in Bazhong region, multi-stage underwater distributary sand bodies of delta front are developed with sandstone thickness of about 25 m and average porosity of 5.6%. The pore types are mainly primary intergranular pores and feldspar/debris intragranular dissolved pores, the pore throat structure is good, and the development of good-quality reservoirs is controlled by the sedimentary microfacies of underwater distributary channel. Second, the oil and gas reservoir of Liang 2 Member is a highly oil-bearing condensate gas reservoir/volatile oil reservoir, whose oil and gas is mainly sourced from the semi-deep lacustrine shale of Liang 1 and 2 Members. Third, channel sand bodies are superimposed and developed continuously in the upper part of Liang 2 and Liang 3 Members, and the source-reservoir configuration is good, with the characteristics of near-source hydrocarbon accumulation and overpressure hydrocarbon enrichment. Fourth, for the channel sandstones with multi-stage vertical superimposition, lateral migration, thin reservoir and strong heterogeneity, the reservoir prediction technology of “high-frequency sequence stratigraphy slice, seismic frequency decomposition and facies-constrained seismic waveform indication inversion” is developed to precisely characterize the “sweet spot” target of narrow channel sandstone, and the key fracturing technology of “dense cutting + composite temporary plugging + high-intensity proppant injection + imbibition and oil-increasing” is formed to realize the large-scale reconstruction of channel sandstone reservoir. In conclusion, the breakthrough of Well Bazhong 1HF in the exploration of Lianggaoshan Formation oil and gas in Bazhong region reveals the huge potential of Jurassic oil and gas exploration in the Sichuan Basin, and plays a positive role in promoting the exploration and development of the Jurassic channel sandstone oil and gas in the Sichuan Basin.

Geologic Causatives and Seismic Attributes Heterogeneities for Structural and Stratigraphic Interplays, Sitra Area, North Western Desert, Egypt

Sand-lithofacies distributions are a vital component of reservoir characterisation and the generation of successful reservoir models, particularly in thin reservoirs thickness. The integration between seismic attributes and conceptual geologic models is important to identify the sand distributions and reservoir geometries. The aim of this work is illustrating the uses of seismic data in revealing the structural and stratigraphic elements of two main reservoir units. It is important to identify and list the attributes, which can be involved in analysing the reservoirs and their degree of involvement in the characterisation of the hydrocarbon accumulation zones. The study was carried out for the reservoirs: Abu Roash C and Abu Roach E in Sitra oil and gas concession, which is located in the northern part of the Egyptian Western Desert. Four seismic attributes are used: 1- Coherence (Variance) 2- 3D Curvature attributes were used for resolving mainly the structural features and also the stratigraphic features 3- Instantaneous phase 4- Instantaneous frequency attributes were used mainly for resolving the stratigraphic features. Through the integration of selected seismic attributes with post-stack seismic data, reservoir distributions and architectures are accurately delineated for the Upper Cretaceous reservoir (Abu Roash ‘C’ and ‘E’). Five wells were used to match the results of the seismic attributes and establish the regional trends of reservoir parameters. The integration of wells data, conventional seismic interpretation and extracted the relevant seismic attributes help in reaching a robust geologic model for the reservoirs of interest. Stratigraphic and structural interpretation objectives based on extracting the seismic attributes for reservoir characterisation become more dominant, as they go deeper in seismic data, to derive more subsurface geologic data than traditional interpretation. 3D structure model of the concern area was established by interpreting the available seismic data as both reservoirs implicated by two fault trends: NW-SE and ENE-WSW. By the end a 3D geological model was defined based on the results of the conventional interpretation of the seismic and seismic attributes to reflect all structural and stratigraphic elements of the two reservoir units.

Recent Advances in the Study of In Situ Combustion for Enhanced Oil Recovery

Global estimates for our remaining capacity to exploit developed oil fields indicate that the currently recoverable oil (light oil) will last for approximately 50 years. This necessitates the development of viscous and superviscous oil fields, which will further compensate for the loss of easily produced oil. In situ combustion is the most promising production method, which allows for increased oil recovery from a reservoir. This being the case, this study provides an overview of global trends regarding the research and implementation of the method under consideration, in order to promote understanding of its applicability and effectiveness. The background to the development of the method is discussed in detail, illustrating the growing interest of researchers in its study. Cases of both successful as well as inefficient implementations of this method in real oil fields are considered. The main focus of the article is to investigate the influence of the parent rock and catalysts on the combustion process, as this is a new and actively developing area in the study of enhanced oil recovery using in situ combustion. Geological surveys, in addition to experimental and numerical studies, are considered to be the main methods that are used to investigate processes during in situ combustion. The analysis that we carried out led us to understand that the processes which occur during the combustion of heavy oil are practically unpredictable and, therefore, poorly understood. The specificity of the oil composition under consideration depends on the field, which can lead to a change in the required temperature regimes for its production. This indicates that there exists multiple specific applications for the method under consideration, each requiring additional full studies into both the fractional composition of oil and its reservoirs. The article also considers various technologies for implementing the in situ combustion method, such as ND-ISC, THAITM, COSH, CAGD, and SAGD. However, the literature review has shown that none of the technologies presented is widely used, due to the lack of an evidence base for their successful application in the field. Moreover, it should be noted that this method has no limits associated with the oil occurrence depth. This technology can be implemented in thin reservoirs, as well as in flooded, clayey, sandy, and carbonate reservoirs. The review we have presented can be considered as a guide for further research into the development of global solutions for using the proposed method.

Identification of thin gas reservoir in reflection seismic data by synchrosqueezing S-transform in time-frequency representation

Identification of thin gas reservoir in reflection seismic data by synchrosqueezing S-transform in time-frequency representation

Delineation of thin and discrete sand reservoir facies from shale-dominated Kopili Formation (Middle to Late Eocene) using the post-stack seismic inversion and neural network algorithm: A case study from Assam Basin, India

Delineation of thin and discrete sand reservoir facies from shale-dominated Kopili Formation (Middle to Late Eocene) using the post-stack seismic inversion and neural network algorithm: A case study from Assam Basin, India

Theory and Application of Geostatistical Inversion: A Facies-Constrained MCMC Algorithm

To improve the prediction of thin reservoirs with special geophysical responses, a geostatistical inversion technique is proposed based on an in-depth analysis of the theory of geostatistical inversion. This technique is based on the Markov chain Monte Carlo algorithm, to which we added the contents of facies-constrained. The feasibility of the technique and the reliability of the prediction results are demonstrated by a prediction of the sand bodies in the braided river channel bars in the Xiazijie Oilfield in the Junggar Basin. Based on the MCMC algorithm, the results show that leveraging the lateral changes in the seismic waveforms as geologically relevant information to drive the construction of the variogram and the optimization of the statistical sampling can largely overcome the obstacle that prevents traditional geostatistical inversions from accurately delineating the sedimentary characteristics; thereby, the proposed algorithm truly achieves facies-constrained geostatistical inversion. The case study of the Xiazijie Oilfield showed the feasibility and reliability of this technology. The prediction accuracy of the FCMCMC algorithm-based geostatistical inversion is as high as 6 m for thin interbedded reservoirs, and the coincidence rate between the prediction results and the well log data is more than 85%, which confirms the reliability of the technique. The demonstrated performance of the proposed technique provides a preliminary reference for the prediction of the thin interbedded reservoirs formed in terrestrial sedimentary basins and characterized by small thicknesses and rapid lateral changes with special geophysical responses.

A novel physics-based resolution improvement method for neutron-density log

In the later stages of oilfield development, the accurate identification of thin reservoirs become increasingly crucial for oil and gas exploration. However, conventional logs have limited vertical resolution, making it challenging to identify thin reservoirs. This results in potential hydrocarbon layers getting overlooked during exploration. To address this issue, a novel resolution enhancement method for density and neutron porosity logs based on physical constraint optimization is proposed. The proposed method involves three main steps: (1) developing an objective function that relates the true formation density and porosity to the measurement based on the physics of nuclear, (2) setting density neutron cross-constraints using the volumetric model of logging interpretation, and (3) establishing the objective function matrix equations using sliding window technology and solving the matrix equations using the constrained least square method to obtain high-resolution density and neutron porosity logs. The proposed method is evaluated using both synthetic and field logs obtained from compensated density and compensated neutron tools. The results demonstrate an effective improvement in neutron porosity and density log resolution to 15 cm, which is significantly enhanced compared to the typical vertical resolution of 2 ft. This study offers a new perspective for enhancing the resolution of logs and contributes to the exploration and development of thin oil and gas resources. And the proposed method could be used in future exploration and production projects to identify potential hydrocarbon layers that might have been overlooked by conventional logs.

Experimental Study on the Enhanced Oil Recovery Mechanism of an Ordinary Heavy Oil Field by Polymer Flooding.

It is widely known that in the water flooding development process of ordinary heavy oil, the fingering phenomenon is obvious, there are a lot of unswept areas, and absolutely, the recovery is really very low. In addition, for some shallow and thin ordinary heavy oil reservoirs limited by the geological conditions of the reservoir, the thermal recovery technology also has serious heat loss and high development cost. Therefore, there is an urgent need to transform the development and further improve the enhanced oil recovery (EOR). In this paper, the mechanism of EOR by polymer flooding was investigated for high-porosity and high-permeability terrestrial ordinary heavy oil reservoirs. Through laboratory experiments, we analyzed the characteristics of oil-water relative permeability curves, mobility control ability, and microscopic seepage characteristics during polymer flooding of ordinary heavy oil reservoirs. On this basis, the effect of the mobility ratio on seepage characteristics and the mechanism of EOR enhancement were clarified. The results show that the polymer can effectively improve the mobility control effect of the displacing fluid. As the polymer solution and ordinary heavy oil have the characteristics of high viscosity and low mobility, there is a minimum mobility ratio in the process of polymer flooding. Namely, the characteristics of dual low mobility exist in the process of polymer flooding for the ordinary heavy oil. It effectively enhances the profile control and plugging ability of the polymer, thus expanding the sweep volume of larger pores and improving the displacement efficiency of smaller pores. Based on the two factors mentioned above, it is found that the dual low mobility characteristics can improve the recovery of ordinary heavy oil by polymer flooding. Therefore, it is proposed that an enhanced profile control and plugging effect due to the dual low mobility characteristics is an important EOR mechanism for ordinary heavy oil development by polymer flooding.

Carbon Dioxide Huff and Puff as Environmentally Friendly Method for Enhanced Heavy Oil Recovery

Heavy oil and bitumen are making up approximately 70 percent of the remaining estimated hydrocarbon reserves. Many Enhanced Oil Recovery (EOR) methods such as chemical flooding, thermal recovery, gas injection, etc., were developed to make advances in the production of unconventional oil. Among all the variety of EOR methods, thermal recovery produces practically all of the heavy oil and bitumen among the various EOR methods. But at the same time, throughout its application, there are several disadvantages were revealed such as it is an expensive and not environmentally friendly process, heat loss in surface facilities and distribution lines, the efficiency is low after injection, increases in the extracted oil’s surface viscosity have caused polymerization reactions of free radicals created during the steam injection process, and the requirement for continuous steam injection is attempting to keep a hot oil-water interface at the front of the flow. For these reasons, the solvent-based non-thermal recovery method can be used to enhance heavy oil and bitumen recovery in unconventional reservoirs (thin or deep reservoirs) to prevent or reduce unwanted effects as described above. Toluene, carbon dioxide (CO2), ethane, propane, normal butane, and mixture solvents, among others, can be used as the injection solvent for the solvent-based non-thermal recovery method. That is why the researchers have concentrated on carbon dioxide as a solvent with Huff & Puff method to develop the production of heavy oil and bitumen to overcome all these negative issues because CO2 has several characteristics that make it an excellent option for this application. In this paper, the CO2 Huff and Puff method is reviewed. The CO2 Huff and Puff method’s viscosity reduction and oil swelling procedures have been the most significant factors in increasing heavy oil production. As a results, impacts of oil swelling at various temperatures and pressures as well as the viscosity reduction ratio with CO2 injection have been studied.

Different Development Scenarios to Increase the Production Rates for Fauqi Oil Field Southeastern Iraq

The Fauqi field is located about 50Km North-East Amara town in Missan providence in Iraq. Fauqi field has 1,640 MMbbl STOIIP, which lies partly in Iran. Oil is produced from both Mishrif and Asmari zones. Geologically, the Fauqi anticline straddles the Iraqi/Iranian border and is most probably segmented by several faults. There are several reasons leading to drilling horizontal wells rather than vertical wells. The most important parameter is increasing oil recovery, particularly from thin or tight reservoir permeability. The Fauqi oil field is regarded as a giant field with approximately more than 1 billion barrels of proven reserves, but it has recently experienced low production rate problems in many of its existing wells. This study will concentrate on analyzing the Asmari reservoir as the main production reservoir in this field for an oil gravity of 18 API. While, well (FQ-8) has been selected as a pilot well to verify different development scenarios that could be taken to increase the reservoir production rate. The results show that both drilling lateral sections and performing the stimulation process in some reservoir intervals yield positive results to increase good productivity with different percentages. The lateral sections occasionally gave higher productivity than the stimulation process by (2-3) times.

Application of Seismic Waveform Indicator Inversion in the Depth Domain: A Case Study of Pre-Salt Thin Carbonate Reservoir Prediction

Prestack depth-migrated seismic data, having more accurate imaging position and amplitude fidelity than prestack time-migrated seismic data, are supposed to produce a higher quality reservoir prediction result by using depth-domain inversion. Some researchers have developed different methods of depth-domain seismic inversion. However, it has not been widely used in the industry probably because of two reasons: (1) it is a complex process to conduct depth-domain seismic inversion due to the nonstationary depth-domain seismic wavelet; and (2) time-domain seismic inversion is considered capable of solving the problem with less cost, both in regard to time and the economy. In this paper, we try to use the seismic waveform indicator inversion method in the depth domain. First, a forward model was built to demonstrate that seismic waveforms both in the time domain and the depth domain are highly correlated with lithologic associations. Second, a quantitative evaluation method of seismic data for reservoir prediction was proposed, which can help geophysicists estimate time-domain and depth-domain inversion effects before inversion. Finally, the seismic waveform indicator inversion method was implemented for presalt thin carbonate reservoir prediction in the Central Block at the eastern margin of the Pre-Caspian Basin. The depth-domain inversion result shows a relatively true structure and higher resolution validated by wells.

Thin Reservoir Identification Based on Logging Interpretation by Using the Support Vector Machine Method

A reservoir with a thickness less than 0.5 m is generally considered to be a thin reservoir, in which it is difficult to directly identify oil-water layers with conventional logging data, and the identify result coincidence rate is low. Therefore, a support vector machine method (SVM) is introduced in the field of oil-water-dry layer identification. The basic approach is to map the nonlinear problem (input space) to a new high-dimensional feature space through the introduction of a kernel function, and then construct the optimal decision surface in the high-dimensional feature space and conduct sample classification. There are plenty of thin reservoirs in Wangguantun oilfield. Therefore, 63 samples are established by integrating general logging data and oil testing data from the study area, including 42 learning samples and 21 prediction samples, which are normalized. Then, the kernel function is selected, based on previous experience, and the fluid identification model of the thin reservoir is built. The model is used to identify 21 prediction samples; 18 are correct, and the prediction accuracy reaches 85.7%. The results show that the SVM method is feasible for fluid identification in thin reservoirs.

Innovation, Integration Enable Success in Guyana-Suriname Basin

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30946, “Innovation and Integration: Exploration History, ExxonMobil, and the Guyana-Suriname Basin,” by Audrey L. Varga, Matthew R. Chandler, and Worth B. Cotton, ExxonMobil, et al. The paper has not been peer reviewed. Copyright 2021 Offshore Technology Conference. Reproduced by permission. _ Exploration in the Guyana-Suriname Basin has been a decades-long endeavor, including technical challenges and a lengthy history of drilling with no offshore success before the 2015 Liza discovery. The collection of extensive seismic data has been leveraged to enable successful exploration of multiple play types across the basin. Further data collection has enabled the operator to adopt interpretation techniques that are applied across the entire basin to characterize and understand the subsurface better. Historical Context The first wells drilled in the Guyana-Suriname Basin were onshore; the Rose Hall well in Guyana in 1941 first found oil shows. Rumors of oil in the region, and hopes that the prolific hydrocarbon systems present in Venezuela extended into Guyana and Suriname, led geologists from the Standard Oil Company to conduct initial reconnaissance and seismic and geochemical studies. Despite hints—in retrospect—of a favorable basin configuration and hydrocarbon presence, the decision was made to discontinue exploration activities. Through the 1950s and early 1960s, the region saw relatively low levels of activity. In 1960, the first well was drilled offshore Guyana, and, in 1964, the first offshore well was drilled in Suriname; both were dry. In 1965, the Geological and Mining Service of Suriname found heavy oil near the present-day Calcutta Field. This led to the discovery of the Calcutta, Tambaredjo, and Weg naar Zee heavy-oil accumulations, but only a thin reservoir and heavy oil were encountered. In 1975, Esso participated in the North Coronie-1 well in Suriname. The well found oil and gas shows, confirming the presence of immature but rich source rock that was age-equivalent to the prolific La Luna source in Venezuela. A reconnaissance 2D seismic program followed, and, in 1978, Esso drilled the first deepwater well at Demerara A2-1. This well also was dry but did find high-quality, immature source rock and weak oil and gas shows. After another disappointing well at FG-1 in French Guyana in 1978, Esso ultimately relinquished its licenses but noted the presence of excellent-quality source rocks and reservoirs. The onshore Tambaredjo field, discovered in the 1960s, did not start production until 1982. All in all, before the Liza discovery, more than 300 wells were drilled in the basin, with more than 200 of these dry. Of these, all 60 offshore wells were dry. Why, then, did exploration continue? Data Evolution In the mid- to late-1990s, the Guyana deepwater acreage was completely open. The data available to the operator’s geoscientists consisted of one or two seismic lines, approximately four offshore wells, and a Suriname onshore oil sample. At that time, a major change in global coverage and quality of satellite free-air gravity data occurred with the declassification of US military data. An internal project by the operator merged the Sandwell and Smith free-air gravity grid, available in the public domain, with Getech onshore Bouguer gravity grids to create a global gravity compilation. The operator’s researchers recognized the applicability of these data as a key technology enabler to update plate tectonic models and genetic basin analysis.

Technology Focus: Seismic (February 2023)

The energy transition and disruption in the energy supply/demand chains fueled by the combined effect of the COVID-19 pandemic and the ongoing Russia/Ukraine war have given rise to more-innovative geoscience approaches geared toward carbon-footprint reduction with efficient and sufficient energy supply despite the increasing difficulty in finding new or remaining hydrocarbon accumulations. This year’s titles have a good mix of new frontier exploration, expanding heartlands, and brownfield-development themes. Improved seismic survey techniques, seismic image uplift, enhanced seismic attribute analysis, reservoir characterization, fracture diagnostics, mitigation of induced seismicity, and carbon capture and storage topics also are featured. As in previous years, more achievements in machine learning and automation of seismic processing and attribute analysis on both new or existing data to redefine geological plays, improve understanding of risks and uncertainties, enhance well placement and hydrocarbon recovery, reduce cost, and increase production are worthy of note. The selected top three papers for synopsis and those recommended for reading provide a taste of the themes mentioned above. I hope you find them as informative and transformational as I did. Recommended additional reading at OnePetro: www.onepetro.org. SPE 208174 Accurate Pore Fluid Indicator Prediction Using Seismic Fluid Bulk Modulus Inversion by Makky Sandra Jaya, Petronas, et al. SPE 211627 Seismic Motion Inversion Based on Geological Conditioning and Its Application in Thin Reservoir Prediction, Middle East by Chen Xin, China National Petroleum Corporation, et al. IPTC 22631 First Time-Lapse Walkaway Virtual Seismic Profile Monitoring of CO2 Water-Alternating-Gas Enhanced Oil Recovery Pilot: Challenges and Learnings From Onshore Carbonate Field UAE by Moza Mohamed, ADNOC, et al. SPE 207253 4D Seismic Detectability in a Brazilian Presalt Carbonate Field by Cyril Agut, TotalEnergies, et al. SPE 207719 Benefits of Ultradense 3D Spatial Sampling for Seismic Processing and Interpretation by Mohamed Mahgoub, ADNOC, et al.

Quantitative prediction of sand bodies in a sparsely explored zone of the Tarim basin: A case study of the aketao area

Thin sandstone reservoirs of the fan delta front sub-facies occur in the early Neogene (Miocene) series of the Aketao (Akto) structural belt within the Kunlun piedmont zone of the Tarim Basin. Oil and gas reservoirs in this area correspond to stratigraphic traps. However, owing to the low density of the 2D seismic survey grid deployed in the Aketao belt, inferior seismic data quality, and lack of well logging data, reservoir prediction in this area suffers from a multiplicity of problems and it is difficult to effectively identify sand bodies. Here, a new research approach is proposed involving the use of 3D seismic, well logging, and drilling data from a neighboring highly-explored 3D seismic survey area as a reference for the 2D seismic interpretation of the non-drilled Aketao survey area. Moreover, this approach is integrated with forward modeling and the inversion of post-stack seismic data to identify sand bodies. A comparison of the seismic reflection characteristics clarifies that these 3D and 2D seismic survey areas share similar sedimentary environments. Forward modeling confirms their similar reservoir characteristics, while the reservoir distribution in the 2D seismic survey area is effectively mapped via the inversion. The results show that for a 2D seismic survey area characterized by a low degree of hydrocarbon exploration and appraisal, and a lack of well logging data, the proposed approach can confirm the sedimentary characteristics that correspond to the seismic reflection characteristics, and can quantitatively map the reservoir thickness.

Seismic driven reservoir classification using advanced machine learning algorithms: A case study from the Lower Ranikot/Khadro sandstone gas reservoir, Kirthar Fold Belt, Lower Indus Basin, Pakistan

Reservoir characterization of thin sand bed reservoirs has been a challenge for petroleum explorers across the globe. In this study, we have studied the heterogeneous Paleocene sandstone gas reservoir of Lower Ranikot/Khadro, Kirthar Fold Belt, Lower Indus Basin, Pakistan. The studied reservoir is par below seismic resolution, with an average thickness that varies from 4 to 7 m at places and has provided a good amount of prosecution in some producing wells. The solution to the above challenges has been put forth where an integrated approach of seismic attributes, petrophysical properties, well logs, and facies data sets are combined with advanced machine learning algorithms to get better resolution for the studied thin-bedded sandstone resource. In addition, the thin heterogeneous sands of the Ranikot/Khadro Formation were characterized by predicting the elastic properties of the reservoir and classifying the facies distribution of hydrocarbon-bearing sands within the Zamzama Gas Field. Several machine learning (ML) algorithms were chosen and implemented on pre-stack seismic data from seven wells, two of which were produced from the Paleocene reservoir. The Gradient Boosting Regressor (GBR) produced promising results with the demarcation of thin sands with high accuracy levels. Based on a successful petro-elastic relationship, thin gas sands were highlighted. The low VCL of 30% and Sw of 45% cut-off reflect gas sands with P-impedances of 7500–9500 m/s × g/cc and a Vp/Vs ratio of 1.4–1.6 as decisive ML characteristics. Based on the applied workflow aided by ML, three reservoir units have been assigned for the Paleocene hydrocarbon-bearing sands, and gas sand probability distribution maps have been developed for each reservoir unit. Aligning the seismic inversion technique with machine learning advanced algorithms not only speeds up the prediction of elastic properties for facies classification but also increases accuracy to over 90% while drastically reducing uncertainty and associated costs in the process. Advanced machine learning algorithms have allowed us to cater to thin sand beds by eliminating the need for injecting frequencies. Instead, it recognizes features from the well data, trains itself, and predicts the corresponding features on the seismic trace, thus effectively allowing us to characterize the beds that are below seismic resolution in any given complex geology. The generated probability distribution maps of the three recognized thin-bedded sand units can be the basis for petroleum exploration and development in the study area. The discussed technique is successfully applied to complex folds and thrust belts, and hence can be implemented successfully in other heterogeneous thin-bed reservoirs for the successful classification of hydrocarbon-bearing sand distribution. It would optimize the results in a short period of time and with fewer economics.

Numerical Simulation and Sensitivity Analysis of Hydraulic Fracturing in Multilayered Thin Tight Sandstone Gas Reservoir

Hydraulic fracturing is a necessary measurement to realize the commercial exploitation of oil and gas, but its application in multilayered thin tight sandstone gas reservoirs is still not perfect, which usually have thin gas layers mixed with complex intervals, and shows a dramatic variation in geological and geomechanical properties in the vertical direction. When conventional hydraulic fracturing methods are applied to this kind of reservoir, it is hard to get proper fracture propagation, especially for fracture height control. Facing this situation, this paper proposes a numerical study of the hydraulic fracturing mechanism and analyzes its influencing factors in the multilayered thin tight sandstone gas reservoir. Relying on a real reservoir in the Ordos Basin in China, relevant geological and geomechanical parameters of major gas layers and interlayers are obtained. According to these parameters, the hydraulic fracturing simulation in the multilayered thin tight gas reservoir model is carried out, based on which, the sensitivity analysis of different geological and fracturing parameters which affect the fracture propagation is performed. Furthermore, a real low-production well after fracturing in this kind of reservoir is selected as an example, and based on the analysis, an optimized fracturing scheme is proposed to adapt to the characteristics of the reservoir. According to the comparison of fracturing and production simulations, the optimized fracturing scheme can prevent hydraulic fractures from breaking through thin interlayers, control the fracture height, and prevent fractures from communicating strata with a high water-bearing layer. At the same time, with the same amount of proppant and fracturing fluid, longer fracture length and better fracture conductivity are created, so that the productivity of the optimized fracture has been greatly improved.

An Effective Thin Reservoir Identification Method for Fine Oilfield Development

Thin reservoirs prediction method such as spectral inversion has drawn considerable attention in recent years. In order to avoid extracting wavelets within the whole field area purposeless and to make the filtered data has preferable fidelity as well as signal-to-noise ratio, an effective structural constrained thin reservoir description method which combines spectral inversion and wide-band Ricker wavelet filtering technology has been proposed in this paper. The method given here is more credible and is suitable for the prediction of middle-deep thin reservoirs. We take LD-A structure within Bohai Bay Basin as an example to show the implement of our method. Several sets of thin sand layers which are hardly to recognize originally have been finally identified. Also, with the application of this method, a high-production thin reservoir of LD-B structure has been identified accurately, which provides credible information for subsequent fine oil exploration and development.

Study on parameters limit of fracturing optimization process for thin and differential zone oil Wells

The potential target of water flooding measures has gradually changed to thin differential reservoir in three types of reservoirs. The fracturing proportion of thin differential reservoir in water flooding block oil well has reached more than 60%, and the existing fracturing design code can not fully meet the needs of thin differential reservoir fracturing. Through the effect evaluation of the technical parameters matching different types of thin differential reservoir, the field test is carried out to establish the limit of the optimal technological parameters for fracturing of thin differential reservoir oil well, which is of great significance for improving the fracturing effect and improving the technical level of fracturing in the future oilfield.

Study on the method of remaining oil exploration in thin differential reservoir

It is difficult to excavate the remaining oil in the thin differential reservoir and the oil-water reservoir. The remaining oil can be excavated by means of static and dynamic analysis method and microstructure method to continuously improve the recoverable benefit of the oilfield. Based on this, this paper studies the potential excavation methods of the remaining oil in the thin differential reservoir.