Mendez, Jose Nicanor (China University of Petroleum, Eastern) | Jin, Qiang (China University of Petroleum, Eastern) | Gonzalez, Maria (Emerson E&P Software) | Zhang, Xudong (China University of Petroleum, Eastern)
This study outlines a probabilistic model based on artificial neural networks applied to the very deep karsted carbonates of the Ordovician Yingshan Formation, which represent significanct reservoirs within a region of the Tahe oilfield, Tarim Basin, China. The complexity of rock type prediction and distribution of paleokarst fillings hosted in cavities, drives the need to apply new techniques for identifying more plays. This investigation focuses on a karsted interval located between the reflections of unconformities T74 and 76. The analysis was conducted using acoustic impedance (P-wave) and amplitude seismic attributes, processed from a 32-bit seismic dataset (Poststack). The methodology also includes conventional wireline logs from 28 wells adjusted to lithological descriptions of cores. Democratic Neural Networks Association (DNNA) is the proposed method for rock type prediction in karsted carbonates that simultaneity utilizes 3-D seismic data and well data. Based on sedimentological descriptions, the karst facies are classified in six types of lithofacies: mixed siliciclastic and carbonate (e.g., calcarenite and conglomerate), limestone, very fine-grained sandstone, mudstone, breccia, and unfilled. According to identified lithofacies, a clustering analysis is performed using the followings logs: Gamma Ray (GR), Deep Resistivity (RD), Neutron (CNL), Density (DEN), Sonic (AC), Potassium (K) and Thorium (TH) from Spectral Gamma Ray. Subsequently, the outputs are simplified for selecting the model most representative of lithofacies. Once adjusted data in commercial package, a training set and stabilization geometry involving seismic attributes constrained by interpreted seismic horizons are processed. The extracted seismic traces along borehole trajectory after processing demonstrate a good match with analyzed data, where the predicted maximum probability and class probability tracks vary with respect to lithofacies. Making time slices on the computed volume are observed to estimate effectively the probability of karst facies away from the wells. The outcome of this workflow is a probabilistic facies volume that provides appropiate description of clastic rocks that cover paleokarst fillings essentially in the run-off subzone. The model indicates that mudstone facies are the most prevailing and better proportions of siltstones or sandstones facies are distributed to southeast of area. This study concludes that in determining clastic lithofacies distribution, employing several neural networks running in parallel that simultaneously learn from the same dataset through different strategies is an effective tool. To date, there has not been any study on rock type prediction using DNNA in karsted carbonates. The results represent a significant contribution to the collection of geosciences on characterizing this type of reservoir.
This seminar will teach participants how to identify, evaluate, and quantify risk and uncertainty in everyday oil and gas economic situations. It reviews the development of pragmatic tools, methods, and understandings for professionals that are applicable to companies of all sizes. The seminar also briefly reviews statistics, the relationship between risk and return, and hedging and future markets. Strategic thinking and planning are key elements in an organisation’s journey to maximise value to shareholders, customers, and employees. Through this workshop, attendees will go through the different processes involved in strategic planning including the elements of organisational SWOT, business scenario and options development, elaboration of strategic options and communication to stakeholders.
Decisions in E&P ventures are affected by Bias, Blindness, and Illusions (BBI) which permeate our analyses, interpretations and decisions. This one-day course examines the influence of these cognitive pitfalls and presents techniques that can be used to mitigate their impact. Bias refers to errors in thinking whereby interpretations and judgments are drawn in an illogical fashion. Blindness is the condition where we fail to see an unexpected event in plain sight. Illusions refer to misleading beliefs based on a false impression of reality.
Xu, Feng (RIPED / CNODC) | Li, Xianbing (RIPED) | Gong, Yiwen (The Ohio State University) | Lei, Cheng (RIPED) | Li, Xiangling (RIPED) | Yu, Wei (The University of Texas at Austin / Texas A&M University) | Miao, Jijun (The University of Texas at Austin / SimTech LLC) | Ding, Yutao (CNODC)
Natural fractures are commonly observed in the unconventional reservoir. Production history indicates that natural fractures have been playing an important role in the oil and gas development progress by improving the permeability of the reservoir and increasing the well productivity. In addition, inappropriate development strategies result in the unreasonable single well oil rate, early water breakthrough, severe damages to the unconventional reservoir and overwhelming economic losses when the fracture properties and distributions are not well understood before the development. Hence, it is of great importance to propose a powerful and efficient workflow to describe the fracture distribution clearly, including building a 3D fracture model, performing history matching and forecasting productions of the unconventional reservoir. In this study, we present a powerful and practical workflow through using Fracflow software and EDFM (Embedded Discrete Fracture Model) to build the 3D DFN (Discrete Fracture Network) model. The main methodology used to perform the fracture modelling allows rigorously handling of both hydraulic fractures and natural fractures that can be identified in an unconventional reservoir. This modelling allows computing the real geometrical fracture attributes (mainly orientation and density) and the spatial distribution of fractures. Fracture conductivity values will be calibrated through a comparison of the Kh(permeability thickness) from the well test to the Kh model computed from the upscaling of the fracture model. The mentioned model above will be built by means of a stochastic simulation constrained by the results of the static and dynamic fracture characterization. In the reservoir simulation phase, EDFM processor combining commercial reservoir simulators is fully integrated to perform history matching and production performance forecast of the unconventional reservoir. With a new set of formulations used in EDFM, the non-neighboring connections (NNCs) in the EDFM are converted into regular connections in traditional reservoir simulators, and the NNCs factors are linked with gridblock permeabilities. EDFM provides three kinds of NNC pairs, transmissibility factors, and the connections between fractures and wells. With the aid of the EDFM processor, we can obtain the number of additional grids, the properties of fracture grids, and the NNCs as the simulation input. From the proposed workflow, complex dynamic behaviors of natural fractures can be captured. This will further ensure the accuracy of DFMs and the efficiency offered by structured gridding. The practical workflow for the unconventional reservoir from modelling to simulation highlights the model constrained by the results of the static and dynamic fracture characterization, and the high efficiency to model discrete fractures through the revolutionary EDFM processor. Through this workflow, we can perform history matching effectively and simulate complex fractures including hydraulic fractures and naturally fractures. It potentially can be integrated into existing workflow for unconventional reservoirs for sensitivity analysis and production forecasting.
The objectives of the present study are to evaluate a zwitterionic surfactant for applicability in EOR. The surfactant was tested in terms of its salt tolerance, thermal stability, interfacial reduction capability, wettability alteration and resistance to adsorption. The effect of salinity and alkalinity was also tested on the above stated physico-chemical properties of the surfactant.
The salt tolerance of the surfactant was tested by testing for precipitation of surfactant solution with increasing salinity at 30 °C and 80 °C. The thermal stability of the surfactant was tested by TGA testing. The interfacial tension of the crude oil and surfactant solution with varying surfactant concentration, salinity and alkalinity was tested by spinning drop technique. The wettability alteration by surfactant solution was tested by measuring contact angle on an oil wet sample. The adsorption study was done by measuring the concentration of surfactant after its solution was exposed to adsorption on crushed rock sample.
The surfactant had salt tolerance of 20% salinity. The surfactant was found stable to 130 °C as per TGA curve. The interfacial tension (IFT) was reduced to ultralow value by surfactant solution for concentration at and above its critical micelle concentration. The presence of salt had minimal effect on the IFT reduction capability of the surfactant solution. Presence of alkali had synergetic effect on IFT reduction. The wettability of the oil wet sample was altered to preferentially water wet by surfactant. The loss of surfactant due to adsorption was found to be within recommenced range for applicability in EOR. These excellent physico-chemical properties of the zwitterionic surfactant suggest that it can be used in the mature oil fields for recovery of trapped oil.
With the promotion of oil and gas development around the world, the exploration scope has been gradually extended to complicated geological reservoirs, such as deep or ultra-deep, unconventional, deep-water reservoirs, and lost circulation and wellbore instability have been becoming the most serious problems, which puts forward higher requirements on the drilling fluid technology. In order to solve these technical problems, the wellbore strengthening mechanism, tight fracture plugging methods and simulation experimental method for drilling fluids were studied respectively in this paper. Firstly, the wellbore strengthening mechanism of the stress cage method that improves wellbore pressure containment was firstly investigated based on ABAQUS finite element modeling analysis. It was found that wellbore pressure containment could be improved by enhancing plugging performance of drilling fluids to plug and prop natural or induced fractures to eliminate fracture propagation and increase hoop stress. The key performance of loss prevention materials has been proved to play a prominent role to achieve wellbore strengthening effect and strengthen the wellbore. According to the basic principle of "force-chain" in granular matter mechanics, the key fine technical indices were proposed to evaluate the particle strength, particle resiliency and surface friction of loss prevention materials. Meanwhile, the corresponding physical model of tight fracture plugging zones was established to reveal the tight fracture plugging mechanism at micro scale and the optimization method of tight plugging drilling fluids was also put forward, and it was concluded that using reasonable particle type, particle size distribution and concentration control, rigid particles, resilient particles and fibers were synergized to plug fractures, so as to form tight pressure containment plugging zones with a strong force chain network and greatly improve the wellbore pressure containment. The novel experimental apparatus for evaluation and dynamic simulation on the plugging characteristics of drilling fluids was developed, which could simulate the loss and plugging process of fractures with different openings under different formation pressures and temperatures.
Cao, Chuan (CNPC CPET) | Luo, HuaiDong (CNPC Interational Chad Co., Ltd.) | Zhang, QuanLi (CNPC CPET) | Xu, BingGui (CNPC CPET) | Zhang, YanPing (CNPC CPET) | Jia, Tao (CNPC CPET) | Yu, YongLiang (CNPC CPET) | Yin, HongWei (CNPC CPET) | Wang, JianLi (CNPC CPET)
Water encroachment is considered main reason for production decline on Carbonate reservoirs which are trapped in deep, HTHP formations in Tarim Basin, after early development stage. Sidetracking re-entry horizontal wells is a cost-effective way to recover oil production from existing mature fields. However, the unstable formation and variation in formation pressures during re-entering posed extremely challenging problems which drive well costs up and even jeopardize reaching total depth. The operator launched a work over campaign to re-enter old wells, sidetracking through 7"casing to the target Ordovician reservoir. The unstable Carboniferous Formation lying above and different pressure regimes (high pressure on Carboniferous formation; low pressure on Ordovician reservoir) significantly reduce the probability of operation success. A Solid expandable solution was selected to case off the high pressure and unstable zone. This paper reviews three case histories of solid expandable liner installations on horizontal sidetracking wells. The maximum expandable liner installation depth reached almost 20,000ft, at deviated 65.8 deg. well section with 1,728ft expandable liner expanded. The expandable liner isolated the high pressure Carboniferous Formation, this enabled the operator to drill the reservoir with lower mud weight while minimizing the risk of differential sticking, and conserved valuable hole size to allow the logging program to be conducted as desired and produce through larger diameter production tubular. Solid expandable solution has demonstrated as the best option to meet the objectives for re-entry deep horizontal wells.
Zhao, Le (China University of Petroleum, Beijing) | Zhang, Hong (China University of Petroleum, Beijing) | Tu, Yulin (SINOPEC Research Institute of Petroleum Engineering) | Duan, Qingquan (China University of Petroleum, Beijing)
Le Zhao and Hong Zhang, China University of Petroleum, Beijing; Yulin Tu, SINOPEC Research Institute of Petroleum Engineering; and Qingquan Duan, China University of Petroleum, Beijing Summary The application of an expandable profile liner (EPL) for leakage plugging in a directional section of deep and ultradeep wells is still at the exploratory stage. EPL that can meet the plugging and strength requirements. The internal-pressure-limit test, crushing test, overall string-sealing experiment, and mechanical shaping experiment are performed, and the optimal welding procedure is developed. After the hydraulic-expansion and mechanical shaping process, the EPL is found to meet the design size and construction requirements. Simulating the trip-in and the expansion process at different reaming-wellbore diameters, with a comprehensive consideration of the expansion requirements and ensuring that the adhesion force effectively seals the EPL against the wellbore, it is better to set the diameter of the reaming wellbore to 6.889 in. Introduction Severe drilling-fluid leakage is an important unfavorable factor that hinders safe, fast, and economical drilling in petroleum-drilling engineering (Abdrakhmanov et al. 1995; Metcalfe 2002; Takhautdinov et al. 2002, 2003; Abdrakhmanov et al. 2006). Unlike vertical wells, the wellbore stability of a directional well varies from the changes of the deviation angle and the azimuth, and therefore research on wellbore stability of the directional well will encounter enormous challenges. Plugging construction is much more difficult to apply to the directional section of deep and ultradeep wells to reconcile the demands of reservoir protection under complex geological conditions, raising higher requirements for effective leakage plugging.
This article reports on a novel simple method for transforming the high-salinity-incompatible petroleum sulfonates into a persistently stable oil-swollen micelles, referred to here as nanosurfactant. We present and discuss the effect of three different nanosurfactant formulations on the interfacial tension (IFT) between high-salinity water and crude oil, their phase behavior, and the effect of their dilution on IFT to assess their ability to reduce mobilize oil after injection into high-salinity and temperature reservoirs.
The three nanosurfactant formulations were prepared in high-salinity water following a direct-mixing procedure in which solutions in fresh water of 5 wt% petroleum sulfonate in mineral oil and three 4 wt% zwitterionic co-surfactants were mixed with high-salinity water at room temperature to give a combined concentration of all active ingredients of 0.2 wt%. The IFT between crude oil and different nanosurfactant formulations was measured using a spinning drop interfacial tensiometer at 90°C. IFT was measured every 5 minutes while the oil drop was spinning at ~4000 rpm. The phase behavior was investigated by monitoring the turbidity and UV absorbance changes in a system of crude oil atop of the nanosurfactant formulation over time at 100°C without any mechanical mixing.
The particle size of the three nanosurfactant formulations is in the range of 40 to 80 nm, depending on the co-surfactant used. All formulations were persistently stable, colloidally, and chemically under high-salinity (~56,000 ppm) and temperature (100°C) for more than four months. All formulations showed substantial reduction in IFT with crude oil compared to high-salinity water alone. Dilution with high-salinity water up to five times further reduced the IFT, suggesting improved performance after injection into the reservoir. This behavior was consistent with the observed gradual decrease in surface tension of the nanosurfactant formulation as its concentration decreases toward the CMC value. Phase behavior experiments showed enhanced formation of homogeneous micelles at 100°C without the aid of any mixing. Our results demonstrate the ability of nanosurfactants to solubilize oil under typical carbonate reservoir conditions. Their colloidal nature allows them to migrate deeper in the reservoir compared to conventional surfactants due to size exclusion and chromatographic effects.
Nanosurfactants are novel oil-swollen micelles of the inexpensive and abundant petroleum sulfonate salts that are efficient in reducing IFT under typical carbonate reservoir conditions. The formulation method can be extended to other surfactants and chemical treatments that are incompatible with high-salinity water at high temperatures. Their nanoparticle character and colloidal behavior suggest their ability to migrate and penetrate deep in the reservoir. Nanosurfactants can therefore help overcome some of the most critical drawbacks in conventional chemical EOR technologies.
Mou, Jianye (Shaodan Tao China University of Petroleum-Beijing) | Hui, Xuezhi (Seventh Oil Production Plant of Changqing Oilfield of CNPC) | Wang, Lei (China University of Petroleum-Beijing, State Key Laboratory of Petroleum Resources and Prospecting) | Zhang, Shicheng (China University of Petroleum-Beijing, State Key Laboratory of Petroleum Resources and Prospecting) | Ma, Xinfang (China University of Petroleum-Beijing, State Key Laboratory of Petroleum Resources and Prospecting)
Multi-stage acid fracturing of horizontal wells is a necessary and effective technology in developing tight carbonates. In open-hole horizontal wells in high-temperature, naturally fractured deep formations, segmentation with tools is of high risk and costly, even ineffective sometimes, so segmentation with diversion agents is alternative to tools and was pilot tested in some fields. The stimulation results were satisfactory, and pressure response feature was in accord with expectation. However, this technique has not been studied experimentally or numerically extensively yet.
In this study, we investigated tool-free multi-stage fracturing experimentally in open-hole horizontal wells with diversion agents. Firstly, we designed a multi-stage tri-axial fracturing system and experimental procedures to satisfy the requirements of diverted fracturing in horizontal wells. Next we conducted a series of experiments to investigate feasibility of multi-stage fracturing with diversion agents using natural carbonate outcrop cubic blocks with the size of 300*300*300mm. CT scanning was used to obtained detailed fracture geometry after experiment. Finally we analyzed the effect of diversion agent type, concentration, and injection procedure on diversion.
The experimental results show that multi-stage fractures perpendicular to the open-hole horizontal wells was created, which verifies the validity of the tool-free multi-stage fracturing of open-hole horizontal wells with diversion agents. Proper agents or combinations can effectively plug the fracture generated previously and generate pressure high enough to initiate another fracture. The breaking pressure or propagation pressure of second fracture was monitored higher than the one of the first fracture. Under experiment conditions, 1-3mm fiber or combination of fiber and particle (0.8-1.2mm) can effectively plug fractures and realize segmentation. Concentration of diversion agents tested ranges 0.4-1.6wt%. Injection procedure for two-stage fracturing was fracturing fluid + diversion fluid + fracturing fluid. The amount of diverter and open-hole length are the vital factor for the success of experiments.
This study newly designed a multi-stage tri-axial fracturing system and experimental procedures for the diverted fracturing. The finding verified the validity of the tool-free multi-stage fracturing of open-hole horizontal wells with diversion agents and provides fundamental for field treatment design.