Search

The prevention and control of natural gas hydrate (hereinafter, “hydrate” for short) blockage during deepwater gas well production tests is very important in ensuring the test safety. In this paper, the distribution of wellbore temperature and pressure field under different test conditions was analyzed, and the changes of hydrate deposition and blockage degree in the pipe string in the whole process of test under different test systems were evaluated using the hydrate generation–deposition–decomposition calculation method. On this basis, a deepwater gas well production test method based on hydrate prevention and control was proposed. And the following research results were obtained. First, in the process of deepwater gas well tests, the vapor–liquid phase of annular-mist flow pattern with the greatest risk of hydrate blockage is often formed in the wellbore. Therefore, it is more reasonable to take measures to prevent hydrate blockage in the process of tests than to prevent the formation of hydrate. Second, when the conventional four-point test method is used, it is required to set low gas production measurement points with lower flowing temperature. In the wellbore with high temperature and low temperature, however, hydrate tends to form and deposit easily, and a long period of test will increase the risk of test string blockage. Third, the mixed-sequence test system suitable for deepwater gas well tests can change wellbore temperature by adjusting the sequence of measuring points without changing the production rate and duration, so as to decompose hydrate sediment layers and reduce the maximum blockage degree of test string in the process of tests. Fourth, a three-point or two-point test method is recommended for deepwater gas wells without sand production, stress sensitivity, retrograde condensation and water production. Superior to the conventional four-point test method, three-point and two-point test methods can effectively reduce the risk of hydrate deposition and blockage in the test string, and it can shorten the testing time and reduce the test cost on the premise of ensuring the accuracy of the productivity equation. In conclusion, the research results are of help to the field test construction of deepwater gas wells. Keywords: Deepwater gas well, Production test, Natural gas hydrate, Prevention and control method, Mixed-sequence test, Pipe blockage degree, Flow assurance

Although considerable advances have been achieved in recent years, there is still a long way to go for hydrate prediction and prevention during deepwater gas well testing. Well hydrate blockage is a time-dependent continuous process, and evaluation of wellbore blockage is critical for hydrates prevention and control. In this work, the authors presented a novel wellbore blocking degree evaluation model for deepwater gas-well testing. Firstly, a new evaluation model consisting of mass, momentum and energy balance equations considering hydrates formation was proposed. Secondly, considering hydrate phase equilibrium, the finite difference method and iterative technique were used to obtain the model results. Finally, the model was applied to the deepwater gas wells in the South Sea of China for verification and was subjected to sensitivity analysis. The predicted results were in good agreement with field test results. According to the sensitivity analysis, gas output, methanol concentrations, water production rate have different degrees of influence on hydrate blocking. The length of the hydrate stability region (HSR), the position of largest plugging point, and the distribution of wellbore inner diameter are the key to hydrate prevention and control. Meantime, combining the model evaluation results, optimizing the testing process can achieve the purpose of preventing-controlling gas hydrates economically and effectively.

Wellbore cleanup is an important part of deepwater gas wells completion testing and also a critical stage for hydrate formation. For evaluating hydrate risk and proposing specific hydrate preventio...

Currently, the analysis of Sustained-Casing-Pressure (SCP) tests is limited because some researchers' simulations did not take the effect of gas migration in mud into account and their models were based on Newtonian fluids. This is not consistent with the actual field situations that gas migrates in non-Newtonian fluids. In addition, the yield stress effect was also not taken into account. To ensure the operators a realistic and accurate diagnostic testing for the SCP problem, the improvements of mathematical models in SCP problem are of great significance. In this study, by considering the correlation between gas velocity and drag coefficient, a new formula of gas migration velocity in stagnant non-Newtonian fluids was established. Moreover, the yield stress effect was incorporated in the new model. The validations of field data demonstrate that the new model has the credence to the field work. Furthermore, in this study, the effect of gas migration on SCP problem was paid attention seriously based on new model. To demonstrate the importance of gas migration effect, the analysis of variance (ANOVA) were employed to find out the values of mud properties (flow behavior index, yield stress, length of mud, consistency index) that can most significantly influence the wellhead pressure. Then these most influential parameters were utilized in both the new model (with gas migration effect) and the previous model (without gas migration effect) to conduct the comparison. The comparison result indicate that the value of mud compressibility and the value of cement permeability got by the new model are higher than those by the previous model, and the value of initial gas chamber size got by the new model is lower than that by the previous model. These stress explicitly the necessity and significance of considering gas migration effect and considering the non-Newtonian effect on SCP problem, which should not be neglected. The developed models in this research offer significant insights into the SCP problem, which turns out to be powerful in the application of analyzing the SCP problem. This work can lay the theoretical basis to assist operators in diagnostic testing of wells with SCP problem accurately.

Forecasting production in shale gas reservoirs accurately has been of growing interest in the industry. Horizontal wells with multiple fractures are commonly utilized to develop shale reservoirs, which indicates that the dominant flow regime observed will be linear flow for several years. Until now, it has been widely recognized that the rate-transient data analysis is the most efficient approach to estimate rate, where it appears as a straight line on the plot of normalized pressure vs. square root of time in linear flow. However, the traditional square-root-of-time plot may result in overestimation of reservoir properties and will not allow us to forecast production with confidence in shale gas reservoirs. In this paper, a new analytical methodology is put forward to analyze the rate-transient data from fractured wells in shale gas reservoirs producing at a constant flowing-pressure, which incorporates both slip flow/Knudsen diffusion of bulk gas and surface diffusion of adsorbed gas directly into the model. These flow mechanisms cannot be well described by traditional models. Depending on flow discrepancies from conventional reservoirs, the modified pseudo-pressure and pseudo-time equations to account for these critical transport mechanisms are constructed. In addition, a new procedure for rate-transient data analysis applying the proposed model is presented in details, which is reliable and easy to utilize. The novel approach is validated against numerically simulated cases and field observations. Comparisons between the new approach and traditional method are conducted by a number of test cases. The results demonstrate that the newly developed model dramatically eliminates the inaccuracy of production forecast and provides a more reliable estimated ultimate recovery (EUR). This work should provide an efficient guidance to assist analysts in evaluating hydrocarbon production accurately in shale gas reservoirs.

Currently, analysis of the Sustained Casing Pressure (SCP) tests or other gas migration problems in the wellbore is limited because the mathematical models employed by most researchers are based on Newtonian fluids, which is not consistent with the actual situation that the mud is non-Newtonian fluid in the Annulus. To ensure the operators a realistic and accurate diagnostic test, the improvement of current gas-migration models is of great significance. In this study, a new model of gas migration in non-Newtonian power law fluids was established. This new model incorporates the correlation between swarm bubbles velocity and drag coefficient, and combines the petroleum correlations and the drift-flux model to determine the friction pressure gradient. In addition, the gas slip velocity in non-Newtonian power law fluids is rigorously determined by the proposed calculation procedure using an iteration approach. Furthermore, improvements of the new model are analyzed and discussed in details. During the process of the hypothetical parameters determination (Initial gas chamber length, initial gas concentration in liquid column, mud compressibility, cement permeability, and formation pressure) for simulation, the same values of parameters with previous study are tried to be utilized to minimize the difference. Results in this work indicate that the big discrepancy of matched parameters between the new model and previous model are generated from the mud compressibility, which is attributed to the gas holdup. The higher gas holdup obtained from the new model manifest the validity of proposed model, which is caused by the higher viscosity of non-Newtonian power law fluids. The new model is suitable for relatively low gas holdup ( α 0.25 ), where the bubble flow prevails in annuli. This work provides significant and necessary improvements for gas migration. For the first time, the problem of multi-phase flow in the SCP problem is accomplished by introducing calculation approach of non-Newtonian fluids. This calculation approach can be extended to calculations of other multiphase flow problems in the wellbore.

The exploration and development of shale gas reservoirs has been of growing interest in the industry in recent years. It has been widely acknowledged that, during different thermal evolutio...

When modeling of steam flow in wellbores, the effect of friction work on temperature/steam quality of both fluid in wellbores and reservoir should be considered. A model that can describe the energy re-distribution in the system should be built. In this paper, new energy balance equations for steam flow in inner tubing (IT) and annuli are developed with consideration of the effect of frction work on the energy re-distribution process in the system. The heat energy caused by shear stress has an obvious influence on the increase of steam quality or superheated steam temperature, especially under high injection speed condition. Firstly, a model for steam flow is developed in wellbores based on the energy and momentum balance equations. The energy balance equation controlls the predicted values of steam quality or superheated steam temperature, and the momentum balance equation controlls mainly the steam pressure. Secondly, coupled with the seepage model in oil layer, a comprehensive mathematical model is establiehed for single, two-phase flow of steam in horizontal wells with toe-point injection technique. Results show that: (a) when the effect of friction work was neglected, the predicted steam quality or superheated steam temperature were obviously smaller than field data. (b) While seam quality decreases with distance when wet steam flows in wellbores, superheated steam temperature in annuli has an increase at the heel-point in annuli. This is because the fluid with lower temperature in annuli absorbs heat from steam with higher temperature in IT. (c). In order to obtain a satisfactory oil recovery ratio, field engineers are suggested to increase the injection pressure to a reasonable level based on the rock fracture pressure experiment.

Forecasting production in shale reservoirs accurately has been of growing interest in the industry in recent years. Until now, various techniques to interpolate production have been developed. Among them, decline curve analysis models have been widely recognized as the most efficient and easiest approach to apply. Unfortunately, each decline curve model has its own limitations and will not allow us to forecast production in shale gas reservoirs with confidence. In this paper, based on the similar characteristics between shale gas production and self-diffusion of dense gas/surface diffusion of adsorbed gas, a new early-late decline model with two fitting parameters were developed by employing general equations of this two behaviors respectively. These flow characteristics cannot be addressed by traditional decline curve models. In addition, a detailed forecasting procedure applying this novel decline model in the whole life of shale gas production was proposed, which is reliable and easy to utilize. Furthermore, this proposed model was validated by numerically simulated cases and field observations. Good matches between forecast rates calculated using this novel method and numerically simulated rates/field rates were obtained. The comparison between this proposed method and traditional methods were further conducted, which indicated that this novel approach leads to more confident forecasts than commonly utilized approaches. This work will provide a theoretical basis for analysts in evaluating hydrocarbon production rapidly and efficiently in shale gas reservoirs.

Estimating stimulated reservoir volume (SRV) in shale gas reservoirs with high accuracy has been of more concern to oil and gas industries. However, current SRV prediction methods are of limited use for characterizing critical flow mechanisms. To make more accurate prediction of SRV in shale gas reservoirs, multiple mechanisms cannot be ignored. In this paper, we develop a novel analytical model to accurately estimate the volume of SRV in shale gas reserviors by incorporating both Knudsen diffusion of bulk gas and surface diffusion of adsorbed gas directly into the model. Depending on flow discrepancies from conventional reservoirs, the modified pseudo-pressure equation to account for these critical transport mechanisms are further constructed. Predicted values of SRV by using this new model are in fair agreement with values from the CMG simulation. Compared with related research, it is the first time that both Knudsen diffusion of bulk gas and surface diffusion of adsorbed gas are taken into consdertion to analyze and estimate the volume of SRV in shale gas reservoirs. A clear workflow for implementation of this method is presented. Compared with the common numerical reservoir simulators, this approach is easier to setup and less data-intensive.

In recent years, improving the accuracy of production forecast in unconventional reservoirs has been of growing interest to oil and gas industries. Decline curve analysis (DCA) models have been recognized as the most efficient and easiest approaches to estimate gas rate. However, fluid flow regime and well rate decline curves are highly affected by the geological properties of formations. Therefore, the selection of DCA models based on completion designs and geological properties of formations is important for production rate prediction. Traditional DCA methods, particularly Arps' decline model, was originally developed for predicting boundary dominated hydrocarbon well rate decline, which differs from the dominant long-duration transient flow regime in shale reservoirs. The Stretched Exponential model, the Duong model, the Arps model with a minimum terminal decline rate and the scaling method by Patzek were developed to match and forecast wells with transient flow followed by boundary dominated flow (BDF). In this paper, firstly we developed a new model to estimate production in shale gas reserviors by considering both Knudsen diffusion of bulk gas and surface diffusion of adsorbed gas based on the traditional equation of rate versus square-root-of-time. This proposed model can provide better fits to data in transient linear flow regimes. In addition, a systematic analysis of numerical simulation cases in CMG were performed to compare with the traditional model. The results demonstrated that, in most cases, our model which is demonstrated in this paper, provide more accurate estimation of reserves for numerically simulated cases compared with the traditional decline methods. Therefore, the work offers critical insights into evaluating production in shale gas reserviors in a more efficient way.

Well control in gas reservoirs with high pressure has been of growing interest in the industry in recent years. It has been widely recognized that challenges of well leakage and ground equipment damage will be faced in well-control work. Unfortunately, current well-control procedures do not allow us to kill with confidence and serious accidents occur sometimes. To ensure a safe and successful kill operation, before drilling, utilizing multiple well-control approaches to simulate the kill operation and after blowout, determining reasonable kill parameters to accomplish the kill should be of great significance. In this study, the Qing Xi 1 well was taken as an example to perform the first and second dynamic kill simulations by the Drillbench software to evaluate the effectivity of different kill operations with various choke pressures. The feasibility analysis of the dynamic kill was conducted by switching the displacement of mud pump, ascertaining the values of laminar coefficient A and turbulence coefficient B skillfully, and employing the known parameters of pump pressure, gas influx from formation and fracture pressure. The simulation results demonstrated that, under the limited geological conditions and the site environment of the Qing Xi 1 well, the second killing scenario will succeed when 40MPa choke pressure was employed in the dynamic kill operation, which differs dramatically from the realistic failure of the second killing scenario in the site of the Qing Xi 1 well. Accordingly, the maximum of choke pressure should be suggested in the future site operation of killing scenario when the equipment conditions are allowable. Although higher choke pressure may make the well leak-off, it will generate smaller losses compared with serious blowout out of control. In addition, a reliable pre-prevention and post-processing well-control procedure for implementation of our method was proposed, which is the most efficient and easy to apply. Our work in this paper should provide a basis for guiding field operations involving kill efficiency and should assist engineers in ensuring personal and property safety.

Accurate pressure build-up test interpretation technologies for both conventional and unconventional reservoir development have been highly applied in oil and gas industries in recent years. However, for the late development stage of wells, current well test interpretation methods lose their accuracy to characterize fluid flow behavior and fracture properties etc. due to the complex underground situation and interference among adjacent wells. Novel pressure build-up test interpretation methods should be developed with the incorporation of these effects. We developed a novel model to interpret formation pressure and formation physical properties, during the process of pressure build-up test, by incorporating stress interference among adjacent wells and two-phase flow of oil/water directly into the model. Trial approach was utilized to iteratively correct average formation pressure and permeability of oil and water phase, depending on the complexity of well interference systems. A simulation was developed based on this semi-analytical model which is capable of interpreting formation pressure and formation physical properties during the process of pressure build-up with much higher accuracy compared with traditional methods. A numerical simulation in Eclipse was utilized to validate our model. Our interpretation results, including formation pressure, skin factor and permeability etc., are in fair agreement with the numerical simulation. We applied our model to conduct pressure build-up interpretation tests for testing wells in the Huabei Oilfield, and the precision of our model can reach up to 35.15% which has greater accuracy compared with traditional methods. This novel model exhibits high efficiency and accuracy for pressure build-up test interpretation for the case with interference among adjacent wells and oil and water two-phase flow. This work provides an effective framework for pressure build-up test interpretation in fractured reservoir development.

Synergism of hydrogen and composition of oils in noncatalytic upgrading of different petroleum residues were analyzed. Residues were upgraded under temperature of 400°C and initial pressure of 4 MPa for 20 min in the presence of hydrogen or nitrogen, respectively. In addition, anthracene was used as chemical probe to quantify the hydrogen-donating ability of the three feedstocks and the contribution of hydrogen gas. Results show that hydrogen has better synergism with the residue that contains more naphthenic aromatic structure, heteroatom, and metals. Moreover, hydrogen activation possibilities limit the effect of the hydrogen solubility of the oils on upgrading.

The recombination reaction between H2S and 1-hexene with H2 was detected. The catalyst used was NiMoS/Al2O3 (presulfided); the volume fraction of 1-hexene in the model feedstock was 5, 10, 15, 20, 25 (vol%), respectively; H2S concentration was 4,000 μg/g; initial H2 pressure was 2 MPa; and reaction time and reaction temperature were 2 hr and 473 K, respectively. It was revealed that, in the reaction system, as the volume fraction of 1-hexene increased, the concentration of total sulfur in the reaction system first increased significantly and then was steady; the hexanethiol content in the product first increased and then decreased. The hydrogenation of 1-hexene was promoted as the 1-hexene volume fraction increased. As the 1-hexene volume fraction increased, the mass fraction of hexane in the product increased; the mass fraction of 2-hexene in the product first increased and then decreased; the mass fraction of 3-hexene in the reaction system first increased significantly and then was steady.

The recombination reaction between H2S and 1-hexene with H2 was detected. The catalyst used was NiMoS/γ-Al2O3; the volume proportion of 1-hexene was 10 (vol%); H2S content was 500, 1,000, 2,000, 3,000, 4,000 μg/g, respectively; initial H2 pressure was 2.0 MPa; and reaction time and temperature were 2.0 hr and 473 K, respectively. It was revealed that, in the reaction system, as the content of H2S increased, the content of hexanethiol and total sulfide in the reaction system increased significantly. The inhibition of hydrogenation by H2S and the isomerization of 1-hexene toward 2-hexene and 3-hexene were researched. As the content of H2S increased, the mass fraction of hexane, 2-hexene, and 3-hexene decreased and the remaining 1-hexene increased in the reaction system; therefore, H2S inhibits the formation of hexane, 2-hexene, and 3-hexene.

Five different (Bi, Ni, Mo, Pt, H)/ZSM-5 catalysts were tested for hydrodealkylation (HDA), isomerisation, dehydrogenated, cyclistion, and poly-alkyl-aromatics activities. Experiments were performed in a fixed-bed microreactor between 300°C and 420°C, at a total pressure of 0.8 MPa and a liquid hourly space velocity of 1.0 h−1. Pt (Mo)/ZSM-5 catalysts enhanced activity in terms of better balance between metal nanoparticles formed and acid sites. Pt-loading catalysts were the best overall catalysts, producing high C9 alkyl-aromatics (isopropylbenzene) conversion (95.9%), high HDA selectivity (92.2%), and relatively low reaction temperature. Mo-loading catalysts, despite producing the high conversion, required the higher reaction temperatures.

Now problems of shale gas development reveal that organic matter diagenesis, hydrocarbon generation process of kerogen, characteristics of methane and water occurrence in organic pores are all with complexities, which will seriously affect the desorption and production laws of shale gas. But existing research is shortage in these aspects, such as: the product characteristics of each thermal evolution stage of shale organic matter, the mechanism of hydrocarbon generation, organic pores type as well as formation mechanism. Besides, the occurrence modes of methane and water in organic pores are controversial, so further research is necessary. Literature reviews on process of kerogen formation, generation mechanism of oil/gas in shale kerogen, evolution characteristics of pores in organic matter and water distribution characteristics in pores of organic matter are conducted. During the biochemistry stage, kerogen is generated by bacterial action and condensation polymerization. Because the C-H bonds of aliphatics in kerogen release, aliphatic-intermolecular pores occur. During the thermo-catalysis stage, asphaltenes, liquid hydrocarbon and residual kerogen are generated by thermal-depolymerization, and cracking of asphalt turn out to be liquid hydrocarbon, so the marginal-oil pores (liquefied pores) form. During the thermo-cracking stage, liquid hydrocarbon crack into wet gas, and major pores in organic matter are marginal (or internal) -gas pores. During the deep high temperature stage, hydrocarbon transform into dry gas, owing to the release of C-H bonds in kerogen aromatics, pores in organic matter mainly include intermolecular pores in aromatic and gas pores. In addition, it is water that is involved in the pores of organic matter during each thermal evolution stage of shale kerogen, which shows a solid-liquid interface effect. As a theoretical basis on exploration and development of shale gas, it is valuable to obtain better understanding on production discipline of shale gas.