Flow Simulation and Influence Factors Analysis of CO2 Foam Fracturing in Annulus Injection

CO2 foam fracturing fluid is widely used in unconventional oil and gas production because of its easy flowback and low damage to the reservoir. Nowadays, the fracturing process of CO2 foam fracturing fluid injected by coiled tubing is widely used. However, the small diameter of coiled tubing will cause a large frictional pressure loss in the process of fluid flow, which is not beneficial to the development of fracturing construction. In this paper, the temperature and pressure calculation model of gas, liquid, and solid three-phase fluid flow in the wellbore under annulus injection is established. The model accuracy is verified by comparing the calculation results with the existing gas, solid, and gas and liquid two-phase model of CO2 fracturing. The calculation case of this paper shows that compared with the tubing injection method, the annulus injection of CO2 foam fracturing fluid reduces the friction by 3.06 MPa, and increases the wellbore pressure and temperature by 3.06 MPa and 5.77°C, respectively. Increasing the injection temperature, proppant volumetric concentration, and foam quality will increase the wellbore fluid temperature and make the CO2 transition to the supercritical state while increasing the mass flow rate will do the opposite. The research results verify the feasibility of the annulus injection of CO2 foam fracturing fluid and provide a reference for the improvement of CO2 foam fracturing technology in the field.

Determination of the Near-Wellbore Pressure Drop for Dual Casing in Hydraulic Fracturing and Refracturing Applications

Due to the increases in completion costs demand for production improvements, fracturing through double casing in upper reservoirs for mature wells and refracturing early stimulated wells to change the completion design, has become more and more popular. One of the most common technologies used to re-stimulate previously fracked wells, is to run a second, smaller casing or tubular inside of the existing and already perforated pipes of the completed well. The new inner and old outer casing are isolated from each other by a cement layer, which prevents any hydraulic communication between the pre-existing and new perforations, as well as between adjacent new perforations. For these smaller inner casing diameters, specially tailored and designed re-fracturing perforation systems are deployed, which can shoot casing entrance holes of very similar size through both casings, nearly independent of the phasing and still capable of creating tunnels reaching beyond the cement layer into the natural rock formation. Although discussing on the API RP-19B section VII test format has recently been initiated and many companies have started to test multiple casing scenarios and charge performance, not much is known about the complex flow through two radially aligned holes in dual casings. In the paper we will look in detail at the parameters which influence the flow, especially the Coefficient of Discharge of such a dual casing setup. We will evaluate how much the near wellbore pressure drop is affected by the hole's sizes in the first and second casing, respectively the difference between them and investigate how the cement layer is influenced by turbulences, which might build up in the annulus. The results will enhance the design and provide a better understanding of fracturing or refracturing through double casings for hydraulic fracturing specialists and both operation and services companies.

Formation Pressure Inversion Method Based on Multisource Information

Summary The exploration and development of offshore oil and gas have greatly alleviated the tension of global oil and gas resources. However, the abnormal pressure of offshore reservoirs is more common compared with terrestrial oil and gas reservoirs, and the marine geological structure is complex, with the development of faults, fractures, and high and steep structures, which leads to the strong anisotropy of formation pore pressure distribution and uncertainty of pressure system change. In this paper, considering the corresponding characteristics of the randomness of the formation pressure prediction results in the Eaton equation for their respective variables, a formation pressure inversion method based on multisource information, such as predrilling data, bottomhole while drilling data, seabed measured data, and surface measured data, is established. On this basis, combined with the data of a well in the South China Sea, the variation law of the uncertainty of formation pressure prediction results under the conditions of predrilling data, measurement while drilling (MWD) data, and their mutual coupling is analyzed. The simulation results show that the uncertainty distribution of formation pressure prediction based solely on predrilling data shows linear accumulation trend with well depth, and the formation pressure inversion method based on multisource information can significantly curb the increasing trend of uncertainty when MWD data are introduced. Therefore, through the analysis of typical change patterns of monitoring parameters under normal/abnormal conditions during drilling, combined with the method of multisource information, the abnormal pressure information can be accurately predicted and inversed, which provides important support for wellbore pressure regulation under complex formation conditions.

Double Casing Exit for Side-Track to Commingle Two Borehole Sizes Based Sections in One Slim Shot to Well TD

This project began when a 9-5/8" in 43.5 ppf production casing became inaccessible due to the existing cemented pipe inside, preventing further reservoir section exposure and necessitating a mechanical side-track meanwhile introducing the challenge of loosing one section and imposimg slim hole challenges. The size and weight of the double-casing made for challenging drilling, as did the eight very different formations, which were drilled. The side-track was accomplished in two steps, an 8½ in hole followed by a single long 6⅛ in section, rather than the three steps (16 in, 12¼ in, 8½ in) that are typically required. The optimal kick off point carfully located across the dual casing by running electromagnetic diagnostics, the casing collar locator, and the cement bond log. The double casing mill was carefully tailored to successfully accomplish the exit in one run. Moreover, an extra 26 ft. MD rathole was drilled, which helped to eliminate the mud motor elongation run. A rotary steerable system was utilized directly in a directional BHA to drill an 8½ in open hole building section from vertical to a 30⁰ inclination. A 7.0 in liner was then set to isolate weak zones at the equivalent depth of the outer casing (13-3/8"). Subsequently, a single 6⅛ in section was drilled to the well TD through the lower eight formations. Drilling a 6⅛ in section through eight formations came with a variety of challenges. These formations have different challenging behaviors relative to the wellbore pressure that typically leads to the drilling being done in two sections. Modeling the geo-mechanical characteristics of each formation allowed the determination of a mud weight range and rheology that would stabilize the wellbore through all eight formations. The slim, 6⅛ in, hole was stabilized with higher equivalent circulating density (ECD) values than is typically used in larger boreholes. Optimizing mud weight and drilling parameters, while managing differential sticking with close monitoring of real-time ECD, helped to stabilize the high-pressurized zones to deliver the well to the desired TD with a single borehole. This project represents the first time in Kuwait that double casings in such large sizes have been cut and sidetracked. It is also the first time these eight formations have been cut across such a smaller hole size, slim hole (6⅛ in) in a single shot. Geo-mechanical modeling allowed us to stabilize the pressurized formations and to control the ECD. The well also deployed the longest production liner in the field commingling multiple reservoirs with differnt pore pressure ramps, with excellent cement quality providing optimal zonal isolation.

Study of Homogeneous Reservoir Pressure Inversion Model Based on Permeability Mechanics and Interpretation Software Design

Well test analysis is required during the extraction of oil and gas wells. The information on formation parameters can be inverted by measuring the change in wellbore pressure at production start-up or after well shutdown. In order to calculate the characteristic parameters of the well, this paper creates a well test interpretation model for homogeneous reservoirs based on the theory of seepage mechanics, uses the Stehfest–Laplace inversion numerical inversion algorithm, and builds the Gringarten–Bourdet logarithmic curves model. The model can be used to evaluate the homogeneous reservoir. We use this model to design the pressure inversion interpretation software to implement a pressure inversion method based on permeability mechanics theory by using computer. The software can obtain the reservoir characteristic parameters such as permeability ( K ), skin coefficient ( S ), and wellbore storage coefficient ( C ). The homogeneous formation Gringarten–Bourdet curves data are available at https://github.com/JXLiaoHIT/Study-of-homogeneous-reservoir-pressure-inversion-model.

Application of a Drilling Simulator for Real-Time Drilling Hydraulics Training and Research

Challenging wells require an accurate hydraulic model to achieve maximum performance for drilling applications. This work was conducted with a simulator capable of recreating the actual drilling process, including on-the-fly adjustments of the drilling parameters. The paper focuses on the predictions of the drilling simulator's pressure losses inside the drill string and across the open-hole and casing annuli applying the most common rheological models. Comparison is then made with pressure losses from field data. Drilling data of vertical and deviated wells were acquired to recreate the actual drilling environment and wellbore design. Several sections with a variety of wellbore sizes were simulated in order to observe the response of the various rheological models. The simulator allows the input of wellbore and bottom-hole assembly (BHA) sizes, formation properties, drilling parameters, and drilling fluid properties. To assess the hydraulic model's performance during drilling, the user is required to input the drilling parameters based on field data and match the penetration rate. The resulting simulator hydraulic outputs are the equivalent circulation density (ECD) and standpipe pressure (SPP). The simulator's performance was assessed using separate simulations with different rheological models and compared with actual field data. Similarities, differences, and potential improvements were then reported. During the simulation, the most critical drilling parameters are displayed, emulating real-time measured values, combined with the pore pressure, wellbore pressure, and fracture pressure graphs. The simulation results show promise for application of real-time hydraulic operations. The simulated output parameters, ECD and SPP, have similar trends and values with the values from actual field data. The simulator's performance shows excellent matching for a simple BHA, with decreasing system's accuracy as the BHA design becomes more complex, an area of future improvement. The overall approach is valid for non-Newtonian drilling fluid pressure losses. The user can observe the output parameters, and by adding a benchmark safety value, the simulator gives a warning of a potential fracture of the formation or maximum pressure at the mud pumps. Thus, by simulating the drilling process, the user can be trained for the upcoming drilling campaign and reach the target depth safely and cost-effectively during actual drilling. The simulator allows emulation of real-time hydraulic operations when drilling vertical and directional wells, albeit with a simple BHA for the latter. The user can instantly observe the output results, which allows proper action to be taken if necessary. This is a step towards real-time hydraulic operations. The results also indicate that the simulator can be used as an excellent training tool for professionals and students by creating wellbore exercises that can cover different operating scenarios.

The Evolution of CaCO3 Scaling Potential in ADNOC Reservoirs Under Water Flooding and CO2 WAG Scenarios

Wells producing from an oilfield in Abu Dhabi were investigated to understand the CaCO3 scaling risk at current production conditions, and to predict how the downhole and topside scaling potential will change during a planned CO2 WAG project. The results of this study will be used to design the correct scale inhibitor treatment for each production phase. A rigorous scale prediction procedure for pH dependent scales previously published by the authors was applied using a commercial integrated PVT and aqueous modelling software package to produce scale prediction profiles through the system. This procedure was applied to run many sensitivity studies and determine the impact of field data variables on the final scale predictions. These results were used to examine the scaling potential of current and future fluids by creating a diagnostic "what if" chart. Some of the main variables investigated include changes in operating pressure, CO2 and H2S concentrations and variable water cut. Scale prediction profiles through the entire system from reservoir to stock tank conditions were obtained using the above modelling procedure. The main findings in this study are: (i) That CaCO3 scale is not predicted to form at separator conditions under any of the current or future scenarios investigated for these wells. This is due to the high separator pressure which holds enough CO2 in solution to keep the pH low and prevent scale precipitation. (ii) The water at stock tank conditions was found to be the critical point in the system where the CaCO3 scaling risk is severe, and where preventative action must be taken. (iii) Implementing CO2 WAG does not affect CaCO3 scaling risk at separator conditions where fluids remain undersaturated. However, the additional CO2 dissolves more CaCO3 rock in the reservoir producing higher alkalinity fluids which result in more CaCO3 scale precipitation at stock tank conditions. (iv) Fluids entering the wellbore are likely to precipitate some CaCO3 (albeit at a fairly low saturation ratio, SR) due to a significant pressure drop and the relatively high temperature, and this is not associated with the-bubble point in this case. This downhole scaling potential becomes slightly worse by an increase in CO2 concentration during CO2 WAG operations.(v) Scale inhibitor may or may not be required to treat downhole fluids depending on the wellbore pressure drop, but it is always necessary to treat fluids downstream of the separator due to the very high scaling potential at stock tank conditions. By applying a rigorous scale prediction procedure, it was possible to study the impact of CO2 WAG on the risk of CaCO3 scale precipitation downhole and topside for this field. These results highlight the current threat downhole and at stock tank conditions in particular and show how this will worsen with the implementation of CO2 WAG and this will require a chemical treatment review.

Study on the Surge-Swab Pressure considering the Effect of the Cutting Plug in Shale Drilling

Wellbore instability is a frequent problem of shale drilling. Accurate calculation of surge-swab pressures in tripping processes is essential for wellbore pressure management to maintain wellbore stability. However, cutting plugs formed in shale horizontal wells have not been considered in previous surge-swab pressure models. In this paper, a surge-swab pressure model considering the effect of cutting plugs is established for both open pipe string and closed pipe string conditions; In this model, the osmotic pressure of a cutting plug is analyzed. The reduction of cutting plug porosity due to shale hydration expansion and dispersion is considered, ultimately resulting in an impermeable cutting plug. A case study is conducted to analyze swab pressures in a tripping out process. The results show that, in a closed pipe condition, the cutting plug significantly increases the swab pressures below it, which increase with the decrease of cutting plug porosity and the increase of cutting plug length. Under the give condition, the swab pressure at the bottom of the well increases from 3.60 MPa to 8.82 MPa due to the cutting plug, increasing by 244.9%. In an open pipe string condition, the cutting plug affects the flow rate in the pipes and the annulus, resulting in a higher swab pressure above the cutting plug compared to a no-cutting plug annulus. The difference increases with the decrease of the porosity and the increase of the length and the measured depth of the cutting plug. Consequently, the extra surge-swab pressures caused by cutting plugs could result in wellbore pressures out of safety mud density window, whereas are ignored by previous models. The model proposes a more accurate wellbore pressure prediction and guarantees the wellbore stability in shale drilling.

Experimental Study on the Suspension Amount of Invasion Gas in Drilling Fluid with Yield Stress

The gas suspension phenomenon caused by the yield stress of the drilling fluid affects the accurate calculation of wellbore pressure after gas invasion. At present, most studies on the bubble suspension in the yield stress fluid focus on the single-bubble suspension condition and there are few studies on the gas suspension concentration. This paper carried out the GSC (gas suspension concentration) experiment in the simulated drilling fluid, xanthan solution, with different gas invasion methods. The GSC in the drilling fluid under the conditions of diffuse gas invasion and differential pressure gas invasion was simulated by using two methods of stir-depressurization and continuous ventilation. The results showed that when the size of a single bubble satisfied the single-bubble suspension condition, multiple bubbles can be suspended at the same time. The GSC is affected by the average size of the suspended bubbles, the yield stress of the drilling fluid, and the gas invasion modes. For different gas invasion modes, the empirical models of critical GSC related to the dimensionless number Bi are established. Compared with the experimental data, the relative error of the critical GSC in diffuse gas invasion is less than 6% and the relative error of the critical GSC in differential pressure gas invasion is less than 10%. The results of this work can provide guiding significance for accurate calculation of wellbore pressure.

Successful Wellbore Pressure Management Using Intelligent MPD and Continuous Circulation System on an HPHT Well in Vietnam

A managed pressure drilling (MPD) and early influx detection system is gaining worldwide acceptance as an enabling technology for drilling wells with challenges that can lead to tremendous nonproductive time (NPT), significant unplanned costs, and increased risk exposure. MPD counteracts the high cost of these wells by delivering significant savings when eliminating fluid losses or well control events that cause NPT. MPD technology has proven that is used to not only reduce NPT but also enable access to reserves previously considered un-drillable. In this case history, MPD helped to reach reserves that could not be reached in the first well. Client planned to drill the well A, which is its second offshore exploration well. Early on in 2019, the campaign encountered significant problems because of high temperatures and a narrow pore-pressure/fracture-pressure (PP/FP) gradient window. Additionally, using conventional drilling methods in offset wells led to problems relating to kicks, loss scenarios, and stuck pipe. Before drilling the second exploration well, the relevant parties considered that the first well-presented multiple drilling issues, and they drew from past success. The latter job had ended with reaching all the well targets despite high-pressure/high-temperature (HP/HT) conditions using a continuous circulating device in conjunction with an MPD system. Therefore, this combination of technologies was chosen to drill the well A. The operator used the MPD system, from the start when drilling the 14 3/4-in × 16-in. hole section to the end when drilling the 8 1/2-in. hole section, in offshore Vietnam. Applying MPD technology on this well resulted in many benefits, including the main benefit of always controlling the bottomhole pressure through the challenging zones. MPD also helped to maintain the equivalent circulating destiny (ECD) and equivalent static density (ESD) during drilling, connections, and a logging operation to mitigate the risk of any gas breaking out at the surface and to drill the well to the desired target depth. This paper focuses on using MPD technology in conjunction with the continuous circulation system, in offshore Vietnam. It goes into detail by describing the experience and providing some of the lessons learned.