In depleted offshore reservoirs, pore pressure declines and consequently horizontal in-situ stresses decrease as well. This causes a very limited well depth for extended-reach drilling targeting to offshore depleted reservoirs. In this paper, based on analyzing the safe mud weight window of the depleted offshore reservoirs, a model of predicting the Maximum Allowable Measured Depth (MAMD) for extended-reach drilling targeting to offshore depleted reservoirs is developed. Meanwhile, the numerical method of the model is proposed, and the key affecting factors of the MAMD are also investigated. The results show the pore pressure depletion has obvious effects on the MAMD. With the depletion of pore pressure, the safe mud weight window appears narrower and even disappears, consequently the predicted MAMD becomes shorter. For a normal regime depositional environment in the depleted reservoirs, it may be impossible to drill with conventional drilling method in the nearby directions of the maximum horizontal in-situ stress, while it may be much safer and attain a long MAMD when drilling in the directions near the minimum horizontal in-situ stress. Moreover, the MAMD will decrease with the increase of Poisson’s ratio and Biot’s parameter, and its response to Poisson’s ratio is more obvious. For a specific target depleted reservoir, the extended-reach drilling with a high borehole inclination may have a longer MAMD than that with a low borehole inclination. This paper presents a method for promoting the design of extended-reach drilling targeting to offshore depleted reservoirs.

https://www.mdpi.com/1996-1073/11/5/1072/pdf

The Maximum-Allowable Well Depth While Drilling of Extended-Reach Wells Targeting to Offshore Depleted Reservoirs

In coal seam gas (CSG) wells, water is periodically removed from the wellbore in order to keep the bottom-hole flowing pressure at low levels, facilitating the desorption of methane gas from the coal bed. In order to calculate gas flow rate and further optimize well performance, it is necessary to accurately monitor the liquid level in real-time. This paper presents a novel method based on autocorrelation function (ACF) analysis for determining the liquid level in CSG wells under intense noise conditions. The method involves the calculation of the acoustic travel time in the annulus and processing the autocorrelation signal in order to extract the weak echo under high background noise. In contrast to previous works, the non-linear dependence of the acoustic velocity on temperature and pressure is taken into account. To locate the liquid level of a coal seam gas well the travel time is computed iteratively with the non-linear velocity model. Afterwards, the proposed method is validated using experimental laboratory investigations that have been developed for liquid level detection under two scenarios, representing the combination of low pressure, weak signal, and intense noise generated by gas flowing and leakage. By adopting an evaluation indicator called Crest Factor, the results have shown the superiority of the ACF-based method compared to Fourier filtering (FFT). In the two scenarios, the maximal measurement error from the proposed method was 0.34% and 0.50%, respectively. The latent periodic characteristic of the reflected signal can be extracted by the ACF-based method even when the noise is larger than 1.42 Pa, which is impossible for FFT-based de-noising. A case study focused on a specific CSG well is presented to illustrate the feasibility of the proposed approach, and also to demonstrate that signal processing with autocorrelation analysis can improve the sensitivity of the detection system.

A Novel Acoustic Liquid Level Determination Method for Coal Seam Gas Wells Based on Autocorrelation Analysis

Estimating formation leakage pressure using a coupled model of circulating temperature-pressure in an eccentric annulus

Construction of offshore gas wells is characterized by increased requirements for both the technological process in general and the technological parameters of drilling fluids in particular. Parameters and properties of the used drilling muds must meet a large number of requirements. The main one is the preservation of the permeability of the reservoirs, in addition to the environmental and technological concerns. At the same time, pressures in the productive formation at offshore fields are often high; the anomaly coefficient is 1.2 and higher. The use of barite in such conditions can lead to contamination of the formation and a decrease in future well flow rates. In this regard, the development and study of the compositions for weighted drilling muds is necessary and relevant. The paper presents investigations on the development of such a composition based on salts of formic acid (formates) and evaluates the effect of the molecular weight of the polymer reagent (partially hydrolyzed polyacrylamide) on the equivalent circulation density of the drilling fluid. The result of the work is a formate-based high-density drilling mud with no barite added. Application of such a mud will preserve the permeability of the productive formation.

Dependence of the Equivalent Circulation Density of Formate Drilling Fluids on the Molecular Mass of the Polymer Reagent

The main objective of this paper is to use experimental measurements of downhole pressure, temperature and initial mud density to predict downhole density using multigene genetic programming. From the results, the mean square error for the WBM density model was 0.0012, with a mean absolute error of 0.0246 and the square of correlation coefficient (R2) was 0.9998; while for the OBM, the MSE was 0.000359 with MAE of 0.01436 and R2 of 0.99995. In assessing the OBM model's generalization capability, the model had an MSE of 0.031, MAE of 0.138 and mean absolute percentage error (MAPE) of 0.95%.

Modeling the downhole density of drilling muds using multigene genetic programming

The accurate control of the wellbore pressure not only prevents lost circulation/blowout and fracturing formation by managing the density of the drilling fluid, but also improves productivity by mitigating reservoir damage. Calculating the geothermal pressure of a geothermal well by constant parameters would easily bring big errors, as the changes of physical, rheological and thermal properties of drilling fluids with temperature are neglected. This paper researched the wellbore pressure coupling by calculating the temperature distribution with the existing model, fitting the rule of density of the drilling fluid with the temperature and establishing mathematical models to simulate the wellbore pressures, which are expressed as the variation of Equivalent Circulating Density (ECD) under different conditions. With this method, the temperature and ECDs in the wellbore of the first medium-deep geothermal well, ZK212 Yangyi Geothermal Field in Tibet, were determined, and the sensitivity analysis was simulated by assumed parameters, i.e., the circulating time, flow rate, geothermal gradient, diameters of the wellbore, rheological models and regimes. The results indicated that the geothermal gradient and flow rate were the most influential parameters on the temperature and ECD distribution, and additives added in the drilling fluid should be added carefully as they change the properties of the drilling fluid and induce the redistribution of temperature. To ensure the safe drilling and velocity of pipes tripping into the hole, the depth and diameter of the wellbore are considered to control the surge pressure.

Equivalent Circulation Density Analysis of Geothermal Well by Coupling Temperature

A whole-process simulation for energy piles in unsaturated soils considering the coupled heat and moisture transfer

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Zheng Yan

Papers

Equivalent Circulation Density Analysis of Geothermal Well by Coupling Temperature

A whole-process simulation for energy piles in unsaturated soils considering the coupled heat and moisture transfer

Equivalent Circulation Density Analysis of Geothermal Well by Coupling Temperature

An improved model for predicting the thermal conductivity of sand based on a grain size distribution parameter