Much attention has been given to the drilling, completion and initial production stages of horizontal wells. The advantages of using horizontal well technology is well documented and many successful field cases-in terms of well productivity-have been reported. Much less attention has been given to some of the production problems which may arise when such wells start to produce water. In particular, there are a range of specific production chemistry issues which have not been widely discussed in the industry literature. The main reason for this is that, to date, there is very little operational experience with such problems. In this paper, we consider the problem of carrying out scale inhibitor squeeze treatments in horizontal wells. If carbonate or sulphate scale formation occurs in a water producing horizontal well, we anticipate that the treatment strategy will be rather different from that which would commonly be applied in a vertical well. The authors are not aware of very much field experience which can be called upon for this type of treatment. We have therefore taken a conceptual design approach which tries to anticipate the problem and to plan ahead for its solution. A simulation and modelling study is presented in which various scale inhibitor treatment strategies are examined with a view to determining the main factors which affect this process in a horizontal well. We tackle a number of important questions which will face the industry as scaling problems are encountered in horizontal wells. We present this work as a preliminary study which tries to highlight some of the issues, problems and questions which will arise in the future when more horizontal wells start to operate at higher watercuts. The objective is to raise these issues at this stage in order to stimulate some discussion within the industry about how scaling problems in horizontal wells will be solved, possibly by using squeeze technology. We do not solve all of the problems which we raise but a number of points emerge from our study which we present as a preliminary assessment of this problem. Introduction and Background More and more current field developments are employing horizontal well technology in order to improve reservoir sweep efficiency, raise well productivity and to generally improve project economics(1). Indeed, many field developments would not be possible without the use of horizontal wells. The states of development of horizontal well technology might be broadly classified into the following three categories: (i) drilling and completion, (ii) reservoir characterization and engineering and (iii) production operations and well intervention. This order also represents the industry+s decreasing level of experience, and hence knowledge, with the third category being some way behind the others(2). How much one might need to engage in the third area dealing with water production and stimulation depends on the specific company+s view on how they wish to use horizontal wells. If no period of post-water breakthrough is envisioned, ...
The emission bands observed by Azam and Reddy and ascribed by them to two systems, b1Σ+, a1Δ–X3Σ−, of SeO are shown to arise from a single system, b1Σ+–X3Σ−. Head-origin separations are employed to derive rough values of Bν′ and these in turn are used to estimate band-origins and thence vibrational constants. The values of the constants derived for b1Σ+ of 80SeO are as follows: Tc = 9724.1 cm−1 (with respect to the minimum in the Ω = 0+, F1 component of X3Σ−, Gν = 836.58(ν + 1/2) – 5.11(ν + 1/2)2, and Bν = 0.457 – 0.0034(ν + 1/2). The separation (Ω = 1)c – (Ω = 0+)c in the ground state is found to be 165.8 cm−1.
This paper presents a gas kick simulation model for horizontal and conventional wells. The model is based on the solution of the appropriate mass and pressure balance equations. The unique aspect of this model is the coupling of the fluid flow in the horizontal section with the gas influx from the formation. Two particular kick control scenarios are presented. The simulation results demonstrate that the actual horizontal drilling situation, actions taken immediately upon kick detection, and operations during kick development all have an effect on the development of the kick profile along the wellbore, which in turn has significant impact on the pressure build-up during the shut-in period and the subsequent kick circulation operations.
The drilling of wells offshore West Madura, East Java, can be challenging. The geological structure of the area often requires drilling at high deviations with large stepouts, through formations consisting of carbonates, shales and sands. As a result, wellbore stability issues are frequently encountered, such as total mud losses, stuck pipe, loss of bottom hole assemblies and associated sidetracking, leading to non-productive drilling time and unnecessary costs. In order to lower the associated risks the operator commissioned a geomechanics study, to identify the root causes of the wellbore stability issues, and provide recommendations for improved drilling of future development wells. Numerous wells had been drilled within the area of interest over more than three decades, resulting in a large variation in the availability and quality of data. Recently acquired 3D seismic data were also available. Therefore, a multidisciplinary approach was employed with geomechanics at its core, accompanied by well log conditioning, generation of synthesized shear sonic logs, simultaneous seismic inversion, and drilling engineering. The integration of the different disciplines ensured the development of robust 1D and 3D geomechanical models, which were applied to develop mud weight recommendations for the planned development wells. Firstly, a 1D geomechanical model was constructed. Two recently drilled wells had excellent data sets: extended leakoff and minifrac test results showed very consistent fracture closure pressures. This, combined with the presence of borehole breakouts and direct rock strength measurements on core, allowed the determination of the minimum and maximum horizontal stresses with only small ranges of uncertainty. The 1D geomechanical model was further calibrated by a detailed comparison with critically reviewed drilling incidents. Simultaneously, well logs were conditioned and pseudologs were created, which were used for 3D simultaneous seismic inversion, from which rock property volumes (P-impedance, S-impedance, and Vp/Vs) were derived in turn. Gardner’s relationship was used to transform the seismic velocity data to a density volume. The 1D geomechanical model was subsequently combined with the 3D seismic data via a structural model grid, resulting in a full 3D geomechanical model containing cubes of pore pressure, principal insitu stresses, elastic rock properties and rock strength. Finally, wellbore stability analyses were performed for the planned development wells, including a quantitative risk assessment to gauge the impact of uncertainties in various key variables on the overall potential drilling success. Well deviation and azimuth sometimes showed a counterintuitive effect on recommended mud weights, as illustrated by stereonet plots. A key factor in the execution of this project was the integration of data and expertise in petrophysics, seismic inversion, geomechanics and drilling engineering over a relatively short timeframe to deliver a technically robust set of mud weight windows, which, combined with recommendations based on a detailed review of passed drilling practices, should enable the successful drilling of the wells in this very challenging environment.
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