Reservoir Drilling, Completion and Breaker Fluid Qualification for Direct Injection Wells on the Johan Castberg Field – A Multi-Disciplinary Study to Secure Injectivity

2021 ◽  
Author(s):  
Charlotte Eliasson ◽  
Ove Braadland ◽  
Håvard Kaarigstad ◽  
Anne-Mette Mathisen ◽  
Zalpato Ibragimova ◽  
...  
Keyword(s):  
Filter Cake ◽  
Drilling Fluid ◽  
Direct Injection ◽  
Time Frame ◽  
Development Project ◽  
Fluid System ◽  
Injection Wells ◽  
Field Development ◽  
Fluid Systems ◽  
Open Hole

Abstract For the Johan Castberg field development project, injector wells are important for achieving high production and overall high recovery factors. Injectivity has become more important due to limitations in injection pressures and required control of fracture growth. Securing injectivity has been identified as one of the project’s main risks, making drill-in fluid and breaker fluid system qualification a vital parameter for success. Operational procedures and completion design also affect the effectiveness of breaker fluid placement and, thus, the overall injectivity of the well. In this paper, we present a cross-disciplinary systematic approach for the reservoir drill-in fluid and breaker fluid qualification to ensure injectivity in these wells. Two wells were selected for covering the expected pressure and temperature range of the field in an environmentally sensitive area. Two independent fluid systems were designed, where the bridging material consisted of either sized salt particles or calcium carbonate particles. The open hole completion design has been optimized for an effective breaker fluid placement, using a modified gravel pack system with a wash pipe. The displacement sequence has been optimized for effective deployment. An extensive laboratory test matrix for both the reservoir drilling fluid (RDF) and breaker fluid system was established, including thorough analysis of the interaction between the deposited filter cake and the breaker fluid system. The RDF and breaker fluid formulation optimization was performed whilst keeping in mind the operational requirements and the well’s future injectivity The presented results show successful qualification of two independent fluid and breaker fluid systems where filter cake breakthrough is achieved within the desired time frame. The fluid systems in combination with the lower completion design and operational procedures ensure maximal reservoir exposure of the breaker fluid solution and enable rapid deterioration of the filter cake.

scholarly journals Experimental approach for assessing filter-cake removability derived from reservoir drill-in fluids

2021 ◽  
Vol 11 (11) ◽  
pp. 4029-4045
Author(s):  
Asad Elmgerbi ◽  
Gerhard Thonhauser ◽  
Alexander Fine ◽  
Rafael E. Hincapie ◽  
Ante Borovina
Keyword(s):  
Potassium Carbonate ◽  
Filter Cake ◽  
Experimental Methodology ◽  
Drilling Fluids ◽  
Cleaning Efficiency ◽  
Fluid Systems ◽  
Open Hole ◽  
Lift Off ◽  
Dynamic Filter ◽  
Cake Removal

AbstractPredicting formation damage in cased-hole and open-hole completion wells is of high importance. This is especially relevant when the damage is caused by reservoir drill-in fluids hence being well-bore induced. Cake filter removal has proven to be a good approach to estimate induced damage and to evaluate drill-in fluids’ performance. We present an experimental methodology to evaluate filter cake removal, which could be achieved during the well's initial production. An improved experimental setup, to the ones presented in literature, has been developed to enhance data quality. A twofold approach was used for setup design, and first, it can be integrated with devices used to evaluate the static/dynamic filter-cake. Second, it can be used to simulate more realistic cases (field related) by adjusting the experiment parameters. Hence, to replicate the expected drawdown pressure as well as the corresponding flow rate of the studied reservoir. Three key indicators directly related to filter-cake removal were used as evaluators in this work. Lift-off pressure, internal and external filter cakes removal efficiency. Three reservoir fluid systems were studied, two polymer-based and one potassium carbonate. Results show that pressure required to initiate the collapsing process of the filter cake is not significant. Polymer-based drilling fluids showed better performance in terms of external and internal filter cake cleaning efficiency comparing to potassium carbonate. Moreover, we observed that filtrate volume has no clear relation with the degree of residual damage.

A QUICK-LOOK EVALUATION OF THE SANDING POTENTIAL OF PRODUCTION WELLS IN THE YOLLA FIELD

2005 ◽  
Vol 45 (1) ◽  
pp. 77
Author(s):  
Z.J. Pallikathekathil ◽  
J.R. Marsden ◽  
R.J. Suttill ◽  
M. Mussared ◽  
L. Qiuguo
Keyword(s):  
Time Frame ◽  
Development Planning ◽  
Rock Properties ◽  
Earth Model ◽  
Well Test ◽  
Worst Case ◽  
Data Set ◽  
Field Development ◽  
Production Wells ◽  
Open Hole

The preliminary downhole completions and surface facilities for the Yolla field had been designed based on the well test results from the Yolla–1 well. This well had produced insignificant sand during production testing, but during the field development planning, there was a concern raised regarding the propensity of some zones to sand. If the zones were prone to sanding, then the design of completions and surface facilities would have to be re-worked on with steps taken to mitigate any sanding. Mitigation steps would include perforation strategy (selective zone perforation, oriented perforation), sand screen or gravel pack.Therefore, a quick-look evaluation of the sanding potential of the particular zones of interest was undertaken to be completed within the project time frame. The sand zones analysed were Sand–2718, –2755, –2809, and –2973 from the Eastern View Coal Measures(EVCM).Yolla–2 well had the most complete data set available. A mechanical earth model (MEM) containing information on rock properties, pressures and in-situ stresses was constructed based on open-hole log data from the Yolla–2 appraisal well. Laboratory tests provided some uni-axial compressive strength (UCS) data for calibration of the model. The MEM data were input into sanding analyses, for various reservoir depths and for selected completion and perforation options. Since some MEM parameters were poorly constrained, best- and worst-case scenarios and sensitivities were evaluated to assess the influence of geomechanical parameters on sanding propensity.When Yolla–3 and –4 were drilled, more complete sets of logs were acquired and used to improve confidence in the earlier evaluations, and to check the validity of certain assumptions that had been made. With revised evaluation for Yolla–3 and –4, decisions on the completion strategy and perforation intervals were taken and implemented in the field development planAfter completion, both Yolla–3 and Yolla–4 were tested and sanding rates were monitored. After initial transient production of sand during clean-up, sand rates produced were insignificant. This confirmed the results of the quicklook geomechanical analyses that had been conducted.

Incorporation of Fe3O4 Nanoparticles as Drilling Fluid Additives for Improved Drilling Operations

2016 ◽  
Author(s):  
Zisis Vryzas ◽  
Omar Mahmoud ◽  
Hisham Nasr-El-Din ◽  
Vassilis Zaspalis ◽  
Vassilios C. Kelessidis
Keyword(s):  
Electron Microscope ◽  
Rheological Properties ◽  
Fe3o4 Nanoparticles ◽  
Filter Cake ◽  
Drilling Fluid ◽  
Filter Press ◽  
Rheological Parameters ◽  
Fluid Loss ◽  
Fluid System ◽  
Custom Made

A successful drilling operation requires an effective drilling fluid system. Due to the variety of downhole conditions across the globe, the fluid system should be designed to meet complex challenges such as High-Pressure/High-Temperature (HPHT) environments, while promoting better productivity with a minimum interference for completion operations. This study aims to improve the rheological and fluid loss properties of water-bentonite suspensions by using both commercial (C-NP) and custom-made (CM-NP) iron oxide (Fe3O4) nanoparticles (NP) as drilling fluid additives. Superparamagnetic Fe3O4 NP were synthesized by the co-precipitation method. Both types of nanoparticles were characterized by a High Resolution Transmission Electron Microscope (TEM) and X-ray Diffraction (XRD). Base fluid (BF), made of deionized water and bentonite at 7wt%, was prepared according to American Petroleum Institute (API) procedures and nanoparticles were added at 0.5wt%. A Couette-type viscometer was used to analyze the rheological characteristics of these fluids at different shear rates and various temperatures (up to 158°F). The rheological parameters were obtained from analysis of viscometric data using non-linear regression. The API Low-Pressure/Low-Temperature (LPLT) and HPHT fluid filtrate volumes were measured, using a standard API LPLT static filter press (100 psi, 77°F) and an API HPHT filter press (300 psi, 250°F). Observation of the porous matrix morphology of the produced filter cakes was done with Scanning Electron Microscope (SEM). TEM showed that the mean diameter of the CM-NP was 7–8 nm, with measured surface areas between 100–250 m2/g. The C-NP had an average diameter of <50 nm, as per manufacturer specifications. The XRD of the CM-NP revealed peaks corresponding to pure crystallites of magnetite (Fe3O4) with no impurities. Rheological analysis showed very good fitting by the Herschel-Bulkley model with coefficient of determination (R2) greater than 0.99. Rheological properties of all samples were affected by higher temperatures, with increase in yield stress, decrease in flow consistency index (K) and slight increase in flow behavior index (n). Fluid filtration results indicated a decrease in the LPLT fluid loss and an increase in the filter cake thickness compared to the BF upon addition of higher concentrations of C-NP, because of a decrease in filter cake permeability. At HPHT conditions, samples with 0.5wt% C-NP had a smaller fluid loss by 34.3%, compared to 11.9% at LPLT conditions. CM-NP exhibited even higher reduction in the fluid loss at HPHT conditions of 40%. Such drilling fluids can solve difficult drilling problems and aid in achieving the reservoir’s highest potential by eliminating the use of aggressive, potentially damaging chemicals. Exploitation of the synergistic interaction of the utilized components can produce a water-based system with excellent fluid loss characteristics while maintaining optimal rheological properties.

A Step Change in Open Hole Gravel Packing Methodology: Drilling Fluid Design and Filter Cake Removal Method

2007 ◽  
Author(s):  
Mathew M. Samuel ◽  
Abdul Hameed Ahmad Mohsen ◽  
Aziz Ejan ◽  
Matthew Alexander Law ◽  
Chao Wei Wrong ◽  
...  
Keyword(s):  
Filter Cake ◽  
Drilling Fluid ◽  
Step Change ◽  
Removal Method ◽  
Open Hole ◽  
Gravel Packing ◽  
Fluid Design ◽  
Cake Removal

On the Development and Performance Evaluation of Potassium Silicate Polyol Drilling Fluid

2012 ◽  
Vol 524-527 ◽  
pp. 1496-1502 ◽  
Author(s):  
Ping Quan Wang ◽  
Yang Bai ◽  
Zhi Wei Qian ◽  
Gang Peng ◽  
Yi Liu ◽  
...  
Keyword(s):  
Cloud Point ◽  
Comprehensive Evaluation ◽  
Drilling Fluid ◽  
Research Direction ◽  
Potassium Silicate ◽  
Chemical Effect ◽  
Fluid System ◽  
Fluid Systems ◽  
And Performance ◽  
New Research

It has been long known that the drilling hole stability is often a major issue faced by drilling workers. And for such a great challenge, a lot of work has been done both at home and abroad in the aspect of the chemical stability of wall, including developing and successfully applying such a series of drilling fluid systems as formate, oil base, synthetic base, silicate, polyol. Since silicate and polyol are often added into drilling fluid system as aggregation inhibitors and lubricants, there is no mixing use of them. In this paper, from the perspective of the comprehensive role of treating agent, the chemical effect of potassium silicate (gel sedimentation) and the physical effects of polyol (cloud point effect) are put into composite application so that a set of drilling fluid system of membrane structure and silicon potassium polyol with gel - cloud point effect is established, and a comprehensive evaluation of the performance of the system is given a complete explanation, opening up a new research direction for drilling fluid's stabilizing well wall.

The Application of PEM Drilling Fluid System in Environmentally Sensitivity Area

2001 ◽  
Author(s):  
Xu Shaocheng ◽  
Xiaojian Jin ◽  
Li Zili ◽  
Xinjing Xiang
Keyword(s):  
Drilling Fluid ◽  
Fluid System

scholarly journals Study on Thermo-Hydro-Mechanical Coupling and the Stability of a Geothermal Wellbore Structure

Energies ◽  
2021 ◽  
Vol 14 (3) ◽  
pp. 649
Author(s):  
Xiaolin Huan ◽  
Gao Xu ◽  
Yi Zhang ◽  
Feng Sun ◽  
Shifeng Xue
Keyword(s):  
Effective Stress ◽  
Cold Water ◽  
Drilling Fluid ◽  
Water Injection ◽  
Coupled Model ◽  
In Situ Stress ◽  
Excess Pore Pressure ◽  
Mechanical Coupling ◽  
Open Hole ◽  
Cement Sheath

For processes such as water injection in deep geothermal production, heat transfer and fluid flow are coupled and affect one another, which leads to numerous challenges in wellbore structure safety. Due to complicated wellbore structures, consisting of casing, cement sheaths, and formations under high temperature, pressure, and in situ stress, the effects of thermo-hydro-mechanical (THM) coupling are crucial for the instability control of geothermal wellbores. A THM-coupled model was developed to describe the thermal, fluid, and mechanical behavior of the casing, cement sheath, and geological environment around the geothermal wellbore. The results show that a significant disturbance of effective stress occurred mainly due to the excess pore pressure and temperature changes during cold water injection. The effective stress gradually propagated to the far-field and disrupted the integrity of the wellbore structure. A serious thermal stress concentration occurred at the junction of the cased-hole and open-hole section. When the temperature difference between the injected water and the formation was up to 160 °C, the maximum hoop tensile stress in the granite formation reached up to 43.7 MPa, as high as twice the tensile strength, which may increase the risk of collapse or rupture of the wellbore structure. The tensile radial stress, with a maximum of 31.9 MPa concentrated at the interface between the casing and cement sheath, can cause the debonding of the cementing sheath. This study provides a reference for both the prediction of THM responses and the design of drilling fluid density in geothermal development.

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