High-pressure High-temperature Wells Research Articles

Effect of temperature on transport index of fish oil-based drilling mud in high pressure high temperature well: a hybrid model approach

Diesel Oil-based drilling mud used in the oil and gas industry causes severe environmental and public health issues due to its high toxicity, especially in high-pressure, high-temperature (HPHT) wells. Therefore, easily biodegradable synthetic oil-based mud with high drilling performance is essential. Fish oil is a bio-oil known for its non-toxicity, high lubricity, thermal stability, and biodegradability. Effective hole cleaning is crucial for drilling performance and is ensured by the rheological properties of drilling mud. While rheological parameter prediction can be performed using an artificial neural network (ANN) based model, such models often fail to provide accurate predictions for unseen data. In contrast, empirical models are more robust and facilitate generalization. This study aims at assessment of the suitability of invert emulsion fish oil-based drilling mud (IEFOBDM) in HPHT wells through evaluation of hole cleaning performance (HCP) using a hybrid approach that combines an ANN with nonlinear regression (NLR) for temperatures ranging from 40 °C to 80 °C.Firstly, an ANN model was developed considering mud weight, temperature, and shear rate. Secondly, the NLR model was used in the prediction of rheological parameters, namely, Yield point (YP) and Plastic viscosity (PV), based on the predicted shear stress from the ANN model. Finally, the performance metrics of the ANN-NLR rheological model were evaluated using the root mean square error (RMSE) and correlation coefficient (R2) and comparison made with the Single ANN rheological model. The results showed the outperformance of ANN-NLR model over the ANN model for rheological parameter prediction, with R2 values of (0.99) for YP and (1) for PV. The predicted PV and YP values were then used for evaluation of transport index (TI) for HCP analysis. The effect of temperature on TI analysis showed this with increase in temperature, TI also increased, indicating the proposed mud providing good HCP under HPHT conditions.

Water density–pressure–temperature modeling for drilling fluids in real-time HPHT applications

Accurate equations for extrapolating the density of water to varying pressures and temperatures are important for the petroleum industry. Water is a key component in drilling fluids, and extrapolation models of water are essential for calculating the density of the fluid as a whole for different depths in the well. This is further of paramount importance to be able to keep the pressure in the well within safety limits. This paper shows and explains how density–pressure–temperature (DPT) models referred to in the field of Petroleum are not well-suited for high-pressure, high-temperature (HPHT) wells which are becoming more and more common. It also discusses DPT- and pressure–volume–temperature (PVT) models from other disciplines and demonstrates that models with the accuracy needed for HPHT wells, are excessively complex and have unnecessary long execution times. For many challenging wells, hydraulic models run today in parallel with the operation in real-time and may constitute one of several components in a digital twin. In such applications it is important that each component runs as efficiently as possible, such that the entire system is able to deliver its results in time. In this work, new polynomial DPT models are constructed, that fill this gap in water DPT modeling. I.e., they are designed for being used for calculating the water density in real-time, and cover HPHT wells with pressure up to 200MPa and temperature up to 260°C. It is demonstrated that it is possible to construct polynomial models that are 1−2 decades faster than the industry standard used for comparison, while also being more accurate over the pressure and temperature range relevant to HPHT wells. If the accuracy can be slightly relaxed, a new model that is 2−3 orders of magnitude faster than the industry standard is proposed.

Research on the application of wellbore strengthening methodology and managed pressure drilling for HTHP wells in highly depleted reservoirs at the Nam Con Son basin

The gas production in high-temperature, high-pressure (HTHP) projects in the Nam Con Son basin is entering a declining production phase, the production duration almost reaching the final phase of the designed field life. Therefore, the need to build a development plan for maintaining and supplementing gas production is the most important in the current phase. Evaluation of gas field conditions, drilling infill wells to expand existing prospects is considered a feasible solution both technically and economically. However, the physical characteristics of the production reservoirs have changed after a long production time, including a decrease in pore pressure at the production reservoirs, posing a significant technical challenge during the drilling operations. The infill wells are required to penetrate through the shale formations interbedded with sand formations. In there, the cap rock shale layer remains at or close to virgin pressure and the sand reservoir with pore and fracture pressures has largely decreased due to production activities. There is no mud-weight window that exists any more at the transition between cap rock and reservoirs which leads to drilling problems such as loss circulation, gas kicks and especially, the well could not reach the total desired depth or production targets which impact to overall development project. This article evaluates the applicability of a combination of technologies, including utilizing special lost circulation materials to seal the fractures due to changes in reservoir properties and the application of managed pressure drilling methodologies while drilling through infill wells in HTHP conditions. The goal is to minimize the risks of well problems and provide the management of uncertainties during the drilling which improves project efficiency.

Characteristics of Viscosity of a Scale Inhibitor: An Experimental Study

The use of chemical scale inhibitors in the oil and gas industry for subsea installations has been presented for a long time, but the ever-increasing exploration of HPHT (high pressure high temperature) wells put demands on knowledge of how the rheological properties such as viscosity of scale inhibitors behave under large pressures. This work reports new experimental data of high-pressure viscosity using a rotational rheometer, measured across a pressure range of 0.1 MPa to 15 MPa, at temperatures from 273 K to 298 K, and a broad range of shear rates, 100 s^{-1} to 1000 s^{-1} for a scale inhibitor. The experimental data are used to construct a power-law regression model with fitting parameters. Results indicate that the inhibitor shows a near Newtonian behavior.

Response analysis and safety control of tubing vibration in HPHT and ultra-deep gas wells

Under the condition of high pressure, high temperature(HPHT) and high yield in ultra-deep wells, the buckling deformed tubing will produce violent vibration when opening and closing the well or production fluctuation, which will make the tubing bear large periodic fluctuating load, cause the failure of tubing thread seal, form fluid leakage channel, and induce the problem of sustained casing pressure(SCP). Serious annulus pressure will lead to increased tubing leakage, casing failure or more serious consequences. In order to explore the failure process of well barrier caused by tubing vibration in HPHT and ultra-deep wells, a fluid solid coupling vibration model of tubing is established, and the coupling vibration equation is numerically solved by the characteristic line method. Finally, an example of a gas well in the west is analyzed. The calculation results show that there is an obvious Poisson coupling effect between the tubing and the gas in the pipe in well X. The axial stress of the tubing is always in an unstable pulsating alternating stress state, reciprocating vibration along the axis and gradually attenuated to stability; the closer to the wellhead, the more violent the gas fluctuation in the pipe, and the greater the axial vibration amplitude of the upper part of the tubing away from the wellhead; large vibration of tubing may induce seal failure, resulting in oil jacket connection and pressure on a annulus; finally, the allowable annulus pressure of the example well is calculated, and the annulus pressure control measures are put forward. The research results have good guiding significance for well barrier failure analysis and annulus pressure control caused by tubing vibration in HPHT ultra-deep wells.

New wellbore temperature control design for preventing failure and poor performance of logging tools in high pressure – high temperature wells

Failure and poor performance of logging tools in high pressure-high temperature wells; the associated technical consequences and the resultant high cost of logging operations are recurrent problems in the oil & gas industry worldwide. The aforesaid prompted this work to invent the “New Wellbore Temperature Control Design” for protection of logging tools against high bottom-hole temperatures. It hinges on the novel concept of thermal drainage radius and the temperature-drop effect of chilled oil-based mud to reduce bottom-hole temperature prior to logging. The methods applied include laboratory testing, mathematical modeling and design. The novel concept of “thermal drainage radius” quantified the radial extent of temperature-drop effect in the formation, away from the wellbore. Novel mathematical models were also invented. Laboratory results showed that the formation temperature-drop from bottom-hole temperature to thermal equilibrium temperature increased with bottom-hole temperature per chilled oil-based mud. The temperature-drop duration and temperature-rise duration increased with bottom-hole temperature per chilled oil-based mud. The temperature-rise duration increased with decrease in the temperature of the chilled oil-based mud per bottom-hole temperature. Job design results showed that when placed in the zone of interest in the wellbore the heat energy absorbed increased with quantity of the chilled oil based mud but the temperature rise duration decreased with increasing heat transfer rate from the formation and vice versa. Furthermore, results revealed that the higher the thermal conductivity of the formation, the longer the thermal drainage radius and vice versa. The logging operation should commence after placement of the chilled oil-based mud in the zone of interest (no circulation of the chilled oil-based mud) and be completed before the end of the temperature-rise duration. Oil-based mud is cheap and available in every country unlike the expensive vacuum flasks and thermal insulating jackets currently used for protecting logging tools against high temperature. The new wellbore temperature control design has global applicability.

Sensitivity analysis of factors controlling the cement hot spot temperature and the corresponding well depth using a combined CFD simulation and machine learning approach

Designing a suitable cement system has been a challenging task in high pressure-high temperature wells (e.g., deep oil and gas wells, geothermal wells). Bottom hole circulating temperature (BHCT) is commonly used as the key operating variable in the cement design. However, it has been shown that cement formulations based on the BHCT failed to meet field requirements in many cases (especially in deep wells or geothermal wells). In reality, the temperature of the hot spot, where the highest temperature occurs in a well during the circulation, should be used as the setting temperature criteria for proper cement slurry formulation. However, as there are multiple factors affecting the hot spot temperature and its corresponding depth, it is not a simple task to determine these design parameters. To overcome these design challenges and facilitate optimization of the cement system formulation for the deep, hot wells, a new systematic approach has been developed by coupling a machine learning and a computational fluid dynamics (CFD) simulation technique. In this study, we investigated the effects of the five common design variables (i.e., wellbore depth, geothermal gradient, casing size, hole size and flow rate) on the hot spot temperature and the corresponding depth. Data extracted from the simulation study results were used to train multiple linear regression models, which were developed as part of using machine learning approach for comparing the influences of these five factors on the hot spot temperature and the corresponding depth. The results indicate that increasing casing size (OD), geothermal gradient and the well depth also increased the hot spot temperature and its corresponding depth, while the increasing flow rate and the wellbore size caused reduction in the hot spot temperature and its corresponding depth. Casing size and the cement circulation rate seemed to have the greatest impact. Results also indicated that the effects of these factors on the hot spot temperature and its corresponding depth were synchronized. With the increasing wellbore to casing diameter (i.e., do/di) ratio, both the hot spot temperature and its corresponding depth decreased (i.e., lower maximum cement temperature was observed at the shallower depth). The new numerical method is proven to be a realistic and reliable approach for comparing the influences of different factors on the hot spot temperature and the corresponding depth. Practical guidelines developed from the results of this study can be used for improved cement job design in field applications.

Improved High-Pressure, High-Temperature (HPHT) Materials Qualification Using Dissolved H2S Concentration as the Sour Service Scalable Metric

Gas phase H2S partial pressure (PH2S) is associated with sulfide stress cracking (SSC) and is routinely used as the “scalable” parameter to qualify materials for high-pressure, high-temperature (HPHT) wells. Candidate materials for HPHT wells routinely require ANSI/NACE MR0175/ISO 15156 compliance because a few mole ppm of H2S at high pressure may place the well beyond the 0.05 psia (0.3 kPa) sour service threshold. PH2S has been accepted historically as the scalable sour severity parameter. However, as the total pressure increases, the relationship between PH2S and the dissolved H2S concentration becomes nonlinear. This limits the robustness of PH2S as the sour severity metric. Thus, ISO 15156-1:2020 now permits the use of H2S fugacity (fH2S), H2S activity (aH2S), and H2S aqueous concentration (CH2S) as alternatives for sour testing. This recent revision is based on evidence that fH2S and CH2S each provide better correlations to SSC at elevated total pressures than PH2S. This paper will address the merits and challenges of using fH2S or CH2S to define sour severity: we argue that CH2S is a practical, experimentally verifiable approach, which can be used to validate ionic-equation of state frameworks used to characterize mildly sour HPHT environments.

Implementation of artificial intelligence and support vector machine learning to estimate the drilling fluid density in high-pressure high-temperature wells

One of the challenging conditions in wellbore management is high-pressure, high-temperature wells that apply large expenditures and maintenance costs to petroleum industries. In this regard, drilling fluid rheology and its crucial factors would help engineers to have a fundamental understanding of the most appropriate wellbore management. Moreover, it can help engineers to control the fluid loss phenomenon. This paper aimed to consider different artificial intelligence and machine learning models to predict the drilling fluid density and select the optimum model, which can be extended to field applications. These models are ANFIS (adaptive neuro-fuzzy inference system), PSO-ANFIS (particle swarm optimization-adaptive​ neuro-fuzzy inference system), LSSVM-GA (least square support vector machine-genetics algorithm), and RBF (radial basis function) algorithm were modeled in the programming era. In LSSVM-GA model, it is evident that the proper linear equation for the prediction of drilling fluid density is “y = 1.0041x + 0.0019” with the correlation factor of (R2=0.9966). Due to the advantages of RBF algorithm to other genetics algorithm, this algorithm was used in this part to predict the drilling fluid density. Therefore, it is evident that the proper linear equation for the prediction of drilling fluid density is “y = 1.0009x + 0.0034” with the correlation factor of (R2=0.9999). Consequently, RBF model was selected as the optimum method in drilling fluid prediction. Furthermore, there is a proper match with training and experimental data and the maximum deviation is about -0.006. In ANFIS algorithm, exponential derivation would be preferred to predict the drilling fluid density instead of linear equation. Consequently, the RBF model provide has a good agreement with the experimental drilling fluid density. It is indicated that the model have appropriate accuracy and validity with experimental data.

Influence of Cement Return Height on the Wellhead Uplift in Deep-Water High-Pressure-High-Temperature Wells.

In oil and gas production in deep-water high-pressure–high-temperature (HP–HT) wells, wellhead uplift may cause the seal failure of wellbore integrity. Aiming at the oil and gas production stage in deep-water HP–HT wells, we considered the influence of cement sheath cementation and developed a model for calculating the height of wellhead uplifts, and simulation experiments for wellhead uplifts were carried out under the condition of the double pipe string at different cement return heights and multilayer pipe string coupling cementing and noncementing based on a self-developed HP–HT wellhead uplift simulation device. The results show that the elongation of the double pipe string under the condition of a cement return height of 100% is reduced significantly compared with that under the condition of a cement return height of 50%. Also, the maximum elongation of the multilayer pipe string under the condition of coupling and cementing is significantly reduced compared with that under the condition of noncementing. These show that cement sealing has a binding effect on wellhead uplifts. The error between the calculated and the experimental results is less than 10%; thus, the model can be used to predict the wellhead uplift height under different working conditions and provide technical guidance for designing scientific measures to prevent wellhead uplifts.

Real-Time Prediction of Equivalent Circulation Density for Horizontal Wells Using Intelligent Machines.

Equivalent circulation density (ECD) is an important part of drilling fluid calculations. Analytical equations based on the conservation of mass and momentum are used to determine the ECD at various depths in the wellbore. However, these equations do not incorporate important factors that have a direct impact on the ECD, such as bottom-hole temperature, pipe rotation and eccentricity, and wellbore roughness. This work introduced different intelligent machines that could provide a real-time accurate estimation of the ECD for horizontal wells, namely, the support vector machine (SVM), random forests (RF), and a functional network (FN). Also, this study sheds light on how principal component analysis (PCA) can be used to reduce the dimensionality of a data set without loss of any important information. Actual field data of Well-1, including drilling surface parameters and ECD measurements, were collected from a 5–7/8 in. horizontal section to develop the models. The performance of the models was assessed in terms of root-mean-square error (RMSE) and coefficient of determination (R2). Then, the best model was validated using unseen data points of 1152 collected from Well-2. The results showed that the RF model outperformed the FN and SVM in predicting the ECD with an RMSE of 0.23 and R2 of 0.99 in the training set and with an RMSE of 0.42 and R2 of 0.99 in the testing set. Furthermore, the RF predicted the ECD in Well-2 with an RMSE of 0.35 and R2 of 0.95. The developed models will help the drilling crew to have a comprehensive view of the ECD while drilling high-pressure high-temperature wells and detect downhole operational issues such as poor hole cleaning, kicks, and formation losses in a timely manner. Furthermore, it will promote safer operation and improve the crew response time limit to prevent undesired events.

Enhancing Hematite-Based Invert Emulsion Mud Stability at High-Pressure High-Temperature Wells.

Drilling fluids have a crucial continued role in drilling a successful well; however, most of the drilling technical and operational challenges are incorporated with the drilling mud stability and properties. The solid particles settling in drilling mud that deteriorates its stability is a common issue encountered in high-pressure high-temperature (HPHT) conditions. This issue, known as solids sagging, may eventually result in stuck pipes, wellbore instability, and loss of circulation. The objective of this work is to introduce garamite to enhance the stability of hematite-based invert emulsion mud under HPHT situations. The used garamite and hematite weighting material were analyzed using X-ray fluorescence, scanning electron microscopy, and particle size distribution to identify their compositions, morphologies, and particle sizes. The effects of adding different concentrations of garamite (0.5, 1.0, 1.25, and 1.5 g) to the field formula of hematite-based invert emulsion mud were investigated. The mud density, stability, sagging tendency, rheology, viscoelasticity, and filtration properties were studied to formulate a stabilized and distinguished-performance drilling mud. The obtained results indicated that garamite did not change the mud density while enhancing the emulsion stability by increasing the electrical stability proportionally with the added garamite quantity. The sagging experiments showed that adding 1.25 g of garamite is sufficient to prevent the sagging problem in both static and dynamic conditions as it was enough to enforce the sag parameters into the safe range of sag performance indicators. This 1.25 g of garamite improved the yield point by 152% from 19 to 48 lb./100 ft2 with a slight increase in plastic viscosity from 14 cP for base mud to 18 cP and significant increase in the gelling strength and viscoelastic properties. Adding 1.25 g of garamite showed a slight enhancement in the filtration properties as the filtrate volume was reduced by 8% from 3.7 to 3.4 cm3 and the filter cake thickness has 16% reduction from 2.69 to 2.26 mm. As a result, a mud with distinguished performance, in terms of rheology, suspension, sag performance, and stability, was obtained. Hence, a basis for safely drilling the HPHT formations was delivered, which reduces the drilling cost by minimizing the nonproductive time.

Nanomaterial-Based Drilling Fluids for Exploitation of Unconventional Reservoirs: A Review

The world’s energy demand is steadily increasing where it has now become difficult for conventional hydrocarbon reservoir to meet levels of demand. Therefore, oil and gas companies are seeking novel ways to exploit and unlock the potential of unconventional resources. These resources include tight gas reservoirs, tight sandstone oil, oil and gas shales reservoirs, and high pressure high temperature (HPHT) wells. Drilling of HPHT wells and shale reservoirs has become more widespread in the global petroleum and natural gas industry. There is a current need to extend robust techniques beyond costly drilling and completion jobs, with the potential for exponential expansion. Drilling fluids and their additives are being customized in order to cater for HPHT well drilling issues. Certain conventional additives, e.g., filtrate loss additives, viscosifier additives, shale inhibitor, and shale stabilizer additives are not suitable in the HPHT environment, where they are consequently inappropriate for shale drilling. A better understanding of the selection of drilling fluids and additives for hydrocarbon water-sensitive reservoirs within HPHT environments can be achieved by identifying the challenges in conventional drilling fluids technology and their replacement with eco-friendly, cheaper, and multi-functional valuable products. In this regard, several laboratory-scale literatures have reported that nanomaterial has improved the properties of drilling fluids in the HPHT environment. This review critically evaluates nanomaterial utilization for improvement of rheological properties, filtrate loss, viscosity, and clay- and shale-inhibition at increasing temperature and pressures during the exploitation of hydrocarbons. The performance and potential of nanomaterials, which influence the nature of drilling fluid and its multi-benefits, is rarely reviewed in technical literature of water-based drilling fluid systems. Moreover, this review presented case studies of two HPHT fields and one HPHT basin, and compared their drilling fluid program for optimum selection of drilling fluid in HPHT environment.

Problems Analysis on Preparation of Oil and Gas Drilling Rig Installation for Next Operations Readiness after HPHT (High Pressure High Temperature) Well Operation

Oil and gas drilling is an activity designed to bring oil and gas resources into the surface of the earth using drilling rig. One of the characteristics of drilling wells is HPHT (High-Pressure High Temperature) condition, where this type of well can reach temperature of 150 °C and pressure of 15,000 psi. Due to these extreme conditions, the drilling rig installation often need to be serviced after it operates under HPHT condition before it can be operated again. The influences of HPHT wells conditions to the equipment component in the drilling operation systems are studied to find out the probable failures root cause that make the drilling rig break down and have significant Non-Productive Time (NPT) after operated on HPHT well. During this study, we found out that the root cause of the problem is failed to apply a detailed requirements in SOP and Operation Manual as a provision of drilling operation. The problems become more significant for the rig performance and its NPT thus affecting the overall drilling program and company revenue.

Applications of real-time chemical stratigraphy in support of the safe drilling of HPHT wells: examples from the Shearwater Field, Central North Sea, UK

X-ray fluorescence (XRF) data from a series of high-pressure–high-temperature (HPHT) wells drilled in the Shearwater Field, UK Continental Shelf (UKCS) are presented. These data comprise a total of 789 samples across a series of eight study wells. Chemical stratigraphy was utilized in conjunction with other geological data (i.e. well logs, ditch cutting descriptions and biostratigraphic analyses) to aid real-time stratigraphic placement. Systematic changes in geochemical composition were identified and used to build a chemostratigraphic zonation to aid delineation of lithostratigraphic boundaries. The application of chemical stratigraphy provided a valuable source of data, particularly through critical ‘drill-in-liner’ sections that are devoid of conventional logging while drilling (LWD) data. The identification of key geochemical zones and provision of a synthetic gamma-ray (Synth GR) profile were utilized in the placement of key casing points and identification of challenging top reservoir picks (Fulmar Formation). These data also served as a backup during LWD tool failure resulting from excessive temperatures. The successive addition of geochemical data accumulated with each well-site exercise permitted continued refinement of the zonation framework, with derived Synth GR profiles exhibiting an extremely close relationship with subsequent wireline logs. Chemical stratigraphic data are shown to be robust and repeatable within the Shearwater Field, enabling close stratigraphic control through critical sections, whilst also providing a low-cost backup in the event of conventional logging tool failures.

Deep Illustration for Loss of Circulation While Drilling

One of the most severe, costly, and time-consuming problems in the drilling operation is the loss of circulation. The drilling fluid accounts for 25–40% of the total cost of the drilling operation. Loss of the drilling fluid will increase the total cost of the drilling operation. Uncontrolled lost circulation of the drilling fluid may result in dangerous well control problem and in some cases the loss of the well. Fluid losses can occur in different formations such as natural fracture, induced fracture, unconsolidated, and cavernous and vugular. The objective of this paper is to deeply understand and illustrate different types of loss of circulation, techniques used to determine the loss rate, and detection of loss zones. In addition, losses mitigation techniques, different lost circulation materials (LCM), and the apparatus used to evaluate the available LCM will be explained in detail. The deep literature review illustrated that lost circulation costs 10–20% of the cost of drilling high-pressure high-temperature wells and 90% of these losses occur in fractured formations. The loss rate depends on the drilling fluid types, and it is generally higher in the case of water-based drilling fluid than in the case of oil-based drilling fluid. It is important to utilize an advanced measurement for losses with high frequency to detect the occurrences of lost circulation quickly and correctly. The measurements of flow rate (flow in and flow out) should be supported by additional data such as logging data, lost circulation information (loss rate and depth), mud properties, and surface drilling parameters. The preventive approach is the most efficient to mitigate the loss of circulation since the use of conventional LCM is not successful in most of the cases because of their limitations. It is vital to consider the size of different fractures encountered while drilling and modify the laboratory equipment to simulate this problem. Loss of circulation is affected by many parameters that are related to formation characterization, drilling parameters, fluid properties, and a lot of other known and unknown factors. Therefore, it is a challenge to predict the loss of circulation. To overcome such challenge, it is recommended to develop a new technique such as artificial intelligence to predict the thief zones and the loss rate by capturing the changes in the drilling mechanical parameters and the fluid properties.

Failure analysis for the cement with radial cracking in HPHT wells based on stress intensity factors

Wells are often cemented to provide zonal isolation and structural support through their entire service lifetime. Even if a cement sheath is set properly, it may inevitably contain small cracks which tend to propagate under harsh environmental and operational conditions. This work presents a mechanical model to predict the stress intensity factor at a radial crack tip in the cement under high pressure/high temperature (HPHT) conditions. The well section comprised of casing-cement-formation is modeled as three isotropic material domains under plane strain condition. The model calculates the stress field in the well section and estimates the stress intensity factor by a distributed dislocation technique. Two failure factors corresponding to the material strength criterion and fracture propagation criterion are introduced to evaluate the cement integrity. The influence of loading conditions and cement's mechanical and thermal properties on the failure factors is also investigated. The results indicate the predominant failure mode under HPHT conditions. The proposed model provides guidelines for the assessment of cement sheath integrity based on fracture mechanics.

Mitigation of barite sagging during the drilling of high-pressure high-temperature wells using an invert emulsion drilling fluid

Sagging of particles is one of the most critical issues when drilling deep oil and gas wells especially when the hole angle is greater than 30°. Accumulation of cuttings at the bottom of the hole around the drilling bit as a result of barite sagging cause severe problems such as the loss of well control. Temperature has a major effect on barite sagging so there is a need to develop a new drilling fluid formulation that can prevent barite sagging under different geometries of hole path and high temperatures (greater than 300 °F).The objective of this study is to evaluate the effect of using an organophilic phyllosilicate (OP) as an anti-sagging additive to prevent barite sagging in an invert emulsion drilling fluid (IEDF) at high temperature (350 °F). Static sag tests were conducted at vertical and inclined (45°) positions at 350 °F. Dynamic sag tests were performed at 120 °F. The second objective is to determine the optimum concentration of OP and evaluate the effect of the selected concentration on the rheological and filtration properties of the IEDF at 350 °F.The results show that the optimum amount of OP for preventing barite sagging at 350 °F in both vertical and inclined positions is 1.5 g. Adding 1.5 g of the OP prevents barite sagging under dynamic conditions and enhances the rheological properties by increasing the yield point plastic viscosity ratio. The OP enhances the suspension capability of the drilling fluid at low shear rate (3 rpm).

Risk Based Technology Qualification Method for HPHT Well

With the increasing demand for new technologies in HPHT (high pressure high temperature) wells, more and more attention has been paid to the system of technical qualifications. Most established norms, standards and recommended practices are written in prescribed formats, setting out methods, procedures and acceptance criteria for product design, manufacture and testing. However, established norms, standards or recommended practices may not adequately cover new technologies or applications. The technical qualification system is established in this paper, which can identify the potential failure modes and some activities in order to control the uncertainties and increase confidence of using new technology. A risk-based technical qualification system is used to assess non-traditional operations. It includes following seven main steps: system breakdown, technology assessment and classification, technical novelty, failure model and risk analysis, risk-based qualification planning and participation level development. The core of technical qualification system is to understand the ways and causes of system failure, and to carry out corresponding activities to provide evidence that the system will not fail. Through the technical identification process, the detailed equipment/operation specifications and identification requirements have been formulated. Different levels of participation are assigned for each eligibility activity, depending on the hazard and risk. It is proved that the application of the technical qualification principle in the systematic evaluation and control of the risks of new technologies or new applications is successful. In HPHT wells in particular, operators can move from a reactive approach to a proactive approach.

Enhancing the Stability of Invert Emulsion Drilling Fluid for Drilling in High-Pressure High-Temperature Conditions

Drilling in high-pressure high-temperature (HPHT) conditions is a challenging task. The drilling fluid should be designed to provide high density and stable rheological properties. Barite is the most common weighting material used to adjust the required fluid density. Barite settling, or sag, is a common issue in drilling HPHT wells. Barite sagging may cause many problems such as density variations, well-control problems, stuck pipe, downhole drilling fluid losses, or induced wellbore instability. This study assesses the effect of using a new copolymer (based on styrene and acrylic monomers) on the rheological properties and the stability of an invert emulsion drilling fluid, which can be used to drill HPHT wells. The main goal is to prevent the barite sagging issue, which is common in drilling HPHT wells. A sag test was performed under static (vertical and 45° incline) and dynamic conditions in order to evaluate the copolymer’s ability to enhance the suspension properties of the drilling fluid. In addition, the effect of this copolymer on the filtration properties was performed. The obtained results showed that adding the new copolymer with 1 lb/bbl concentration has no effect on the density and electrical stability. The sag issue was eliminated by adding 1 lb/bbl of the copolymer to the invert emulsion drilling fluid at a temperature >300 °F under static and dynamic conditions. Adding the copolymer enhanced the storage modulus by 290% and the gel strength by 50%, which demonstrated the power of the new copolymer to prevent the settling of the barite particles at a higher temperature. The 1 lb/bbl copolymer’s concentration reduced the filter cake thickness by 40% at 400 °F, which indicates the prevention of barite settling at high temperature.