Causes and Remedies of Drillstring Failures while Drilling Medium Radius Horizontal Wells (Field Study)

The underbalanced drilling of horizontal wells involves the injection of gas either with the drilling mud or via a separate string to that through which the drilling mud is injected. Nitrogen is generally used to prevent fire and explosion hazards during drilling; however, this adds considerably to the cost. Costs can be reduced by the replacement of nitrogen injection with normal air, de-oxygenated air or vitiated air (air/nitrogen mixture), but this increases the potential for flammable, or explosive, mixtures to be present in the wellbore and surface piping during underbalanced drilling. Safe operational ranges of oxygen-containing drilling mud mixtures can be determined if the flammability of the mixtures is known. Several studies were carried out to determine the flammability of these mixtures as a function of pressure to minimize the potential for downhole and surface explosion, and to set out the guidelines for safe underbalanced drilling operations of horizontal wells. A specially-designed apparatus was calibrated utilizing methane/air mixtures, then the ignition and the flammability characteristics of various mixtures of air, drilling mud and live oil were established over a range of pressures from atmospheric to 2,100 kPa at 21 ° C. Additional tests were carried out utilizing drilling mud, live oil, and either a nitrogen/air mixture (vitiated air) or de-oxygenated air. Flammability limits were determined for each series of experiments, and the results used to design the safety features for the underbalanced drilling of several horizontal wells. The field trials proved successful, and significant cost savings were realized. Introduction A growing demand for maximizing heavy oil production in a cost-effective manner has led to the development of a variety of novel technologies. One such technology involves the drilling of wells employing underbalanced or near-balanced drilling procedures in order to minimize the possibility of formation damage due to drilling fluid invasion. There is a potential for flammable, or explosive, mixtures to be present in the wellbore and surface piping during this type of drilling operation. In underbalanced drilling, normal air or an oxygen-containing gas (usually vitiated air, which is air mixed with nitrogen, or de-oxygenated air, which is air with some of the oxygen removed) is injected and/or circulated with the drilling mud to reduce the potential for formation damage due to whole mud, fluid filtrate and solids invasion into the hydrocarbon-bearing formation. The study presented in this paper was performed to determine the safe conditions for underbalanced drilling of Husky Wainwright Well 15B-31-44-4 W4 using compressed air and liquid nitrogen. This well, located in the Camrose reservoir, which is a fractured vugular carbonate at 690 m TVD, was proposed to be drilled 550 m laterally(1). The main objectives of this investigation were:To establish the flammability of mixtures of air, live heavy oil and drilling mud as a function of pressure, andTo determine the optimum composition of vitiated air (nitrogen- air mixture), based on the flammability data, in order to minimize the potential for ignition or explosion during the underbalanced drilling operation.

A compositional equation-of-state simulator has been used to make comparisons of CO2 process performance with several combinations of horizontal and vertical wells and various alternative reservoir descriptions. This is the first time that the performance of CO2 flooding using horizontal wells has been reported. We have used the reservoir and fluid properties of an actual West Texas carbonate reservoir that is currently being waterflooded. The phase behavior and properties of the CO2 used in these simulations are typical of those of multiple-contact- miscible field conditions of West Texas. A layered-type reservoir description was initially used to investigate the effect of water- altemating-gas (WAG) ratio with various combinations of well types. We then investigated the effect of vertical permeability, length, and position of the horizontal injector using the same reservoir description and a horizontal injector-vertical producer combination. Similar investigations using an unconditioned stochastic permeability field having a Dykstra Parsons coefficient (VDP) of 0.81 were made. Our final three-phase flow simulation was performed using a stochastic permeability field conditioned with core data. Since three nonaqueous phases can occur at low temperatures typical of West Texas floods resulting in up to four-phase flow with mobile water, we investigated the impact of four-phase flow in one of these simulations. This is the first time that three-dimensional, four-phase flow reservoir simulations have been reported with either vertical or horizontal wells.

With the advent of rotary steerable systems, successful drilling of horizontal wells became a reality in the oilfield. Even though the costs are much higher than for a vertical well, the production factor can be enhanced multiple times, making it very attractive. However, the drilling of horizontal wells is extremely difficult, mainly due to lateral lithological discontinuities of the reservoirs and seismic uncertainties. To overcome such challenge, Well Placement technique is used to interactively position the well based on geological and seismic criteria together with LWD measurements. While covering drilling, geology and geophysics, most Well Placement approaches rarely consider reservoir engineering aspects. Therefore the project objectives were to evaluate the impacts in the productivity generated by the geometrical changes in the trajectory through numerical reservoir simulation. The research work was then divided into two parts. The first one was the creation of a representative 3D synthetic reservoir model where numerical simulations were applied for each trajectory design. A detailed sensitivity analysis was made by comparing the results among the different trajectory cases in order to identify the relationship between well positioning and its productivity response. The second part consisted of a real geosteering case study. Around both planned and executed wellbores, it was created a detailed reservoir model enhanced by LWD inputs. To increase prediction accuracy, a refined gridding with variable cell size technique was applied to enhance pressure and saturation sensitivity. The level of precision was improved by using LWD measurements, such as the most precise formation pressure, the permeability near wellbore and the remote boundary mapper technology that provided a detailed reservoir structure based on formation resistivity contrast. Afterwards, reservoir simulations were performed in order to evaluate the impacts caused by the trajectory variations, demonstrating the expected productivity results versus the actual ones. The work delivers a novel ability to construct optimal horizontal wells not only by including conventional Well Placement technique, using geological and geophysical criteria, but also by adding into the workflow an advanced numerical simulation approach. Such integration allows the operator to predict the impacts on the productivity as the trajectory is being changed, and the actual reservoir geometry and its properties are determined by LWD measurements. It also reinforces that predictions related to reservoir productivity should not only be performed on planning stage, but most importantly during or right after well execution using relevant inputs, such as the actual well path, LWD logs, and formation pressure measurements, which all combined provides an enhanced reservoir model, and so a more accurate forecast analysis.

REVITALIZATION OF A MATURE VOLATILE AND CONDENSATE OIL RESERVOIR USING HORIZONTAL WELLS. Abstract The great interest shown in optimizing the exploitation of reservoirs, in the last two decades through the drilling of horizontal wells, has been the best evidence of the potential of this technology. Significant increments in production rates and recoveries have been reported even in oil fields considered uneconomic. In this paper, the revitalization of the RG-14, COEF reservoir in the Santa Rosa Field by means of horizontal wells is analyzed. This reservoir is the most important mature reservoir producing volatile oil and condensate in Eastern Venezuela. The RG-14, COEF reservoir started its production in April of 1950, having been subjected to gas injection since 1955. Depth of the reservoir varies from 6560 ft subsea at the crest of the dome to 11150 ft at the flank. Presently, gas channeling and the subsequent entrampment of oil in undrained areas limit the recovery of 14.5 MMBls of remaining reserves. Consequently, the drilling of horizontal wells is a potential option to minimize gas channeling and maximize the drainage area, increasing crude production, final recovery and the economic feasibility of the project, at the same time. This paper presents the integration of geological, reservoir and production studies to define undrained flow units, the selection of objective areas for three horizontal wells, the characterization of fluids, production forecast by means of pseudocompositional simulation and an economic analysis. A Peng-Robinson equation-of-state was used, to characterize both gas condensate and black oil. The simulation studies were performed only in the areas were horizontal wells are proposed, in order to compare them with vertical wells. Results indicate that it is feasible to reactivate production from the RG-14, COEF reservoir in the Santa Rosa Field from the current 567 STBD to a level of 2620 STBD through the drilling of three horizontal wells. Introduction In Corpoven's Anaco and San Tome traditional areas in the Eastern Venezuela Basin, there are about 134 mature fields of condensates and medium and light oil which still have reserves of between 50 and 300 million barrels. Secondary recovery processes (gas injection) used in these fields for the last 30 years have permitted the extraction of 75% of the initial estimated reserves. However, a good portion of the remaining reserves are still trapped due to inefficient drainage and preferential channeling of injected gas and/or water in the reservoirs subjected to a pressure maintenance. Due to these circumstances, the use of the horizontal drilling technology is required in order to maximize the contact with undrained areas and so reduce the water and/or gas coning. Consequently, this procedure will permit the acceleration of the final recovery of reservoirs. P. 231

This scientific work summarizes the experience of drilling horizontal wells at abnormally high reservoir pressures in the Western part of Turkmenistan. The article describes in detail the choice of the layout of the bottom-hole assembly (BHA), drilling methods, the area of the angle set and the stabilization interval of the zenith angle, and also notes the importance of the quality of drilling mud when drilling horizontal wells. The work performed proves that drilling of horizontal wells is possible both at an early and late stage of field development and their drilling should be provided for when creating technological development schemes at the level of the field development project. Such work will find application for drilling deep horizontal wells with abnormally high reservoir pressures and will lead to an increase in hydrocarbon production, as well as organizational restructuring of horizontal drilling on a scientific basis. Keywords: oil recovery; geological structure; deviation; zenith angle; borehole; communication channel.

The increasing complexity and higher drilling cost of horizontal wells demand extensive research on software development for the analysis of drilling data in real-time. In extended reach drilling, the downhole weight on bit (WOB) differs from the surface seen WOB (obtained from on an off bottom hookload difference reading) due to the friction caused by drill string movement and rotation in the wellbore. The torque and drag analysis module of a user-friendly real-time software, Intelligent Drilling Advisory system (IDAs) can estimate friction coefficient and the effective downhole WOB while drilling. IDAs uses a 3-dimensional wellbore friction model for the analysis. Based on this model the forces applied on a drill string element are buoyed weight, axial tension, friction force and normal force perpendicular to the contact surface of the wellbore. The industry standard protocol, WITSML (Wellsite Information Transfer Standard Markup Language) is used to conduct transfer of drilling data between IDAs and the onsite or remote WITSML drilling data server. IDAs retrieves real-time drilling data such as surface hookload, pump pressure, rotary RPM and surface WOB from the data servers. The survey data measurement for azimuth and inclination versus depth along with the retrieved drilling data, are used to do the analysis in different drilling modes, such as lowering or tripping in and drilling. For extensive analysis the software can investigate the sensitivity of friction coefficient and downhole WOB on user-defined drill string element lengths. The torque and drag analysis module, as well as the real-time software, IDAs has been successfully tested and verified with field data from horizontal wells drilled in Western Canada. In the lowering mode of drilling process, the software estimates the overall friction coefficient when the drill bit is off bottom. The downhole WOB estimated by the software is less than the surface measurement that the drillers used during drilling. The study revealed verification of the software by comparing the estimated downhole WOB with the downhole WOB recorded using a downhole measuring tool.

The prediction and optimization of the rate of penetration (ROP) for horizontal wells are more complicated than for vertical wells, but most of the current ROP prediction studies are for vertical wells, which cannot be adapted to the complex drilling characteristics of horizontal wells. To this end, this paper proposes a data knowledge dual-driven horizontal well ROP prediction method. Firstly, the drilling characteristics of horizontal wells are analyzed, showing that the horizontal wells ROP prediction model cannot be modeled using surface measurement data; secondly, based on the analysis of horizontal well drilling characteristics, a physical model-based horizontal well ROP modeling data pre-processing method is proposed by introducing the drag and torque model. Finally, a data knowledge dual-driven horizontal well ROP prediction method is proposed in conjunction with data-driven algorithms. The proposed horizontal well ROP prediction method is applied to the A1~A4 wells in the Sichuan area. Compared with the conventional data-driven ROP prediction method, the prediction accuracy of this method is improved by 30%. The proposed method can provide a basis for the intelligent optimization and management of ROP during the drilling of horizontal wells.

A new multi-disciplinary integrated steering technology for horizontal wells in tight sandstone gas reservoirs: A case study of the Ordos Basin

Recent advancements in technologies pertaining to the drilling of horizontal well and multistage hydraulic fracturing have made it possible to get significant hydrocarbon production even from extremely low permeability formations. Evaluation of the economics is becoming increasingly essential before committing to any big investment. In this scenario, production forecasting plays an important role by not only evaluating the economic feasibility of the project, but also helping in the selection of the most optimal development strategy (Shivam et al. 2017). This paper presents an integrated workflow that has been applied in one of unconventional gas bearing formation which is a common reservoir in Egypt’s Western Desert. It does form a reasonable reservoir size and spread over several hundred sq.kms. It is characterized as a low permeability carbonate (0.2 mD) in soft chalk reservoir. Many vertical wells were drilled and completed in the appraisal program for collecting the required data to evaluate reservoir performance before the completion of horizontals, but economical target production rates could not be achieved. To help optimize field development strategy and further increase production, a full field development plan was initiated by drilling horizontal wells with multistage fracturing stimulation. Horizontal pilot wells were drilled and completed along and perpendicular the minimum horizontal in-situ stress direction to enable both transverse and longitudinal fracture propagation patterns for the best completion option. The objective of this paper is to present an integrated approach to evaluate an unconventional resource, improve the completion efficiency, improving the future fracture design and understand the productivity enhancement specifically in the Western Desert of Egypt, through a detailed analysis of production data and pressure transient analysis. The conclusions from this study will help in evaluating the behavior of multistage fractured horizontal with different fracture azimuth direction and generate production forecast for different development scenarios. The stimulated rock volume estimation will help in planning the future fracture design to increase well EUR. The proposed workflow and lessons learned formed the basis for subsequent development of various unconventional plays in Egypt.

The drilling of horizontal wells to improve oil and gas recovery and productivity has quickly become one of the most important and promising technology of the oil industry. This is reflected by the considerable number of technical papers published on this subject. Although these papers have been covered a great deal of aspects of horizontal drilling, one important subject remains almost unexplored: the well pressure control. The scope of this paper is to show important facets of the well control for horizontal wells, especially for deepwater ones, and to highlight some design and operational aspects to make the horizontal drilling safer. One important point analyzed in this paper was the pressure behavior inside a horizontal wellbore during a gas kick removal process. For this analysis, a numerical simulator of a gas kick based on the unsteady state flow of a two-phase mixture (gas and mud) has been developed and used to predict pressure at any point of the wellbore-choke line system. It has also been used to compute and to analyze the kick tolerance during the gas kick circulation process. Some other relevant points of the well control operation for horizontal wells that differ from those for vertical wells were also investigated.They include:swabbing effect when tripping out of the hole,shut-in pressures and pit gain,drillpipe pressure schedule during the kick removal process,and mud density design.

The Pekisko formation in the Bigoray field in central Alberta is an oil-bearing dual permeability/porosity dolomite. A portion of the reservoir has permeabilities in the range of 1-2 Darcy and porosities approaching 25-30% while the rest of the reservoir features 10-30 millidarcy average permeabilities, 8-12% porosities and low initial water saturation. It is suspected that both rock types contribute to the flow of oil. Drilling of horizontal wells in the Pekisko formation offers technological challenges in terms of field development and formation impairment. Damage mechanisms for the two rock types are expected to be different yet need to be addressed in one drilling fluid system. Open hole completion/stimulation to repair any formation damage and the avoidance of underlying water adds to the drilling challenges. This paper describes the results of laboratory formation damage studies to both identify damage mechanisms and evaluate which drilling fluid system to be used in the horizontal well section. The higher permeability/porosity dolomite core plugs were damaged by solids plugging while aqueous phase trapping and solids plugging were responsible for damage in the lower quality rock. A total of eight horizontal wells have been drilled in the field as of December 1997. The horizontal wells were drilled with three types of drilling fluids: oil, oil-soluble resin and a carbonate bridging system containing an aqueous phase trap reduction agent. The horizontal wells drilled with the carbonate/aqueous phase trap drilling fluid system had better oil production and less water than the wells drilled with the other drilling fluids. Discussion will also focus on stimulation of those horizontal wells that were damaged in the drilling process. P. 161

Horizontal well drilling is a highly effective way to develop marine gas hydrate. During the drilling of horizontal wells in the marine gas hydrate layer, hydrate particles and cutting particles will migrate with the drilling fluid in the horizontal annulus. The gravity of cuttings is easy to deposit in the horizontal section, leading to the accumulation of cuttings. Then, a cuttings bed will be formed, which is not beneficial to bring up cuttings and results in the decrease of wellbore purification ability. Then the extended capability of the horizontal well will be restricted and the friction torque of the drilling tool will increase, which may cause blockage of the wellbore in severe cases. Therefore, this paper establishes geometric models of different hole enlargement ways: right-angle expansion, 45-degree angle expansion, and arc expanding. The critical velocity of carrying rock plates are obtained by EDEM and FLUENT coupling simulation in different hydrate abundance, different hydrate-cuttings particle sizes and different drilling fluid density. Then, the effects of hole enlargement way, particle size, hydrate abundance and drilling fluid density on rock carrying capacity are analyzed by utilizing an orthogonal test method. Simulation results show that: the critical flow velocity required for carrying cuttings increases with the increase of the particle size of the hydrate-cuttings particle when the hydrate abundance is constant. The critical flow velocity decreases with the increase of drilling fluid density, the critical flow velocity carrying cuttings decreases with the increase of hydrate abundance when the density of the drilling fluid is constant. Orthogonal test method was used to evaluate the influence of various factors on rock carrying capacity: hydrate-cuttings particle size > hole enlargement way > hydrate abundance > drilling fluid density. This study provides an early technical support for the construction parameter optimization and well safety control of horizontal well exploitation models in a marine natural gas hydrate reservoir.

Summary A horizontal well trajectory targeting multi-layer reservoirs in a brownfield with uneven fluid contact movements due to a long production history was generally developed from 3D Reservoir Model. This paper aims to showcase the recent case study of an application of High-Definition Deterministic Inversion that has successfully mitigated these fluid contact and structure dip uncertainties, resulting in the successful drilling a challenging horizontal well. Reservoir properties and logs from nearby offset wells were used as input for inversion modelling, prior to drilling. Several cases of depth structure and fluid contact scenarios were incorporated into a pre-modeling workflow to capture all possible well-landing elevation outcomes. High-Definition Deterministic Inversion methods were used to optimize the trajectory during the pre-drill planning as well as in real-time, during the drilling of horizontal well. These models were used from the first penetration into the target reservoir (near to landing point), while drilling the horizontal section in the first target sand and thin shale layers, then while chasing and landing in the next target sand and finally while drilling up to the well’s total depth. The result and information from this inversion was incorporated into the 3D reservoir model to identify future potential re-development opportunities.

The Mangala Field is the largest discovered oil field in the Barmer Basin of Rajasthan, India with a STOIIP of over 1 billion barrels contained in stacked clastic fluvial reservoirs of the Fatehgarh Formation (Compton, 2009). The Fatehgarh Formation is divided into two broad reservoir units. The upper Fatehgarh (average net to gross ~40%), consists of low sinuosity channel system sands, and the lower Fatehgarh, consists of 30m to 40m of stacked braided fluvial sands (average net to gross ~90%) having resistivity of more than 5000 ohm-m. The flow simulation model demonstrated that horizontal wells are the best way to develop the lower Fatehgarh reservoirs. The key challenges in successful drilling of horizontal wells are the uncertainty in formation top, the position of field bounding fault, presence of gravitational collapse faults, and navigating within the ultra-high resistive reservoirs. Offset well correlation, high resolution sampling of drill cuttings, close monitoring of grain size variations and real-time density image log analyses were used to overcome the challenge of landing the well in target reservoir zone at desired borehole inclination. After landing the well, the strategy was to build borehole angle to ~90° and geosteer within the reservoir zone. The directional resistivity tool used is sensitive to resistivity contrasts providing an early indication of non-reservoir ahead of bit. However the ultra-high resistive reservoirs limited the boundary detection capability of this tool thus reducing the reaction time to take corrective measures. The true stratigraphic position (TSP) of the wellbore was also continuously monitored using gamma ray correlation. Eleven horizontal wells have been drilled in the Mangala field using various data integration approach. Accurate placement of wells in the best part of the reservoir, avoiding interlayer mudstones, has resulted in more than 90% reservoir contact and an average production of ~10000 bopd/well.

The article discusses the issue of drilling multilateral horizontal wells and provides a brief history of its development. Data were provided on the selection of the location of the multilateral horizontal well, drilling the main wellbore and determining the depth for running the сasing strings. This paper also analyzes the selection of lateral wellbore penetration depth, the importance of drilling multilateral horizontal wells and their application for the first time in the shelf water of South Caspian Basin, at the Western Absheron field, Well 19. Keywords: multilateral wells; drilling of horizontal wells; petrophysical models; drilling of main and lateral wellbores.