Slimhole Well Kill: A Modified Conventional Approach

Frictional pressure loss of drilling fluids in a fully eccentric annulus

Controlling the annular frictional pressure losses is important in order to drill safely with overpressure without fracturing the formation. To predict these pressure losses, however, is not straightforward. First of all, the pressure losses depend on the annulus eccentricity. Moving the drillstring to the wall generates a wider flow channel in part of the annulus which reduces the frictional pressure losses significantly. The drillstring motion itself also affects the pressure loss significantly. The drillstring rotation, even for fairly small rotation rates, creates unstable flow and sometimes turbulence in the annulus even without axial flow. Transversal motion of the drillstring creates vortices that destabilize the flow. Consequently, the annular frictional pressure loss is increased even though the drilling fluid becomes thinner because of added shear rate. Naturally, the rheological properties of the drilling fluid play an important role. These rheological properties include more properties than the viscosity as measured by API procedures. It is impossible to use the same frictional pressure loss model for water based and oil based drilling fluids even if their viscosity profile is equal because of the different ways these fluids build viscosity. Water based drilling fluids are normally constructed as a polymer solution while the oil based are combinations of emulsions and dispersions. Furthermore, within both water based and oil based drilling fluids there are functional differences. These differences may be sufficiently large to require different models for two water based drilling fluids built with different types of polymers. In addition to these phenomena washouts and tool joints will create localised pressure losses. These localised pressure losses will again be coupled with the rheological properties of the drilling fluids. In this paper, all the above mentioned phenomena and their consequences for annular pressure losses will be discussed in detail. North Sea field data is used as an example. It is not straightforward to build general annular pressure loss models. This argument is based on flow stability analysis and the consequences of using drilling fluids with different rheological properties. These different rheological properties include shear dependent viscosity, elongational viscosity and other viscoelastic properties.

Helical flow of non-Newtonian fluids in concentric and eccentric annuli is of great interest in oil/gas well drilling. Experimental results and field measurements demonstrated that frictional pressure loss in the annulus can be affected substantially by the rotation of the drillpipe. Previous studies indicated that the influence of pipe rotation on annular friction pressure loss is affected by fluid properties, flow regime, annular diameter ratio and eccentricity.This article presents results of in-depth experimental and theoretical investigations conducted on the flow of yield power law (Herschel Buckley) fluids in concentric and eccentric annuli with pipe rotation. The aim of this study is to develop a reliable hydraulic model that accounts for the effect of pipe rotation in annular pressure loss calculations.Extensive flow experiments with polymer-based fluids were carried out using a newly developed testing facility. Four different annular geometries have been considered for the investigation. Five different formulations of test fluid were prepared by varying concentrations of Xanthan Gum (XG) and Polyanionic Cellulose (PAC) for each annular geometry. Accurate fluid characterization was made using the horizontal pipe sections and a rotational viscometer. In addition to the experimental work, theoretical analysis of helical flows in concentric annuli was carried out.Experimental results indicate the strong presence of shear thinning and inertial effects when inner pipe rotates. In highly eccentric annuli, inertial effects dominate the phenomenon of shear thinning and result in increased pressure loss as the speed increases. Inertial effects can be generated due eccentricity and/or geometric irregularities of the annulus that substantially influence the velocity field as the pipe rotates. The experimental measurements and theoretical analysis presented in this investigation are very useful for hydraulic program optimization and well control, particularly for managed pressure drilling (MPD) operations.

The migration, deposition, and retention of coal fines carried by drainage fluids in gas production wells of coalbed methane (CBM) wells severely restrict CBM production. This study establishes a numerical model to investigate the coupled gas–liquid–coal fines seepage law in the horizontal wellbore annulus during gas production stage using a combination of computational fluid dynamics and the discrete element method. Results reveal that in an annular wellbore with an eccentricity of 0.06, the seepage space in the lower part of the annulus is narrow, making it difficult for the fluid to carry coal fines and discharge them, resulting in a deposition pattern characterized by “more deposition and less discharge.” In contrast, in an annular wellbore with an eccentricity of 0.08, the wide space in the upper part of the annulus forms a stable advantageous seepage channel for coal fine migration, resulting in a pattern of “more deposition and more discharge.” When the three-phase coupled seepage is stable, the coal fine discharge rate of the wellbore with an eccentricity of 0.06 is 38.62% lower than that of the concentric annulus, and when the eccentricity is 0.08, the discharge rate is 75.66% higher than that of the concentric annulus. Coal fines in concentric annular wellbores are evenly and dispersedly distributed at the bottom, while those in eccentric annular wellbores form concentrated agglomerations, creating a distinct particle bed. Additionally, the flow velocity and annular pressure loss in the lower part of the wellbore are higher, and the pressure loss is inversely proportional to the gas content. Higher gas content results in increased particle collisions, greater energy loss, and reduced particle mobility, making coal fines more likely to get deposited and difficult to migrate and discharge from the wellbore. Water primarily drives particle transport, while gas introduces disturbances that complicate the flow dynamics. Reasonably adjusting the eccentricity of the annulus in the field and adapting pressure control measures according to the gas production stages can effectively promote the discharge of coal fines to increase gas production.

The fluid-loss behavior of cement slurries against permeable formations and its relationship to interzonal fluid migration have been investigated. Static fluid-loss testing, designed to simulate cement placed in a wellbore, has shown that the cement fluid-loss rate through a deposited mud filter cake decreases with time. This decrease in fluid-loss rate is dependent upon the designed fluid-loss properties of the cement slurry, and significantly influences the loss of hydrostatic pressure required to control formation fluids. Once the pressure starts to decay, formation fluids can potentially enter the wellbore causing ineffective zonal isolation and, in some cases, gas migration to the surface. The mechanism described indicates that hydrostatic pressure is initially transmitted after cement placement. During this period, fluid loss to the surrounding formation is compensated for by an equal decrease in slurry volume. The resulting changes in the solid-to-water ratio and gelation properties coupled with the growth of the cement filter cake cause the pressure against the formation to eventually decrease. The rate of pressure decrease is dependent upon the fluid-loss rate and the slurry's compressibility. Once the pressure approaches the formation pressure, interzonal fluid flow through the cement slurry occurs with its rate initially governed by the cement fluid-loss rate. Several correlations have been made relating fluid loss to the pressure profile after wellbore completion. The results suggest that an API fluid-loss requirement of 100 mL/30 min, which may be sufficient during cement placement, is actually too high when consideration is given to the fluid loss that occurs after cement placement. Sufficient delays in the loss of pressure are obtained for an API fluid-loss requirement in the range of 10 to 30 mL/30 min with the actual value dependent upon wellbore geometry, overbalance pressure, mud fluid-loss properties and cement slurry design.

SummaryHorizontal wells are designed to have smooth (straight), curved, and lateral sections. However, the actual drilled path usually suffers from unwanted undulations from the planned well trajectory known as wellbore tortuosity. Wellbore tortuosity can slow the drilling penetration rate, aggravate drillstring vibration and buckling, complicate the casing and cement job, and lead to inaccurate wellbore position. This paper presents a validated computational fluid dynamics (CFD) model to investigate the impact of wellbore tortuosity on hole cleaning. The Eulerian-Eulerian approach is used to simulate solid-liquid laminar flow in annular geometry using polyhedral mesh. Then, the impact of wellbore tortuosity on cuttings accumulation, annular pressure loss, and fluid velocity was investigated and compared with the flow behavior in a straight horizontal well. A parametric analysis of spiral period length, spiral amplitude, drillstring rotation, flow rate, annular eccentricity, drilling rate of penetration (ROP), and cuttings size was conducted to assess their influence on cuttings transport in spiral tortuous holes and their relative magnitude to other design or operating factors.Simulation results show that polyhedral mesh is an optimum meshing technique for spiral profile geometry. Wellbore tortuosity aggravates hole cleaning in lateral sections based on the length of the spiral period and/or the spiral amplitude. Reduction in cuttings velocity was observed in the top part of the spiral geometry (crest), causing large deposition of cuttings in this area compared to the spiral lower part (trough). Drillstring rotation from 0 to 200 rev/min is the critical range for efficient hole cleaning in spiral geometry. Cuttings size can improve cuttings accumulation if the particle size is larger than the viscous layer located near the bed velocity profile. The drilling ROP and annular eccentricity aggravate cuttings accumulation and bed deposition in a spiral hole, similar to what is normally observed in straight horizontal wells.

This paper considers the effect of excessive total pressure losses for heat transfer problems in fluid flows with a high circumferential swirl component. At the Institute of Jet Propulsion and Turbomachinery at RWTH Aachen University, a novel gas generator concept is under research. This design avoids some disadvantages of small gas turbines and uses a rotating combustion chamber. During the pre-design of the rotating combustion chamber using CFD tools, unexpected high total pressure losses were detected. To analyze this unknown phenomenon, a gas-dynamic model of the rotating combustion chamber has been developed to explain the unexpected high Rayleigh pressure losses. The derivation of the gas-dynamic model, the physical phenomenon related to the high total pressure losses in high-swirl combustion, the influencing factors, as well as thermodynamic interpretation of the Rayleigh pressure losses, are presented in this paper. The results presented here are of possible interest for a wide range of applications, since these fundamental findings can be transferred to all heat transfer problems in fluid flows with a high circumferential swirl component.

Porous materials are used in engineering and industry due to their heat transmission qualities. This study examined forced convection flow through an annular tube packed with sphere balls of various materials and sizes using numerical analysis. The sphere balls were permeable. Ceramic, plastic, and steel with spherical diameters of 3, 5, and 6 and porosity of 0.4 were tested for heat dissipated and fluid flow. Also, test the impact of steel balls of diameter 6mm with 0.6 and 0.8 porosity. The numerical simulation results are used to analyze the forced convection and fluid flow parameters of a three-dimensional annular tube with continuous heat flux in the Reynold number range (5000-14000). Steel balls had an 80% higher heat transfer coefficient than annular tubes without porous mediums. The simulation showed that inserting the porous media increased annular tube pressure loss. The maximum heat transfer coefficient improved by about 80% when the spherical diameter is 3 mm. Also, the result illustrated the heat transfer coefficient of steel balls Increased by about 79%, 69%, and 49%, with 0.4, 0.6, and 0.8 respectively

Both Saudi Aramco and Total Indonesia found benefits in selecting 4 in. drill pipe with streamlined double shoulder connections for the drilling of wells, for which the 3 1/2 in. drill pipe was unsuitable. Although dealing with different environments and applications, these benefits can be summarized in "successfully drilling longer slim holes with a drill string having enhanced torsional, tensile and hydraulic characteristics at a lower overall cost". For the Saudi Aramco QTF field, Extended Reach Drilling (ERD) was required with the objective to deliver pay zones located at measured depths of 18,000 ft (for the 1,500 HP rigs) and 25,000 ft (for the 2,000 HP rigs). These depths correspond to step outs ranging from 13,000 ft to 20,000 ft respectively from the drill site. For its Kalimantan field, Total was in a need of higher torsional capacity and also an improvement of the hydraulic characteristics of the drill string. Selecting a larger size of pipe was the retained option against an upgrade of the rig pump installation. The casing and drilling program remained unchanged with the drilling of a 6 in. hole after setting the 7 in. casing, adding a constraint for fishability of the string. In both cases, fishability and torque objectives made the selection of the appropriate connection essential. The selected double shouldered connection maintained a tool joint outside diameter similar to standard 3 1/2 in. drill pipe tool joints, that maintains fishing ability of the 4 in. pipe, in casing and open hole, despite the pipe size increase. The streamline connection design provides 22,000 ft-lb working torque, an outside diameter of 4–7/8 in. and an oversized internal bore that promotes hydraulic efficiency. Other important improvements include considerable gain in pipe resistance under buckling loads, increased available pressure at the bit, better telemetry for the MWD and LWD tools and improved hole cleaning and rate of penetration. Introduction Drilling deeper, slim hole wells has revealed limitations of 3 1/2 in. drill pipe traditionally used to drill the 6 to 6–1/4 in. hole sections. The level of torque that API rotary shoulder, as well as first generation double shoulder connections, can deliver does not match the new requirements for these deeper drilling programs. This increase in drill string length also puts an additional constraint on hydraulic performance. This encouraged drilling engineers to re-evaluate the drill string design requirements and select a new configuration of pipe that would respond to these new requirements. This paper addresses these pipe and connection design considerations and provides two case histories showing the benefits that were realized from using this new drill pipe design configuration. Over 1,400,000 ft of this pipe has been built to date and is in service all over the world. It is also important to mention that this new drill pipe arrangement can also be used for drilling upper hole sections eliminating the need for a string 5 in. drill pipe in many applications. Streamlined Double Shoulder Connections for 4 in. Drill Pipe There has been increasing requirements for drill pipe with improved hydraulic performance and mechanical properties to replace 3–1/2 in. drill pipe traditionally used in slim-hole drilling.

Periodic sound reduction at some frequencies and high pressure loss could be considered as the disadvantages of simple expansion silencers. Generally, reactive elements are applied in silencers to optimize their acoustic and aerodynamic performance. In this paper, we were going to investigate the combined and independent effects of reactive elements, baffle and extended tubes at the inlet and outlet of simple expansion silencer, on the acoustic performance and pressure loss of simple expansion silencer. Firstly, simple expansion silencer dimensions were determined based on theoretical calculations to attenuate the noise by 10 dB. Secondly, the simulation was performed using COMSOL acoustical module software based on finite element method to predict silencer sound transmission loss and pressure loss, respectively, before and after adding reactive elements. Then, according to ISO7235, ISO3744 and ISO3746 standards noise insertion loss of various silencers under study was measured in a free field and in the following that silencers pressure loss evaluated. Finally, the predicted results with the software were compared with the experimental ones. The addition of the extended tubes increased the transmission loss and insertion loss at low and medium frequencies and mitigated the pressure loss of the silencer compared to the simple expansion silencer. The baffle increased the transmission loss curve in the medium frequencies compared to the simple expansion silencer. The combination of baffle and extended tube elements caused an extraordinary increase in insertion loss and transmission loss at the medium frequencies and a decrease in pressure loss. It could be concluded from the present study that using extended tube might be probably the best choice to reduce pressure loss and increase the acoustic performance of simple expansion silencer at low and medium frequencies and what's more is that the best acoustic performance in medium frequencies can be achieved by using a combination of baffle and extended tube.

An abnormally high pressure formation caused the loss of a number of Dukhan Khuff Gas (DKG) wells. The Sudair formation has always been considered normally pressured throughout the Dukhan Khuff gas field area. However, this case study supports the author's hypothesis that, contrary to that belief, Sudair can be abnormally pressured. Two DKG wells A and B were the subject of this case study. These wells experienced loss of integrity due to high annuli pressures and were recently worked over. The author's abnormally high pressure zone hypothesis is based on actual real data from both of these wells. DKG wells were drilled more than thirty years ago. All 28 wells were drilled through the Sudair formation without any pressure or well control issues. However, at some point in time, most of these wells developed annulus pressure in one or more of their annuli. How did that happen? To answer this question, the author searched other operator's experiences in the area. The search pointed out that the Sudair formation is not always normally pressured; it can also be abnormally pressured. We have seen reports of Sudair high formation pressure associated with high rate salt water flow, high rate gas flow and in occasions very low rate salt water flow. While the high rate flows are detectable, it's the very low rate high pressure salt water flow that is almost impossible to detect. Another finding is that the Sudair formation pressures are neither equal nor uniform over a large area but rather different and localized. What could we have done differently thirty-five years ago? The answer is simply no thing because we did not have the knowledge and knowhow of today. However, there are lessons to be learnt, t's to be crossed and i's to be dotted. Introduction Dukhan Khuff is a non associated high pressure gas reservoir. The field was developed in the late 1970s to supply fuel gas to the power generation plants. Because of the high pressure, Khuff Gas wells were designed and constructed according to the highest applicable standard at the time. However, most of these wells developed annulus pressure in one or more of their annuli. DKG wells crossed a number of oil and gas bearing formations that made it almost impossible to finger print the effluents that are flowing from the different annuli. Also, the experienced annuli pressures were, in most cases, within the normal range. Hence, the source of the annuli pressures remained a mystery. The occurrence of a very high sustainable tubing casing annulus (TCA) pressure in DKG-well A prompted us to search for the source of the noted unusual high pressure. Events from the well history as well as pressure data obtained during its workover supports our belief that an abnormally high pressure formation was the cause of the experienced high annulus pressure. While the exact formation bearing the high pressure had not yet been identified its properties and characteristics have become partially known. Our second case study DKG-well B is a recently drilled well. As a result of high annulus pressure, the well developed integrity issues immediately after it was put on production. During the workover to reinstate the well's integrity it became clear that the Sudair formation is the likely source of the high annulus pressure. This case study is a summary of the events that led to the discovery of the culprit high pressure zone. What's next? Now that we know what has caused the loss of integrity of a number of DKG wells. What we present here are other operators' experiences with Sudair formation and what have they done to predict and overcome its pressure.

Borehole stability while drilling in one of UAE's carbonate onshore reservoirs could be challenging due to the uncertainity of formation pressure. With such inaccurate Formation pressure, the regular action taken is to use a higher mud wight to avoid getting unexpected kick or blowout. On the other hand this high overbalance mud weight could lead to big possibility of differential sticking; it also affects the drilling performance & cause formation damage. When it comes to proper decision-making in drilling and delivering a healthy well, accurate formation pressure measurmtent is the only solution in mud weight program. Formation pressure plays a major role in everything related to drilling and production from within a reservoir. Downhole pressure testers have long been a key component in a reservoir engineer's analysis and well planning. There are the determinations of formation pressure, fluid contacts, reservoir connectivity & near wellbore mobility. Real time applications of formation pressure while drilling are obvious in mud weight management, safe selection of casing points, caliberation of pore pressure predicitons, geosteering & obtaining data in high-risk wells. Traditionally, Formation pressure data have been acquired using wireline formation testing different tools upon reaching section or well TD, but due to the difficulties of running wireline tools in such high angles wells, high possibility of getting stuck due to high overbalance pressure & formation pressure change from well to another, the best option was to use while drilling Formation pressure testing that provide accurate formation pressure, help in real time mud weight control decision making & save trip time needed for wireline runs. The Potential operator cost efficiencies of acquiring valid formation pressure data while drilling are becoming more influential in deciding the value proposition of a wireling reservoir characterization program. Incorparating formation pressure testing into the drilling process presents challenges to perform measurments in highly controlled parameters like limited testing time, drilling environment noise, continuous circulation while testing to insure wellbore safety. Providing an accurate while-drilling formation pressure testing (LWD tool) allows a continuous approach to data evaluation & decision making. The ability to measure accurate LWD formation pressure data in a variety of hole sizes represents a significant opportunity for safe & costeffient wellbore construction specially in challenging environments. A logging-while-drilling (LWD) formation tester was used in combination with a normal LWD gamma ray (GR), resistivity, density, and neutron to drill through the carbonate reservoir well. While drilling, formation pressure tester tool was recording in real-time a lot if data such as annulus pressure & equivalent circulating density (ECD) that provided a good indicator of borehole cleaning and mud conditions. In addition, different pressure stations were acquired to ascertain formation pressure and overbalance. Results from the LWD pressure formation tester helped the drilling team make the right decision to safely drop mud weight without any risk and reduce overbalance pressure, avoiding any possibility of losses or differential sticking. Hence, reducing mud weight also increased rate of penetration (ROP) and reduced formation damage.

A computational fluid dynamics (CFD) analysis is conducted on the flow of Newtonian and non-Newtonian fluids in annuli including the effect of inner pipe rotation. A practical numerical model is proposed that accurately estimates the annular frictional pressure losses with and without the inner pipe rotation. Experiments are conducted at a 91 ft. long flow loop using various fluids that can be characterized as Yield Power Law (YPL). A commercial CFD software is used to validate the proposed numerical approach. A comprehensive comparison of the proposed model, CFD results, experimental results, the published experimental results and most widely used models from the literature is presented. The experimental setup simulates horizontal wellbore applications, which are increasingly prevalent due to recent shale plays. Today, since most drilling fluids show YPL behavior, YPL fluids with a wide range of rheological properties are used as test fluids in this study. The numerical model is coupled with a stability criterion that determines the onset and offset of the transitional flow between laminar and turbulent regions. The velocity profiles of a wide range of diameter ratios, Taylor and Reynolds numbers are presented. Various degrees of eccentricity are analyzed in terms of pressure profile and flow stability with the proposed method. The results from the experiments show significantly reduced pressure drops in fully eccentric annuli compared to concentric geometry. An increase in pressure loss is observed as the pipe is rotated while it is eccentric. The comparisons between the models indicate that the slot approximation can result in large errors especially when the diameter ratio is low. A 3D wellbore can be evaluated with grids using the proposed numerical method and the local stability criterion, which leads to accurate pressure loss estimations. Grid analysis can show the flow state profile and the pressure loss profile of a wellbore, which has potential to optimize operations in real-time or in the design phase. This study contributes to a better understanding of flow in annuli. The results obtained from this study are useful to predict the transition and the annular frictional pressure loss profiles more accurately than existing methods. Potential applications include risk avoidance and optimized operations.

Summary To investigate the causes of fluid migration behind the casing after primary cementing, pressure and temperature measurements were made in the annulus of seven wells during cementing operations. Sensors were attached to the outside of the casing as it was run into each well; in this way data were obtained from several depths. A logging cable, also clamped to the casing, was used to bring data from the sensors to the surface. In some of the wells these annular measurements were continued during subsequent completion or work over operations. The pressure data could be used to determine conditions that either prevented or allowed fluid entry into the wellbore. Generally, pressure in the cement column began to decrease shortly after the cement was pumped. The success of the cementing operation depended on the cement attaining sufficient strength to exclude pore fluids from the cement before the pressure somewhere in the cement column declined to pore pressure at that depth. Pressure in the cement generally appeared to decline to the pore pressure in adjacent formations after the cement had set. In one well, however, pressure in the cement opposite a "tight streak" steadily declined to far less than a water hydrostatic gradient as the cement set. Fluid did not enter the wellbore and migrate to the surface soon after cementing in any of the wells investigated, but in one well fluid flow between zones behind the casing was indicated when the pressure in the cement decreased to pore pressure before the cement set. Before perforating was performed, annular flow was confirmed by a noise log in this well. The pressure sensors allowed other observations to be made both during and after cementing, including the effects of annular pressure applied at the surface during curing of the cement, and communication behind the casing during perforating, acidizing, and squeeze cementing. The temperature measurements in the annulus were used to monitor the setting of the cement, which is accompanied by evolution of heat. The cement generally set from the bottom of the wellbore toward the top. These field data confirm laboratory data that show a pressure decline in a cement column as the cement cures. pressure decline in a cement column as the cement cures. Conditions more likely to lead to annular fluid migration before the cement sets and steps that can be taken to decrease the likelihood of these occurrences can be identified from the field results. The pressure loss in a cement column before the cement cures is believed frequently to be responsible for vertical fluid flow behind the casing. The acronym FILAP is suggested for the phenomenon of "flow induced by loss in annular phenomenon of "flow induced by loss in annular pressure." pressure." Introduction The importance of achieving successful primary cementing of a well is hard to overemphasize. If there is a failure to seal the annulus outside the casing or liner, pressure may appear at the surface of the well from pressure may appear at the surface of the well from migrating gas (which is called "annular gas flow"), a liner top may leak, or fluids may flow between zones behind the casing in the well. Flow between zones can cause the loss of valuable hydrocarbons, the failure of stimulation treatments, and other problems. JPT P. 1429

ABSTRACTThis study is related to the newly developed and patented turbo solenoid turbine system. In this context, a numerical study was conducted on turbines with Darrieus, Gorlov and Lucid® configurations. As a result of the tests made on turbines with a NACA0018 aerofoil profile, the Lucid® turbine produced the highest moment and also highest pressure loss. Although a 10° twisted aerofoil Gorlov turbine produced 31.3% less moment than the Lucid® turbine, it also caused 51.4% less pressure loss. Also, it was observed that a Darrieus turbine with NACA0021 profile produced 1.5% less moment and 3.3% more pressure loss than a NACA0018 profile and turbine with NACA0015 profile, which produced 9% more moment and 1.4% more pressure loss than NACA0018.On the performance impact studies of the aerofoil twist angle, 20° twisted Gorlov turbines produced 19.1% more moment and 5.5% less pressure loss than a 10° twisted aerofoil turbine. Finally, a 20° twisted Gorlov turbine with NACA0015 aerofoil profile was analyzed. Following the studies, it was observed that the 20° twisted Gorlov turbine with NACA0015 aerofoil profile gave the best result by creating a 49.3% less pressure loss, in spite of only producing 4.7% less moment than the Lucid® turbine.