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Abstract This paper outlines our selection of well completion design based on the results of sand production prediction for each of the development wells and the total sand production to be expected from the field. The methodology on the formation failure and modeling analysis for sand production and sand rate prediction is provided for the HPHT gas and gas condensate field located offshore in the UK's Central North Sea. Sand production caused by the failure of reservoir formations through pressure depletion and drawdown pressure could lead to a significant loss in well production, well/facility damage or ultimately total well failure. The key objective of this evaluation and sand rate prediction analysis was to develop a well completion design that will deliver effective sand control throughout the producing life of the field. Over the field life it is both critical and prudent to predict the sanding potential of a given reservoir during continuous well production for any completion design under consideration. This paper illustrates our comprehensive geomechanics investigation for sanding potential and sand rate prediction analysis for all the planned wells to be drilled and completed in the very thick sandstone reservoirs. We'll also show that if the reservoir rock strength and its variability along depth are properly measured for each well (through well core testing and log data analysis), the conditions that induce sand production issues for each specific interval could be predicted. In addition, the most important factors contributing to sanding problems have been identified to be the rock strength, flowing bottom-hole pressure, reservoir pressure, in-situ stresses, and flow rate. Therefore if permeability distribution and oil/gas and water saturations were measured (for each well) in addition to the reservoir rock strength, the optimal completion method to reduce the likelihood of sand production problems without significantly impacting production could be found. A 3D non-linear elastic-plastic finite element model incorporated with a fluid-flow module (reservoir component) has been effectively used to conduct such analysis. The key findings from this investigation can be summarized as follows: The sand production rates based on the planned reservoir depletion and production schedules are predicted for each of the eight wells as planned for the field development; We can further update the original sand rate prediction model using the new rock strength and permeability/porosity test results obtained from the immediate testing of the new well cores as retrieved from one of the early development wells; The predicted sand rates in both daily and total sand production are low enough to warrant our sand management (rather than sand exclusion) approach to this new field; and The sand prediction results enable us to come up with optimal well platform/facility design to cope with the predicted sand rates to be produced throughout the reservoir life. The production engineers can also make sure that the overall safety of the facility is to be achieved by conducting regular and periodic inspections of any likely sand erosion for the surface chokes or pipes in the wells that especially have been forecast to produce more prolifically with relatively higher sand rates.
- Europe (1.00)
- North America > United States > Texas (0.69)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.55)
Abstract The authors previously presented the industry's first SPE paper in wellbore strengthening by proposing a new idea for lost circulation prevention while drilling. During our attendance of the 2010 SPE FORUM (Lost Circulation and Wellbore Strengthening) held at Park City, Utah, we presented and discussed about various wellbore strengthening methods as currently employed and practiced in the industry. These methods include well cooling, stress cage, and tip screening of induced fractures. Some participants requested parametric analysis of these methods using equations of rock mechanics principles. A set of analytical equations are developed for parametric analysis of four typical wellbore strengthening methods. They may be classified by the size of cracks to be stabilized as follows: Borehole strengthening with heating by stabilizing 0 to 0.1 in. cracks. Borehole strengthening by stabilizing micro cracks (with mud cake or fine particles) for 0.1 in. to 1 in. cracks Borehole strengthening by stabilizing macro cracks (stress cage method) for 1 in. to 2 ft cracks Borehole strengthening by stabilizing a large fracture with tip screening method for more than 10 ft cracks Simplified equations are developed for the above four methods. These equations reveal limitations and advantage of each method. The following items are a part of the parameter studies: Water base mud mixed with 25-40 mesh particles stabilizes borehole by plugging micro cracks with mud cake. Some solid return from shale shaker or mixing 25-40 mesh crushed nut shell enhances borehole stability. The stress cage method is safely applied if the formation permeability is not too small. However, as the permeability is small, it requires to reduce extension of induced fracture with a high fluid loss pill to place the granular materials, while an ultra-low fluid loss mud is required during drilling after strengthening to reduce the pressure build-up in the fracture section behind the seal. The tip screening method does not require squeezing particles by inducing a fracture. Particles mixed with drilling fluid prevent fracture initiation, and, if a fracture is induced, it prevents further fracture propagation by tip screening. It is effective if a lost circulation zone has some permeability, while it is not effective if the lost circulation zone has no permeability. In this paper, a set of simplified equations are presented to clarify the wellbore strengthening methods and parameter studies are conducted for each method to clarify the advantages and disadvantages of each method. Equations developed in a previous paper by current authors are significantly improved for easier implementations of wellbore strengthening methods.
Abstract This paper describes two types of hole problems and wellbore stability solutions for drilling operations in North Sea fields: (1) severe shale cavings and wellbore collapse; (2) drilling through cap rock and reservoir formations impacted by large pressure depletion and reservoir compaction effects. Field cases of wellbore collapses and failures in shale formations during high-angle drilling are presented along with a systematic program of comprehensive geomechanics investigation and evaluation necessary to prevent such events. The program includes analyzing drilling and log data analysis for rock strength and earth stress model construction, laboratory triaxial stress-strain tests on well core samples considering bedding plane inclination effects, 3D analytical modeling and 3D elastic-plastic numerical modeling analysis for determining optimum mud-weight (MW) windows for secure and stable well drilling. Continuous well production can also present problems for in-field drilling as the severe pressure depletion and reservoir compaction will cause significant reduction in stresses and formation fracture gradient. These effects may occur not only in the reservoir, but may also extend significantly upward into the cap rock formations depending on the reservoir/formation stiffness contrast, reservoir size, thickness and depth, etc. Therefore, the optimum MW must be examined and recalculated based on the insitu stresses that can be altered by this effect. In summary, this paper will include the following: Analysis of actual drilling cases of severe shale caving and wellbore collapses/failures; Laboratory triaxial stress-strain tests on well cores considering bedding plane effects; Effective drilling guidelines based on modeling analysis of troublesome shale formations; Coping with reduced stresses and formation fracture gradient due to reservoir depletion and compaction effects; Use of wellbore strengthening material for drilling (and possible reduction in number of casing strings); Case histories of severe wellbore instability and lessons learned.
- North America > United States > Texas (0.47)
- Europe > United Kingdom > North Sea (0.34)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Europe > United Kingdom > North Sea > Northern North Sea > South Viking Graben > Block 9/23a > Tullich Field > Balder Formation (0.99)
- Asia > Indonesia > Sumatra > Riau > Central Sumatra Basin > Rokan Block > Rokan Block > Kotabatak Field (0.99)
- Europe > Norway > North Sea (0.91)
- (2 more...)
- Information Technology > Modeling & Simulation (0.54)
- Information Technology > Data Science (0.48)
A Comprehensive Modeling Analysis of Borehole Stability and Casing Deformation for Inclined/Horizontal Wells Completed in a Highly Compacting Chalk Formation
Furui, Kenji (ConocoPhillips Co) | Fuh, Giin-Fa (ConocoPhillips Co) | Abdelmalek, Nabeel A. (ConocoPhillips Co) | Morita, Nobuo (Waseda University)
Abstract Numerous casing and production liner deformation/failure problems have been reported in high porosity chalk formations in both the overburden and the reservoir sections, causing costly operation problems that prevent workovers and recompletions. This paper presents the results of studies performed to investigate stability of an openhole, cemented liner, and uncemented liner completions in a highly compacting chalk formation. The effects of critical cavity dimensions caused by various acid stimulation techniques were also investigated. Based on the review of historical caliper survey data, we ascertain that the axial compression collapse is a major liner deformation mechanism in the reservoir zones. Axial compression collapse has been found in both low-angle wells (also buildup sections of horizontal wells) and horizontal laterals. The casing deformation in low-angle sections are due to reservoir compaction (i.e., change in the vertical formation strain) while the deformation in horizontal sections are primarily induced by increased axial loading due to cavity deformation. The current completion practice using cluster perforations and high volume acid treatments causes vertically enlarged cavities resulting in poor radial constraint. A series of laboratory triaxial tests were performed on selected reservoir chalk samples to measure the stress-strain and failure behavior of the chalk formation considering a wide range of porosity, water saturation, and different levels of confining pressures. Using the chalk failure criteria and constitutive relations developed from the analysis of laboratory triaxial compression test data, a 3D non-linear poroelastic-plastic finite element model was developed for the openhole stability analysis. The simulation results show that the abnormally high ductility of chalks after pore collapse around a borehole could actually enhance borehole stability with the magnitude beyond expectation. In this study, the analytical and numerical models are also developed for evaluating cavity-induced axial compression collapse of production liners. Model results indicate that the risk of the cavity-induced axial compression collapse substantially increases for short perforated intervals stimulated with large acid treatments. However, increasing the perforation interval lengths along the entire liner axis results in more uniform acid distribution and will greatly reduce the chance of axial compression collapse caused by localized cavity deformation. Based on these analysis results, key completion design criteria and stimulation strategies were developed for wells completed in highly compacting chalk reservoirs to reduce risk of casing and liner mechanical problems. Introduction Historical casing and liner failure events experienced in high porosity chalk fields were reviewed to determine possible causes of the deformations. Most casing and liner deformations have been realized during routine wireline and workover operations. These casing problems were discovered in both the overburden and the reservoir interval. Nine hundred and sixty one casing and liner deformation problems are recorded in an operation database established from two high porosity chalk fields, roughly 40 % of which occured in the overburden while 60 % were found in the reservoir production intervals. In this study, we focus mainly on production liner deformations in the reservoir section. All of the existing wells in the field are cased, cemented, and perforated well completions. Fig. 1 shows the frequency of the liner deformation events for different well inclinations measured at the deformation depth from one of the high porosity chalk fields. There are large number of casing deformation events recorded at q = 15ยฐ ~ 45ยฐ while there are relatively few deformations identified at higher angle sections (q > 60ยฐ). One of the reasons is that there are a large number of vertical/low-angle wells drilled during the early development stage in the field. During this period, the field was operated under primary depletion. These low-angle wells had buckling problems due to reservoir compaction. Horizontal wells that have been recently completed in the field also experienced liner deformation problems where the effect of reservoir compaction strain may not be as high as the early vertical/low-angle wells. These liner deformation problems are considered as a result of localized acid stimulation treatment causing elongated cavity extension from perforation tunnels.
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Chalk Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.97)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.97)
Abstract The manufacturer's specifications of sand screen usually provide information such as base pipe collapse pressure, maximum tensile load, and bending strength. However, the problem is that a very heavy base pipe is thus required to satisfy such specifications if the pipe collapse pressure indicated by manufacturer is used for field application. The reason is that the screen collapse tests are conducted under hydrostatic loading for screens wrapped with rubber jacket by screen manufacturers. Observation of these tests shows that screen collapse occurs immediately after the base pipe starts yielding. However, this is not the case if screens are installed in the wellbore under geotectonic load. A series of laboratory tests are conducted using either straight pipes without screen or pipes with screen installed in a drilled borehole of some large rock sample. Since the base pipe failure is the dominant factor for screen failure, half of the experiments shown in this paper used straight pipe without including screen or shroud. These tests show that tubular strings may initiate yielding earlier than the specified yielding data provided by screen manufacturers. However, after the initial yielding, the base pipe deforms gradually and it never collapses even after exceeding the ordinary base pipe yielding (0.2โ0.4% deformational strain) by more than 10 times. Based on these laboratory tests, a numerical model is constructed for screen design along with gravel pack or stand-alone screen in openhole completions. The numerical model first simulates hydrostatic screen collapse tests conducted by manufacturers to confirm the design specifications as measured. Then, it is extended to simulate screen behavior after it is installed downhole. It assumes that a screen is placed in the borehole, and then gravel-pack covers the screen, followed by reservoir depletion and drawdown in production mode. This paper sheds light on the sand screen collapse resistance under three typical loading types: hydrostatic, geotechtonic load without void around sand screen and geotectonic load with void for openhole standalone screen applications. Distinctly different failures criteria are proposed for these three types of loadings. Empirical data under such high stress levels are rarely found in the literatures.
Abstract Sand flow models have been successfully applied to heavy oil reservoirs. However, when these models are applied to light oil and gas reservoirs, the equations controlling generation of eroded solid mass or sand release rate are vastly simplified necessitating further field observations controlling sand flow rate in order to improve accuracy. Sand flow is catastrophic when formation is soft. However, if certain conditions are satisfied, the sand rate is reasonably stable. This paper clarifies nine forms of post-failure stabilization. Subsequently, field methods to deal with sand problems with uncertain sand rate predictions are proposed. Introduction Perforation cavities are enlarged with sand production. The cavities become contiguous and form larger cavities around a cased hole. Finally they form irregular cavities as shown in Fig. 1. Fig. 1 Cavity growth during sand production To model the sand flow, each cavity must be meshed as shown in Fig.2 requiring 100โ500 meshes around each cavity. If one thousand cavities are modeled, 0.1โ0.5 million meshes are required. Failure status must be checked at each 3D cavity surface for 0.1โ0.5 million cavities, requiring enormous computer processing time. In order to avoid the prohibitive requirements of enormous computer time, the model must be vastly simplified by eliminating any cavities.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.54)
Use of Reservoir Formation Failure and Sanding Prediction Analysis for Viable Well-Construction and Completion-Design Options
Fuh, Giin-Fa (ConocoPhillips Co) | Ramshaw, Ian (ConocoPhillips UK Ltd) | Freedman, Kerry Craig (Dubai Petroleum Co.) | Abdelmalek, Nabeel A. (ConocoPhillips) | Morita, Nobuo (Waseda University)
Abstract Using two field case examples, this paper presents our current well construction and completion design analysis based on the following approach:carry out detailed evaluation or determination of reservoir formation strength distribution using core testing, log data and drilling data analysis for rock strength estimate and its correlation with core testing results; conduct a series of triaxial tests on selected reservoir core samples in the low to intermediate strength range for defining the stress-strain relationship (or material laws), rock failure and yield criteria, and other non-linear rock parameters required for numerical modeling analysis; perform a series of formation failure and sanding potential analysis for a variety of possible well completion design scenarios using 3-D finite element technique for rock structure coupled with well production and fluid flow simulation. The types of completion design analyzed include cased hole completion using conventional perforations or stress-oriented perforations in inclined or high-angle well, openhole completion in high-angle or horizontal well, screen failure analysis in openhole completion, etc. In addition to investigating the mechanical response of the rock formations in each completion design, the model simulates both well drawdown and reservoir depletion effects on sand failure potential throughout the reservoir life. The results of such systematic study provide useful guidelines on well design and completion strategy for sand control or sand management in order to optimize well productivity. The two case examples presented in this paper highlight the use of this technique and approach. We have used this type of analysis and process for the well design in our business operations around the world with good success. Based on our case example analyses and the specific rock failure characteristics as defined in the laboratory testing results and subsequent numerical simulations of sanding behavior, we are able to identify the most viable well construction and completion design for achieving a superior well deliverability and productivity for the long term, minimizing problems due to unintended solid influx and/or loss of well integrity over the reservoir life. The two field case examples in the North Sea as presented demonstrate and highlight the fundamental concept, methodology and the procedures for conducting the well design analysis through a series of computer simulations of various options for well completion schemes. The field example results will also show the effective use of rock failure characteristics by the engineers for the control of critical flowing bottom-hole pressure in relation to the reservoir drawdown and depletion to avoid premature sand failures during well production.
- North America > United States (0.93)
- Europe > United Kingdom > North Sea > Central North Sea (0.47)
- Europe > Norway > North Sea > Central North Sea (0.28)
- Phanerozoic > Mesozoic (0.93)
- Phanerozoic > Paleozoic (0.93)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.31)
- North America > United States > Texas > Permian Basin > Central Basin > 3000 Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 30/7a > J-Block Field > Judy Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 30/7a > J-Block Field > Joanne Field > Judy Field (0.99)
- (36 more...)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Well Planning (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- (6 more...)
North Slope Heavy-Oil Sand-Control Strategy: Detailed Case Study of Sand-Production Predictions and Field Measurements for Alaskan Heavy-Oil-Multi-Lateral Field Developments
Burton, Robert C. (ConocoPhillips) | Chin, Lee (ConocoPhillips Co) | Davis, Eric Robert (ConocoPhillips Alaska Inc.) | Enderlin, Milton Bock (ConocoPhillips) | Fuh, Giin-Fa (ConocoPhillips) | Hodge, Richard M. (ConocoPhillips) | Ramos, Rico (ConocoPhillips) | VanDeVerg, Phil (ConocoPhillips) | Werner, Michael (ConocoPhillips) | Mathews, William Lloyd (BP Exploration Alaska Inc) | Petersen, Sean David (BP plc)
Abstract The North Slope of Alaska has billions of barrels of heavy oil residing in largely undeveloped reservoirs.Despite this large volume of heavy oil in place, the majority of reserves development on the slope to date has been focused on light crude.However over the past 20 years Arco, BP, Conoco and now ConocoPhillips have begun to develop the North Slope's vast heavy oil resource base.Recently a sand/solids control study was undertaken by ConocoPhillips and BP in order to determine the most economic strategy for solids control and well design in future heavy oil developments. The study was integrated across companies, organizations and discipline boundaries in order to include completion, rock mechanics, laboratory research, drilling, reservoir, geological, operations, facilities and field personnel.With this diverse team, actual solids production and solids predictions were investigated from a number of different perspectives. Solids production predictions were made based on core measurements, log analysis, simulators that predict formation failure and sand production rate, laboratory core flow tests, 2 years of field shakeout data, and multiple field measurements of solids production.Probabilistic predictions were then generated based on these investigations rather than deterministic "best guesses" for the economic analysis.These different methods for predicting solids production will be discussed and illustrated in this case study. The study and ensuing strategy determined that sand management or using non-sand exclusion slotted liners and sand tolerant facilities was the highest value development scenario over the life cycle of the North Slope Heavy Oil Developments.
- North America > United States > Alaska > North Slope Borough (0.94)
- North America > United States > Texas (0.93)
- Research Report > New Finding (0.46)
- Research Report > Experimental Study (0.46)
- North America > United States > Alaska > North Slope Basin > Kuparuk River Field > West Sak Field (0.99)
- North America > United States > Alaska > North Slope Basin > Kuparuk River Field > Kuparuk Field (0.99)
- North America > United States > Alaska > Schrader Bluff Formation (0.94)
SPE Members Abstract Drilling in the "V' Fields of the UK sector of the southern North Sea (particularly the long-reach horizontal type of well) has historically meant differential sticking problems as the reservoirs become depicted through continual gas production. Quite often, reservoir pressures are in the region 5.5-6.5 ppg EMW, with some reservoir compartments failing to as low as 4.2 ppg EMW, which poses considerable problems to the drilling process particularly with respect to differential sticking and the possible risk of hole collapse. This paper describes the engineering which resulted in the success of the most recently drilled "V" Fields horizontal well through the depicted Rotliegendes sandstone reservoir with respect to borehole stability analysis, drilling and the operator's first openhole completion in the UK sector of the North Sea. Introduction Development Well 49/16-P07/01 was the seventh well to be drilled from the North Valiant 1 production platform which forms pan of the 4 V-Fields (North Valiant, South Valiant, Vulcan and Vanguard - Figure 1) which lie on the eastern flank of the Sole Pit Basin in southern sector of the UK North Sea located approximately 75 miles off the Lincolnshire coast. Discovered in 1983, the North Valiant field is prominently faulted and dipped, posing considerable challenges to effective directional drilling. Gas wells to the Rotliegendes sandstone reservoir (the source of the hydrocarbons being the underlying Carboniferous Westphalian coal beds - see Figure 2) in the North Valiant Field are directionally drilled from a jacket which interfaces with the Lincolnshire Offshore Gas Gathering System (LOGGS) which transports collected gas not only from North Valiant and the other V Fields but from a variety of other sources which are largely unmanned satellite platforms. The Rotliegendes sediments, of Early Permian age, comprise desert basin fluvial sands and lacustrine shales overlain by acolian sands. The fluvial/wadi sediments show a NNE transport pattern away from the London-Brabant Massif to the SSW of the 4 Vs area. Because of the prevailing Early Permian wind, the aeolian sediments, derived from unconsolidated alluvial fan, wadi and floodplain deposits, show a westward transport direction. Later, the Zechstein Sea rapidly submerged the desert dunes, establishing conditions favourable for the cementation of the uppermost reservoir sections. The formation of structural traps resulted from tectonic movements in the late Permian and Mesozoic ages; the seals being provided by impermeable Zechstein evaporites. The virgin reservoir pore pressure for Well 49/16 โ P07/01 was expected to be approximately 3650 psi @ 7800 ft TVD SS with depletion pressures (due to production) in the range 2300 โ 1700 psi (5.7 โ 4.2 ppg EMW). Reservoir permeability was expected to be in the range of approximately 0.1 mD to c. 100 mD and reservoir porosity in the range of approximately 9% to approximately 17%. These factors, coupled with the prominently faulted and dipped formations therefore demanded both thorough planning and diligent operational practise at the rige site in order that this well be a success. The following points are discussed with respect to the drilling of this horizontal well through the depicted North Valiant Rotliegendes sandstone reservoir:The avoidance of differential sticking through optimal applications engineering, namely: borehole stability analysis based on field data and laboratory work; use of a low weight elevated low shear-rate rheology mudsystem designed specifically for laminar flow and computer designed/special profile BRA's to both minimise differential sticking risk and optimise jar energy firing efficiency; Contingency planning in the event of becoming stuck, namely: the usage of acid pills which could be absorbed by the mud system and the utilisation of the U-tube method to reduce hydrostatic by the injection of nitrogen into the annulus; The utilization of borehole stability analysis with regard to an openhole completion - the first time this method of completion has been used by the operator in the North Sea. Full utilization of the engineering outlined in points 1 and 3 above proved to be very successful; - the prime goal of avoiding differential sticking was achieved and the well flowed - during testing - at a rate of 46 MMSCFD which was regarded as being a considerable success. P. 741^
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > Block 49/16 > V-Fields > Valiant North Field > North Valiant Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
SPE Members Abstract This paper presents a new concept, theoretical formulations, and field test results of the loss prevention material (LPM*) developed for use in many possible applications such as high-angle and horizontal well drilling, drilling through severely depleted formations (to optimize casing requirements), drilling through highly tectonically active areas (i.e., regions of overthrust faults and salt dome structures) where the in situ rock stresses are high and directionally unequal. Both open-hole microfractures and 5000-ft open-hole leak off tests using LPM were successfully conducted in our wells in Newkirk, Oklahoma, and Ventura, California. LPM is a specialty selected (material strength and specific gravity) and narrowly sized granular material which, after being fully mixed in oil or water based mud at an optimum concentration, can provide good protection to formations against lost circulation while drilling. Higher formation fracture resistance resulting from the use of LPM in drilling fluids can reduce or prevent the occurrence of lost circulation while drilling. This paper will show that a remarkable increase of 8.0 ppg in borehole breakdown pressure was achieved in one of our tests in the Newkirk well. An increase of fracture propagation pressure in the range of 3.0 to 6.0 ppg was recorded in the field tests. These results are in general agreement with our laboratory findings also discussed in this paper. Introduction The idea of lost circulation prevention is not only achievable, but also practically feasible. Needless to say, lost circulation prevention is far more cost effective than any remedial action taken after the occurrence of lost circulation. Especially with oil muds, losses can be very expensive, unsafe (underground blowout), and time consuming. It is under this premise that this new LPM (loss prevention material) product was developed for use in "lost-circulation-prone" zones or in high-angle hole drilling when a higher mud weight is required to counter potential borehole collapse, stuck pipe, tight hole, or other hole instability problems. Adding LPM to the drilling fluid will provide the extra margin of borehole protection for mud weights used and will reduce the degree of uncertainty involved with any type of work or operation concerning natural geologic formations. Based on our laboratory test results using large Berea sandstone blocks, an optimum LPM concentration can be found and it varies with mud densities. According to our experimental investigation and analytical verification, formation fracture initiation and propagation during well drilling can be prevented or inhibited by including an effective concentration of LPM (a specialty sized granular material) in the drilling fluid. P. 569^
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.69)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)