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Summary The Schoonebeek heavy-oil field was first developed by Nederlandse Aardolie Maatschappij B.V. (NAM) in the late 1940s. Because of economics, it was abandoned in 1996. In 2008, the Schoonebeek Redevelopment Project, using a gravity-assisted-steamflood (GASF) design concept, was initiated with 73 wells (44 producers, 25 injectors, and 4 observation wells). Steam injection and cool-down cycles subject a cement sheath to some of the most severe load conditions in the industry. Wellbore thermal modeling predicted that surface and production sections would experience temperatures in excess of 285ยฐC (545ยฐF) and considerable stress across weak formations. A key design requirement was long-term integrity of the cement sheath over an expected 25- to 30-year field life span. Complicating this requirement was the need for lightweight cementing systems, because lost-circulation issues were expected in both hole sections, particularly in the mechanically weak Bentheim sandstone. The long-term integrity challenge was divided into chemical and mechanical elements. Prior research on high-temperature cement performance by the operator provided necessary guidance for this project. Laboratory mechanical and analytical tests were conducted to confirm the high-temperature stability of the chosen design. In addition to using lightweight components, foaming the slurry allowed the density, mechanical, and economic targets to be met. A standardized logistical plan was put in place to allow use of the same base blend for the entire well, adjusted as needed, using liquid additives, and applying the foaming process when necessary. This single-blend approach greatly simplified bulk-handling logistics, allowing use of dedicated bulk-handling equipment. The first well was constructed in January 2009; all 73 wells have been successfully cemented to surface. The steaming process, initiated in May 2011, has progressed with no well integrity issues to date.
- North America > United States (1.00)
- Europe > Netherlands > North Sea > Dutch Sector (0.50)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.35)
- Europe > Netherlands > North Sea > Dutch Sector > Schoonebeek License > Bentheim Sandstone Formation (0.99)
- Europe > Netherlands > North Sea > Dutch Sector > Schoonebeek Field > Bentheim Sandstone Formation (0.99)
- Europe > Netherlands > Coevorden Field > Z3 Carbonate Formation (0.98)
- (6 more...)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
- (7 more...)
Surge-and-Swab Pressure Predictions for Yield-Power-Law Drilling Fluids
Crespo, Freddy (University of Oklahoma) | Ahmed, Ramadan (University of Oklahoma) | Enfis, Majed (University of Oklahoma) | Saasen, Arild (Det norske oljeselskap and University of Stavanger) | Amani, Mahmood (Texas A&M University at Qatar)
Summary Surge and swab pressures have been known to cause formation fracture, lost circulation, and well-control problems. Accurate prediction of these pressures is crucially important in estimating the maximum tripping speeds to keep the wellbore pressure within specified limits of the pore and fracture pressures. It also plays a major role in running casings, particularly with narrow annular clearances. Existing surge/swab models are based on Bingham plastic (BP) and power-law (PL) fluid rheology models. However, in most cases, these models cannot adequately describe the flow behavior of drilling fluids. This paper presents a new steady-state model that can account for fluid and formation compressibility and pipe elasticity. For the closed-ended pipe, the model is cast into a simplified model to predict pressure surge in a more convenient way. The steady-state laminar-flow equation is solved for narrow slot geometry to approximate the flow in a concentric annulus with inner-pipe axial movement considering yield-PL (YPL) fluid. The YPL rheology model is usually preferred because it provides a better description of the flow behavior of most drilling fluids. The analytical solution yields accurate predictions, though not in convenient forms. Thus, a numerical scheme has been developed to obtain the solutions. After conducting an extensive parametric study, regression techniques were applied primarily to develop a simplified model (i.e., dimensionless correlation). The performance of the correlation has been tested by use of field and laboratory measurements. Comparisons of the model predictions with the measurements showed a satisfactory agreement. In most cases, the model makes better predictions in terms of closeness to the measurements because of the application of a more realistic rheology model. The correlation and model are useful for slimhole, deepwater, and extended-reach drilling applications.
- Europe (1.00)
- Asia (0.68)
- North America > United States > Texas (0.29)
- North America > United States > California (0.28)
- Research Report > Experimental Study (0.67)
- Research Report > New Finding (0.46)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
- (2 more...)
Unique Process and Tool Provides Better Acid Stimulation and Better Production Results
Al-Saqabi, Mishari (Kuwait Oil Company) | Gazi, Naz (Kuwait Oil Company) | Vishwanath, Chimmalgi (Kuwait Oil Company) | Al Bahrani, Hasan (Kuwait Oil Company) | Turkey, Naween (Kuwait Oil Company) | Abdul-Razaq, Eman (Kuwait Oil Company) | Al-Zankawi, Omran (Kuwait Oil Company) | Bouland, Ali (Kuwait Oil Company) | Surjaatmadja, Jim B. (Halliburton) | Al Hamad, Abdulla M. (Halliburton) | Brand, Shannon (Halliburton)
Abstract There are many ways to stimulate an unlined openhole horizontal well using acid. The simplest way is to just pump acid into the well (i.e., bullhead) without placement control. However, this can often be ineffective. Although still used, such approaches can create massive enlargements at the entry point or high injectivity area, thus causing ineffective treatments and re-entry issues. Wellbore collapse often follows. The use of coiled tubing (CT) as a "pin-point" delivery method is therefore preferred. Using CT allows dispersal of the acid either uniformly or intermittently along the lateral, as desired. CT also allows acid washing to be performed, which is another common process that can improve stimulation without much additional expense to the operator. Using a jetting tool with many jets, acid can be sprayed onto the wellbore wall, and the active agitation caused by the acid-wash process increases the chemical reactivity of the acid at the desired locations. Another beneficial approach of using CT is the hydrajet assisted acid fracturing (HJAAF) method. With focused jetting of acid at much higher pressures, the process initiates microfractures in the wellbore walls. When etched with acid, this approach effectively bypasses near-wellbore (NWB) damage much deeper than common washes, thus providing much better results. Further modification of the process by exerting high annular pressures offers the capability of delivering medium to large fractures. This paper discusses two HJAAF processes uniquely combined into one process used in two large horizontal wells. Because of the large dimension of the inner diameter (ID) of the wells combined with the small production tubing the tool must pass through, the implementation had to be further improved by using a unique jetting mechanism, which positioned the jet nozzles closer to the target. Actual results of such stimulations are presented.
- North America > United States (0.94)
- Asia > Middle East > Kuwait (0.30)
Abstract One of the major challenges of drilling and completion of oil and gas wells is the uncertainty in the formation fracture gradient and the fracture pressure. It is not uncommon that many drilling companies have spent money, resources and time in drilling and completing wells that should have been simply and optimally done. Fracture gradient evaluation constitutes one of the essential parameters in the pre-design stage of drilling operations, reservoir exploitations and stimulations. Several calculation methods and computer models have been presented in the literature for different regions of the world. Most of these techniques were based on either parametric or empirical correlations, which required a prior knowledge of the functional forms or the use of empirical charts which were not very accurate. This paper presents an innovative method of predicting formation fracture gradient for Gulf of Guinea region. A combination of "Mathew and Kelly" correlation, "Hubbert and Willis" correlation and Ben Eaton mathematical models were used in developing the simplified technique based on field data from the Gulf of Guinea. The model compared favorably with the existing fracture gradient results in the Gulf of Guinea with less than 1 % deviation from other correlations thereby saving the rigors and time in using tables, charts and other long techniques. Although the method was developed specifically for the Gulf of Guinea, it should be reliable for other similar areas provided that the variables reflect the conditions in the specific area being considered.
- North America > United States > Kansas > Willis Field (0.89)
- North America > United States > Kansas > Hubert Field (0.89)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- (2 more...)
ABSTRACT Modeling the stress conditions inside hydrocarbon and geothermal reservoirs is important to predict fracture behavior during injection of fluids. We analyze the influence of elastic heterogeneity on stress and fracture strength distribution in rocks. Therefore, we simulate the distribution of elastic modules inside a reservoir rock as a 3D fractal random medium according to parameters obtained from sonic well logging data. Using an ABAQUS finite element stress analysis model we determine the stress field inside the rock volume. By applying geo-mechanical considerations we then compute the fracture strength distribution and analyze relations between elastic modules stress state and fracture strength. The stress modeling analysis performed in this paper suggests that the stress state in elastically heterogeneous rocks can be highly heterogeneous. Our modeling study according to elastic heterogeneity derived from sonic well log data along the continental deep drilling (KTB) main hole results in a broadly distributed fracture strength between -10 to 20 MPa. We find strong relations between elasticmodules, stress state and fracture strength, which can be applied to predict the stress distribution in hydrocarbon and geothermal reservoirs and the occurrence probability of fluid injection induced seismicity.
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- (3 more...)
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Russian Oil & Gas Exploration & Production Technical Conference and Exhibition held in Moscow, Russia, 16-18 October 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract The Verkhnechonskoye (VCNG) oilfield located in Eastern Siberia is developed on pad clusters, with in excess of 200 wells drilled to date. Typical well geometry consists of a vertical 13 3/8in. Production hole is drilled in 6in. The predominant well design incorporates a double build profile which lands horizontally in the Verknechonskiy reservoir with an approximate 600m lateral drilled in the productive zone. VCNG field has evolved of key strategic importance to deliver oil through the Eastern Siberia Pacific Ocean (ESPO) pipeline from Russia to the vast Asia-Pacific market located to its South East. Increasing production targets have been required to deliver hydrocarbons to fulfill aggressive pipeline commitments. Meeting these requirements have in turn initiated a relentless drive to enhance operational efficiency since the inception of development drilling phase in 2007; leading to a significant increase in drilling performance and reduction in overall well construction time in the period to date. This improvement has been achieved against the backdrop of an environment which is extremely challenging on several distinct fronts; remoteness of the project with 600km from the nearest major conurbation, harshness of an extreme continental climate with temperatures seasonally dropping to -50ยบC and coupled with a unique and problematic lithological column all serve to make drilling, logistics and general operations a complex undertaking. The purpose of this paper will be to take a holistic review of drilling performance in the field and to chronicle the numerous incremental technological and procedural advancements which have led to a reduction in average well construction time from 58 to 21 days between 2007 and 2011.
- Asia > Russia > Siberian Federal District (0.28)
- Europe > Russia > Central Federal District > Moscow Oblast > Moscow (0.24)
- Geology > Geological Subdiscipline > Geomechanics (0.68)
- Geology > Rock Type > Sedimentary Rock (0.46)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Well Planning > Trajectory design (1.00)
- Well Drilling > Drillstring Design > Drill pipe selection (1.00)
- (9 more...)
Abstract Much of the drilling in unconventional resource plays occurs in unstable shales, which are usually fractured and can be easily destabilized. Drilling through them successfully can be difficult at best, and many high-angled holes in these plays are often lost due to mechanical instability. This paper examines the problems of shale gas drilling from the theoretical perspective of Wellbore Pressure Management (WPM) and keys in on the effects of equivalent circulating density (ECD) while drilling and on the effects of equivalent static density (ESD) when there is no circulation. In this paper the following questions pertaining to drilling a typical fractured shale or highly-laminated weak zone are addressed from the WPM perspective: What mud density do I need to drill a fractured shale? Why can a typical shale gas play well be drilled with no drilling problems, yet becomes very unstable on the last trip out of the hole before wireline logging or running casing? Why are drilling problems especially acute in laminated shales or similar weak zones? Why is the wellbore unstable while the drilling density is within the range demarcated by the Safe Drilling Window? Why does shale instability often not improve significantly when drilling fluid density levels are increased? Which tools in the driller's toolbox are often used that actually make the wellbore stability issue more problematic? By using a Wellbore Pressure Management approach to understanding instability in fractured shales, the reader can readily see how to best deal with the problem in the field and hopefully improve stability in future wells.
- South America (0.94)
- Europe (0.70)
- North America > United States > Texas (0.69)
- South America > Colombia > Casanare Department > Llanos Basin > Cusiana Field > Mirador Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (24 more...)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Pressure Management (1.00)
- Well Drilling > Drilling Operations (1.00)
- (5 more...)
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in San Antonio, Texas, USA, 8-10 October 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied.
- North America > United States > Texas > East Texas Salt Basin (0.99)
- North America > United States > Mississippi > Houston Field (0.99)
- North America > United States > Louisiana > East Texas Salt Basin (0.99)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Casing and Cementing > Casing design (1.00)
- (6 more...)
Abstract Cement durability is very important to maintain proper well isolation and stability under HPHT conditions. In the process of well completion and production, pressure decline and temperature variation with time can contribute to cement failure and wellbore stability issues. However, there is no available investigation in the durability and comparison of different types of cement at higher temperature and at different operational scenarios. Three different types of cement (72 pcf, 101 pcf and 118 pcf) commonly used in the Middle East were cured and tested at 300ยฐF in the study. The tests included one year mechanical properties measurement such as compressive strength development, Young's modulus and Poisson's ratio. Finite element method was used to analyze the failure probability of HPHT wells over with time. At the variation of bottom hole pressure and temperature, the casing, cement, and formation system failure probability was studied for these types of cement. The results show that the pressure variation has more effect on the wellbore stability than the temperature variation for HPHT wells. Low density cement can improve the wellbore stability issues due to the cement elastic behavior. This paper introduces the operational envelope for every type of cement investigated in order to achieve successful operations based on field conditions. Field cases were discussed to validate the results of this investigation.
- North America > United States > Texas (0.70)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate (0.28)
- North America > United States > New Mexico > San Juan Basin (0.99)
- North America > United States > Colorado > San Juan Basin (0.99)
- North America > United States > Arizona > San Juan Basin (0.99)
- (16 more...)
Abstract Lost circulation caused by low fracture gradients is the cause of many drilling related problems. Typically the operational practice when lost circulation occurs is to add loss circulation materials (LCM) to stop mud from flowing into the formations. To improve the treatment for lost circulation caused by low fracture gradients, especially designed materials in mud system are used to seal the induced fractures around the wellbore. This operation is in the literature referred to as wellbore strengthening that has been found to be a very effective in cutting Non-Productive Time (NPT) when drilling deep offshore wells. Size, type and geometry of sealing materials are debating issues when different techniques are applied. Also the phenomenon is not truly understood when these techniques applied in different sedimentary basins. This paper presents development and simulation results of a three-dimensional Finite-Element Model (FEM) for investigating wellbore strengthening mechanism. This study also describes a procedure for designing Particle Size Distribution (PSD) in field applications. To better understand the numerical results, the paper also reviews the connection between Leak of Tests (LOTs) and wellbore hoop stress and how these LOTs can mislead in fracture gradient determination. A comprehensive field database was collected from different sedimentary basins for this study. Results demonstrate that the maximum attainable wellbore pressure achieved by wellbore strengthening is strongly controlled by stress anisotropy. Results also show that Particle Size Distribution (PSD) of wellbore strengthening should be designed in order to seal the fractures close to the mouth and at fracture tip. This will result both in maximizing hoop stress restoration and tip-screening effects. In addition this model is able to show the exact fracture geometry formed around the wellbore that will help to optimize the sealing materials design in wellbore strengthening pills. To support numerical modeling results, near wellbore fracture lab experiments on Sandstone and Dolomite samples were also presented. Laboratory experiments results reveal importance of rock permeability, tensile strength and fluid leak-off in wellbore strengthening applications.
- North America > United States > Texas (0.46)
- North America > United States > California (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.51)
- North America > United States > Texas > Sabine Uplift > Trawick Field (0.99)
- North America > United States > New Mexico > San Juan Basin > San Juan Basin Field > Mancos Formation (0.99)
- North America > United States > Colorado > San Juan Basin > San Juan Basin Field > Mancos Formation (0.99)