Primary Cement Jobs Research Articles

English

Oil based muds formulated from diesel oil have proven to be quite expensive and environmentally unfriendly. This current study focused on investigating the suitability of castor oil in formulating oil based muds. The experiment in this work was conducted at different temperature conditions ranging from 40 to 80°C. The density and specific gravity of castor oil based mud were found experimentally to be 0.3 ppg and 0.4 higher than the density and specific gravity of diesel oil based mud, respectively. Plastic viscosity and gel strength of castor oil based mud were found to be 2 cp and 2 lb/100  , respectively found to be less than those obtained for diesel oil based mud (15 cp and 4 lb/100  , respectively) indicating the ability of castor oil in enhancing rate of penetration and efficient in hole cleaning. Results also show that a thinner filter cake was obtained for castor oil based mud in comparison to diesel muds. This shows that with castor oil based mud, undesirable effects such as differential sticking, loss circulation and poor primary cement jobs are minimized. The result from toxicity test also implied that the drilling mud formulated with castor oil can be easily disposed with less post drilling treatment. In conclusion, oil based mud formulated with castor oil can be used as an alternative to diesel oil based mud for drilling operations because its properties show that it can effectively perform its functions as a drilling fluid. It is also environmentally friendly.  Key words: Oil based mud, castor oil, diesel oil, rheological properties, drill cuttings.

Removal of Calcium Carbonate Water-Based Filter Cake Using a Green Biodegradable Acid

The filter cake is a very thin layer of solid particles deposited from the drilling fluid onto the surface of the drilled formation. This is essential during the drilling process as it reduces fluid filtrate invasion, contributing for the well’s integrity. When the drilling processes are over, this formation must be removed efficiently to allow for the primary cement jobs to be conducted efficiently, and for hydrocarbons to be produced without any restrictions. The removal process of the filter cake is challenging and requires specific techniques, depending on several factors including the filter cake homogeneity, drilling fluid components, weight of materials used, and the continuous phase of the drilling fluid (i.e., water or oil). This study evaluates the use of green biodegradable removal acid (GBRA) to dissolve calcium carbonate water-based filter cake. The removal efficiency of this new acid was analyzed using filtration and removal tests, conducted on a ceramic filter disc and real core samples at 212 °F. Then, the new formulation was subjected to physical properties measurements and biodegradation and corrosion tests. Furthermore, the performance of the new acid formulation was compared with 10 wt.% hydrochloric acid (HCl) to ensure its efficiency. The obtained results showed that the new acid formulation was effective at removing the filter cake, with a removal efficiency greater than 90%. The retained permeability was 100% and 94% with the ceramic filter disc and the real limestone core sample, respectively, confirming the good removal performance of the new acid formulation. The corrosion rate of GBRA (50 wt.%) at 212 °F was 0.032 lb/ft2, which was within the acceptable range according to oil industry practices (i.e., less than 0.05 lb/ft2 if the temperature is less than 250 °F), while HCl (10 wt.%) yielded a high corrosion rate of 0.68 lb/ft2.

Cement Sheath Failure Mechanisms: Numerical Estimates to Design for Long-Term Well Integrity

Well cement should provide structural support and zonal isolation through the entire service lifetime of a well. However, even if a good primary cement job is achieved, variations in temperature and pressure over the lifecycle of the well are likely to induce different failure mechanisms that threaten the set cement sealing integrity. This work presents an extensive finite element study with the aim to assess the relevance of casing-cement-formation material properties, geometric parameters and characteristic well-loading events, in contributing to the occurrence of cement sheath failure mechanisms. Special focus is given to thermal-related loading events. There is a discussion of main assumptions to describe and estimate the different cement sheath types of failure. A large number of test cases are defined on the basis of an automated sensitivity screening of random input properties of the wellbore components, in a conventional production casing section. The influence of casing stand-off positions and initial defects in the cement sheath are also evaluated. At the end of this paper, the approach is narrowed-down to be applied to a specific well case, in which the impact of transient well heating/cooling events on cement sheath integrity is assessed. Based on the results, guidelines for the assessment of long-term cement sheath integrity and selection of cement systems mechanical properties are given to mitigate the risk of losing zonal isolation.

Root-Cause-Failure Analysis as a Tool for Investigating Operational Failures: A Case Study

Summary Production-liner cementation in deepwater wells is critical to contain formation pressures and provide zonal isolation. This is especially challenging in the Gulf of Mexico (GOM) because of depleted zones and small drilling margins. Failure to achieve zonal isolation with the primary-cement job leads to added cost and time for remedial operations. A recent primary-cement-job failure in the GOM prompted the use of an established tool, root-cause-failure analysis (RCFA), in a novel way to identify the causes of the incident and avoid repeating the same mistakes in future wells. A team of operations and engineering personnel was assembled to investigate the cause of the primary-cement-job failure that resulted in nonproductive time and cost of approximately 7 days. RCFAs have typically been performed on equipment failures; however, this RCFA was conducted by the operator on a nonequipment-related failure. The RCFA team initially collected data available from both the planning and operation phases of the job to identify which elements of the cementing process contributed to the cement-job failure. After identifying the root cause, the team communicated their learnings to office and rig-based personnel; developed a new tool for real-time monitoring of primary cementation; and adjusted plans for upcoming primary-cement jobs. The findings from the RCFA were applied to a well on another asset owned by the operator, with which the production liner was successfully rotated throughout cementation for the first time. The RCFA identified that the cement-job design was not a contributing factor; instead, the root causes were operational and started during the circulation of drilling fluid, before the cementing operations. The learnings from the RCFA were transferred to both office and rig-based personnel, influencing engineering and operations plans for subsequent wells. Furthermore, the investigation identified previously unknown issues and showed that the use of the RCFA process was an effective approach that can be standardized and scaled to determine root causes of future operational failures.

Optimization of Cement Spacer Rheology Model Using Genetic Algorithm (Research Note)

The primary cement job is a critical step in successful well completion. To achieve effective cementing job, complete mud removal from the annular is recommended. Spacer and flushers are used widely to achieve this goal. This study is about weighted cement spacer systems containing a surfactant package, weighting agent and rheological modifiers. Weighted spacer systems are utilized when a high formation fluid pressure is expected inside the wellbore. A testing program is conducted in laboratory to determine the spacer fluid rheological properties in different temperatures. The measured rheological properties are estimated using the known rheological models. Each model is firstly optimized using Genetic Algorithm as an optimization tool and then the rheological properties are modeled. The performance of the genetic algorithm is then tested by comparing the real laboratory data and modeled data.

Experimental Study of Engineered Cement Plug to Effectively Cure Losses While Drilling in Iranian Oil/Gas Well

Mud losses are one of the most severe problems encountered in drilling. This is commonly known as lost circulation. It can occur in naturally fractured formations and also can be induced in formations through drilling. Mud losses while drilling leading to cost overruns and HSE concerns, primary cement job failure due to not getting the cement up to the desired height resulting in subsequent sustained casing pressure and corrosion, not able to perform work over activity on certain wells due to losses. The objective of this paper is to explain extreme lost circulation problem and introduce cement plug formulation to cure or mitigate this problem. In addition, the cement plug has certain compressive strength that this is proper for use to control lost circulation in field. And finally, the application of a cement plug is described in one well of the Gas Field (National Iranian Oil Company).

Coiled-Tubing-Deployed Shutoffs in Alaska With a Polymer Gel and Microfine Cement

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 173655, “Coiled-Tubing-Deployed Gas and Water Shutoffs in Alaska With a Polymer Gel and Microfine Cement,” by D.B. Robertson, SPE, BP; M.A. Brown, Petrotechnical Resources of Alaska; L.H. Duong, SPE, BP; O.V. Ivanova, Schlumberger; and A. Tambe, SPE, BP, prepared for the 2015 SPE Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 24–25 March. The paper has not been peer reviewed. A common problem in oil and gas wells is excess free gas or water production from only certain portions of the completed interval. A coiled-tubing-deployed profile-modification technique was developed primarily to shut off excess free-gas production from the heel of cased-and-perforated horizontal oil wells. The technique has also been used for water and gas shutoff in both vertical and horizontal wells in a variety of lower-completion types. Introduction Coiled-tubing work has a well- established track record in North Slope of Alaska oil fields involving several thousand interventions of various types. Fig. 1 is a photograph of a typical Arctic-winter coiled-tubing operation. Most of the approximately 1,700 wells in the Prudhoe Bay field penetrate either an extensive gas cap or the aquifer in the sandstone reservoir. Mechanisms for excess free-gas or water production can be related to poor primary-cement jobs of production liners, fluid-contact movements over time, coning, or corroded or damaged liners. In general, any through-tubing-profile modification that can be performed to reduce excess free-gas and water rates and increase oil rate or time on production is beneficial to overall field production. With many candidate wells, there has been a continuous evolution in job design and execution techniques over the years.

Investigation and remediation of active-clay contaminated sepiolite drilling muds

Unconventional gas and oil development has gained remarkable attention in recent years. However, the high content of active clays in shales makes drilling difficult. Since most formations drilled for oil and gas exploration are shales, active solid dispersion into the drilling mud is a common problem. This might results in severe problems, such as stuck pipes, circulation loss, excessive torque and drag, inadequate cuttings transport, poor log quality, poor primary cement job, and borehole instability.In this study, active clay contamination effects on sepiolite drilling muds were experimentally investigated for hostile drilling conditions. Rheological properties of both unweighted and barite-weighted sepiolite drilling muds with and without sodium chloride additions were tested at ambient to 204°C temperatures. Filtration loss properties were determined at a 0.689MPa pressure differential. The drill-hole cleaning efficiency of sepiolite drilling muds was investigated too. Methylene blue tests were also performed to determine the tolerance of sepiolite muds to solids accumulation.Major findings of this study inferred that sepiolite drilling muds formulated in a certain mixing order of additives provided effective rheological properties and water loss. Acquired results of methylene blue test and sufficient annular velocities for all samples strongly supported availability of these muds against active-clay contamination which is the special emphasis of this study. This is also particularly important for expensive high-angle and extended-reach wells.

Drilling and Completing Cascade and Chinook Wells: A Case History

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24179, ’Drilling and Completing Cascade and Chinook Wells: A Design and Execution Case History,’ by Flavio Dias De Moraes, Petrobras; Oswaldo Moreira, Petrobras America; Ziad Haddad, FOI Technologies; Scott Ogier and Jonathan Shipley, SPE, Cherokee Offshore Engineering; Mauricio Rebelo, Petrobras; and Fernando Gama, Petrobras America, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed. During the design, implementation, and operation of the Cascade and Chinook (C&C) field development project in ultradeep water in the Lower Tertiary play of the Gulf of Mexico (GOM), the technical limits of single-trip multizone (STMZ) frac-pack systems were pushed to depths greater than 27,000 ft using high fracture rates and high-strength proppants; knowledge was gained from ultrahigh-pressure (greater than 20,000 psi) tubing-conveyed perforating systems; and well-design criteria suitable for high-drawdown (more than 12,000 psi) production operations were demonstrated. Introduction The C&C development plan in the GOM is one of the most technologically challenging and complex projects ever implemented by Petrobras. This project uses the first floating production, storage, and offloading vessel in operation in US waters at a water depth of 8,200 ft. The C&C subsea infrastructure considers the use of subsea manifolds, rigid flowlines, pipe-in-pipe pipelines, and freestanding hybrid risers. These two fields are 15 miles apart and share several characteristics such as depth, lithology, and reservoir similarities. The Wilcox 1 (Eocene) and 2 (Paleocene) sands belong to the Lower Tertiary geologic period and are part of the latest exploratory frontier in the GOM. At least 12 discoveries have been made in the Lower Tertiary, holding a potentially recoverable volume of several billion bbl of oil, highlighting the importance of this technology development for the industry. These reservoirs are characterized by a considerable thickness of intercalated sandstones and shales. The reservoirs show low horizontal permeability (less than 100 md) and poor vertical communication between sand layers. Other characteristics include a very high static formation pressure, a maximum temperature of 256°F, and a low gas/oil ratio. The produced oil has carbon dioxide concentration in the gaseous phase of less than 1.5%, and there is no evidence of hydrogen sulfide contamination. Drilling Design The casing design was based on delivering an 8½-in.-internal-diameter casing at total depth (TD) to accommodate the completion design. In this design, each string is run to its approximate design limit to maximize leakoff-test (LOT) values. One of the most important strategies of the C&C wells was the elimination of the 11⅞-in. liner, which prevents achieving adequate circulation rates for a successful primary cement job on the 10⅛-in. production casing.

Numerical simulation of Sector Bond log and improved cement bond image

The two principal functions of a primary cement job are to provide support for the casing and to provide hydraulic isolation between zones. A poor cement job may cause many issues during the well production. Therefore, cement bond evaluation is very important in well completion. The Sector Bond log (SBL) has been widely used for cement bond evaluation for years. The SBL tool has eight pairs of directional transmitter-receivers, which are equally distributed in azimuth and used for identifying channels and channel azimuths. To better understand SBL, using a parallel 3D finite difference algorithm, we numerically simulated acoustic responses of the SBL under a variety of cement bond scenarios and investigated the sensitivity of the integral amplitudes to channel size and its azimuth. We further developed a new approach to image potential channels in cement annulus using the integral amplitudes. The comparisons between conventional SBL images and the reprocessed ones using the new approach showed significant improvement on both synthetic and field data.

Understanding the long-term chemical and mechanical integrity of cement in a CCS environment

Portland cement can play a major role in providing cost-effective, long-term zonal isolation for CO2 capture and storage (CCS) used to mitigate climate change. However, achieving zonal isolation with Portland cement under supercritical CO2 environment for the required 1,000 year trapping period may be challenging. Some laboratory researchers report that Portland cement disintegrates when exposed to CO2, leading to potential leakage into the atmosphere or other to underground zones. Other researchers cite Portland cement samples from 30–50 year old CO2 EOR wells where sealing integrity was maintained, even though carbonation was found. In this paper we will discuss reasons likely for this disparity between research lab test results and actual well performance data. Carbonation of Portland cement is a thermodynamically favorable process and therefore difficult to avoid. But the effects can be minimized by various reactive chemical components optimized for the specific thermodynamic conditions. Our research shows partial carbonation of Portland cement is not detrimental unless the mechanical integrity is insufficient to provide effective zonal isolation. For these studies we have developed CO2 treatment test cells capable of producing conditions up to 200 °F and 2,000 psi. In addition, various analytical instruments including x-ray diffraction (XRD), thermo-gravimetric analysis (TGA) and mechanical properties measurement devices have been used for this study. In this paper we will discuss the importance of understanding the percentage of carbonation and depth of CO2 penetration, and how to control these factors by optimizing the cement blend. Interestingly, we found the amount of Portlandite { Ca(OH)2} that forms due to cement hydration and the cement-to-water ratio dictates the depth of penetration as well as percentage carbonation. The implications of this in relation to the long term chemical integrity of the cement sheath under downhole CCS conditions is discussed. This paper also includes the results of recent studies on the changes in mechanical properties of a properly optimized Portland cement blend for a period of up to one year. During this period, measurements were made at different time intervals to examine cement specimen treated with CO2 at 200 °F and 2,000 psi in the presence of water. The results show carbonation without any sign of loss of mechanical or sealing integrity that could lead to zonal isolation failure. Results from a separate set of experiments show the following: (1) Carbonation could be minimized by reducing the Portland cement content by adding Pozzolanic materials and by reducing the permeability and (2) Carbonation could help heal micro-cracks that may be caused by various well operations or ageing. However, such carbonation-induced healing is limited only to a certain width of cracks. In summary of this research, it is recommend that: (1) a high quality primary cement job be performed in adherence to all industry best practices; (2) the cement blend be properly optimized to minimize long-term CO2 corrosion; and (3) the sheath be designed for long-term mechanical integrity. This paper will discuss a comprehensive approach that may be taken to help ensure longer-term effective zonal isolation in new CO2 wells and remedial solutions for old wells and for plugging and abandoning wells.

Thermal Sealants Improve Cementing in SAGD Areas

Abstract With the high demand for oil and gas, operators are becoming increasingly interested in unconventional sources of hydrocarbon. One of the major sources in the world is heavy oil, which has been defined by the API as oil that has API gravity of less than 22.3 °API at 15.6 °C (60 °F) (extra heavy oil, or bitumen, has 10 °API or less). Because heavy oil does not flow on its own in the wellbore, a mechanism must be used to recover the oil by making it mobile. Among the different experimental and operational methods, steam-assisted gravity drainage (SAGD) has been the method of choice for the past few decades. This process uses steam to heat the immobile oil and reduce its viscosity so it can be extracted, usually by using pump jacks. These heavy oil wellbores need to be zonally isolated to help ensure that the reserves are produced properly without environmental or production optimization challenges. In Alberta and Saskatchewan, many wells are drilled and cemented in designated heavy oil fields where SAGD is applied to stimulate production. Most of these wells are successfully cemented, however, some wells experience zonal isolation failures that result in steam breakout or steam loss into non-targeted zones. While the problem may be related to the primary cement job, it may also have been created by post-cementing operations and/or conditions. Sometimes the problem may be temporarily solved by conventional methods, however, the ultimate remedy may have to be applied eventually. The long-term integrity of the cement sheath behind the casing should be planned with drilling, completion, production/injection and abandonment stages considered. A properly designed and engineered cement slurry system can help save a wellbore/field from additional unplanned expenses. The process is shown below:Cement slurries are designed under defined wellbore conditions and exposed to field conditions in the laboratory.The mechanical behaviour of the cement sheath under downhole conditions is studied using three-dimensional, finite element analysis software.The endurance of the cement sheath under applied conditions is predicted and optimized.Operation and placement of the selected slurry is studied to help ensure optimum execution. Stresses exerted on the cement sheath from wellbore operations during construction, injection or production that could damage the cement sheath are integral to the study. These conditions are analyzed to help engineers understand the post-cementing operational effects on the sealant system. This paper presents the design criteria for finding the fit-for-purpose sealant systems that can successfully protect wellbores under harsh environmental conditions of SAGD and cyclic steam stimulation (CSS) operations. Introduction The long-term integrity of a cement sheath throughout a well's life is the ultimate factor for determining whether the sealant will withstand the planned operations, production and injection that are planned for the well. In the case of heavy oil operations, the primary design considerations for a long-lasting sealant are the temperature and pressure regimes. The stresses caused by the extreme changes are exerted on casing, cement and the rock.

Liner Completion Difficulties Resolved With Expandable Liner Top Technology

Abstract Liner top packers, which are run as a standalone unit or integrally with conventional liner hangers, are set through the application of weight applied through the drill pipe or landing string. The capability of the liner top packer to seal at the stated pressures rated for which they are designed requires that a sufficient setting force of up to 355857.7 N (80,000 lbf) be applied through the drill pipe to the packer mechanism. Recently, work performed by an operator in Latin America showed the limitations of this process when used in shallow liner top installations where the available string weight alone to apply a sufficient setting force to the liner top packer is not available. Picking up a string of large drill collars in order to have the capability to supply the significant setting force required was an alternative. However, it was not a preferred option, safety being the main concern, followed by handling time, as was seen on the first well utilizing conventional liner hanger and liner hanger packer technology. The expandable liner hanger (ELH) was developed as a solution to resolve the problem of weight down required to set the liner top and allowing a setting force to be applied to the packer elements locally through the hanger body with the use of hydraulic pressure. The setting force for the packer is measurable and consistent, ensuring that a liner top seal and hang weight is obtainable without requiring weight down. This system contains no moving parts, which makes it possible to function with a drill string. Once deployed in the well, the liner hanger body expands radially through the pressurization of its elastomeric elements, thus, creating a gas-tight seal and achieving zonal isolation. The operator chose to deploy the expandable liner hanger system on two subsequent wells following the initial attempt to utilize a conventional system approach. The ELH installations were successful, saving the operator several days of rig time on each well. The case study discussion and system description presented in this paper will explain the flexibility and integrity of the expandable liner hanger in providing a liner top seal upon setting in a shallow liner top installation. Introduction Historically, problems obtaining a good primary cement job at the top of the liner have been associated with the installation of liners in oil and gas wells. Conventional liner hanger systems have relied upon the primary cement job to provide liner top pressure sealing integrity within the liner/casing overlap. In many wells however, cementing the complete liner and liner lap is often not achievable due to various problems, which include loss of circulation, fluid loss or other wellbore/formation conditions. In cases like these, obtaining a primary cement seal across the liner lap is not obtainable, and a liner top packer must be deployed on a second run to make the primary liner the top seal.

Magnolia Deepwater Development- Striving for Best-in-Class Drilling Performance

Summary ConocoPhillips is developing the Magnolia field with a Tension Leg Platform (TLP) in 4,674 ft of water at Garden Banks (GB) block 783 in the Gulf of Mexico (GOM) (see Fig. 1). The field was discovered in 1999, and appraisal wells were drilled in 2000 and 2001. The well-construction strategy included drilling six additional development wells from a mobile offshore drilling unit (predrilling) before the installation of the TLP. Drilling the new wells consisted of two phases: batch-setting all six wells through 20-in. casing, followed by deepening the wells to a total depth (TD). The wells targeted multiple zones resulting in complex, designer directional wells with 50° to 60° maximum hole angles. This paper examines the application of drilling best practices used to deepen the wells to TD after batch-setting operations were complete (Eaton et al. 2005). To minimize drilling costs while deepening the wells to TD, project goals were to eliminate trouble time; minimize combined drilling, circulating and tripping time per interval; maximize simultaneous activities; and reduce the number of trips necessary to drill the well. The goal of achieving Best-in-Class performance requires detailed planning, documenting, and implementing of results and lessons learned; effective communications; equipment quality control; and implementation of a team environment with all the companies involved in the drilling program. The complex high-angle wells require employing extended reach best practices to balance on-bottom drilling performance with the ability to effectively clean the hole to enable trouble-free tripping of the bottomhole assembly (BHA), running of casing, and obtaining primary cement jobs. The best practices discussed in this paper include changes made to improve rotary steerable reliability; simultaneous drilling and under reaming BHA design (Eaton et al. 2001); hole cleaning; and torque and drag monitoring. The paper also discusses activities that reduced the number of required trips and activities conducted out of critical path, such as moving the subsea blowout preventor (BOP) from wellhead to wellhead with an innovative BHA, a BHA to run and retrieve wear bushings, subsea guidebase installation by way of a winch and remote operated vehicle (ROV), off-critical-path makeup of BHA components, and drillstring management.

The Use of Lightweight Cement Slurries and Downhole Chokes on Air-Drilled Wells

Summary The success of a primary cement job is often measured according to effective zonal isolation, achieving the designed top of cement, and avoidance of remedial cementing. In the San Juan and Rio Arriba counties of New Mexico, many Mesa Verde and Dakota wells are air-drilled because the Mesa Verde formation is subnormally pressured and naturally fractured. This combination makes the Mesa Verde easy to hydraulically fracture during normal drilling and cementing operations. Therefore, meeting the primary-cement-job success criteria is particularly challenging. Cementing of casing within an air-drilled wellbore allows the slurry to free fall. Cement free fall can cause severe surge pressures at the bottom of the hole, leading to hydraulic fracture initiation and loss of lift. Theuse of a downhole choke (DHC) can be employed to prevent these processes from occurring. Because mud filter cake does not exist in an air-drilled hole, the lead water spacer and cement must wet the casing and wellbore rock surfaces. Loss of the lead water spacer, in conjunction with cement water loss, can produce dehydration of the cement column, leading to an increase incement viscosity and equivalent circulating density. Careful control of cement-free water and fluid loss are required to prevent this from occurring. Further more, placing cement across targeted completion intervals that have low fracture gradients requires the use of ahigh-compressive-strength, low-density cement that is competent and capable of maintaining zonal isolation during the completion and production phases of well construction. This paper will outline the evolution of the cementing practices used forthe Mesa Verde and Dakota wells drilled in the 29-6 Unit (T29N−R6W, New Mexico) from 1998 to 2002. It will illustrate how cementing changes enabled the primary cementing to be successfully completed in a single stage instead of two, which has translated into cost savings for both the drilling and completion phases of a well. The impact of using a DHC for the pumping and placement of these primary cement jobs will be illustrated and discussed. The function of the cement additives on slurry properties will also be discussed as they pertain to these cement jobs.

Service Providers Adapt to Industry Changes

Competition for the award of service contracts in the oil field always has been fierce, but the criteria for gaining and maintaining the confidence of operators are changing. Service quality on a well-by-well basis is still important and will remain so, but the definition of outstanding performance has enlarged considerably. Successful operations do not start on the spud date—they arise from collaboration between the service provider and the operator, beginning with project planning and carried on throughout the well-construction process. Service companies have concentrated on producing the new technologies that operators need to meet operational challenges. An unusual number of breakthroughs have occurred in the last few years that have made it possible to drill in areas that were once almost completely off limits operationally and economically. These technical successes help exploit new and marginal reserves without budget-breaking expenditures. These breakthrough products and services are not just commodity items that get the well down. In our fluids division, most—if not all—of the advanced technologies significantly improve wellbore quality and extend the life of the well. Service providers are living up to a commitment to help operators cut costs while achieving top drilling performance, and operators should consider the real economic value represented by such breakthroughs when they come to the bargaining table. The need to minimize environmental impact also has influenced product development. Our industry is seeing an increase in positive engagement with governments and regulatory agencies. Understanding their concerns allows us to design materials and procedures that safeguard natural resources and communities. The industry has done a good job of showing the public the precautions it has taken on behalf of the environment. Not too long ago, many people believed that drilling performance had to be sacrificed to achieve environmental compliance, but that perception is being left behind. Safety and environmental protection are the bywords for oilfield operations anywhere in the world. High-performance systems and technologies can be used safely at just about any drilling location in the world, but getting the most from these new technologies takes a new approach. Service companies have to foster cross-discipline collaboration among their various functions. The best results come from clear alignment of goals and proper job design, in which the various teams involved share best practices, sophisticated modeling software, lab capabilities, and field expertise. That is what it takes to make sure conditions are optimal for the operation at hand. For example, good drilling practices executed by drilling fluids and directional drilling personnel make it possible to run casing to bottom with minimal flat time. Further, the conditions of the drilling fluid and the wellbore have a huge impact on the success of the primary cement job for that casing string. This cross-discipline approach has to go one step further at times—a service provider may be working alongside a competitor. Even then, our objectives remain the same: reduce costs, minimize nonproductive time, and increase the productive life of the well. When we succeed at that, no matter the circumstances, service providers earn the confidence of operators.

Reduction of Surface Casing Vent Leaks In Viking/Kinsella, Alberta Using Improved Drilling And Cementing Techniques

Abstract Surface casing vent leaks (SCVLs), subsequent to production casing cementation, became a serious concern in the Viking/Kinsella area. The gas sand formations responsible for the SCVLs were relatively shallow, low temperature, and overpressured. Drilling angled wells from pad locations increased the possibilities of SCVLs due to the difficulty in obtaining a good primary cement job. Conventional drilling and cementing practices did not prove effective in reliably preventing environmental liabilities were incurred. PanCanadian Petroleum Ltd. Has implemented a number of drilling and cementing "good practices" to reduce SCVL incidents. The changes in drilling and cementing practices and materials have resulted in a significant reduction in the number and severity of SCVLs. Introduction The main objective of a successful primary cementing operation is the complete displacement of drilling fluids and solids from the drilled hole/casing annulus with a competent cement slurry designed for area specific concerns. Industry research and experience has shown that even a properly designed cement slurry cannot provide an effective hydraulic seal if contaminated with drilling fluids or solids, or if a channel through the cement exists. Drilling practices have an impact on the quality of the wellbore to be cemented, as well. This paper addresses the changes in drilling practices and cement design established to eliminate surface casing vent leaks (SCVLs) at the PanCanadian Viking/Kinsella development project. Background The Viking/Kinsella field is located 20 km northeast of Viking, Alberta, in TWP 47 RGE 9 W4M. PanCanadian's wells in this field historically suffer from poor zonal isolation and high frequency of SCVLs. A SCVL is defined as any measurable flow or pressure build up of gas, water or hydrocarbon liquid on a vent on the surface casing bowl(1). This paper specifically refers to SCVLs from gas sources. The source formations (Figure 1). PanCanadian set a goal to eliminate all SCVLs in an effort to reduce well lifecycle cost in the area. PanCanadian utilizes slant well pad drilling in the Viking/Kinsella area to reduce:Capital costs when compared to directional drillingOperating costs; maintain fewer leases and facilitiesWell production operating costsEnvironmental impact by minimizing surface land requirements A typical well configuration consists of: Equations (available in full paper) The operational issues that were addressed in the drilling and cementing of the slant wells in the Viking/Kinsella are:Complete removal of drilled solids from hole,Optimal casing centralization, andOptimal slurry design Mechanical Considerations Numerous cementing techniques have been considered throughout the industry to combat SVCLs, all with limited success. They include:Applying additional pump pressure from surface to compensate for hydrostatic losses due to slurry gelation,Placing a fast setting cement at surface and "pancake" squeezing a slower setting slurry into the gas zone, orInflating an external casing packer at the surface casing shoe to provide a mechanical barrier to gas flow.

Inflatable Casing Packers-Expanding The Limits

Gas migration, inter zonal water flows, and cementing low frac gradient wells remain some of the biggest completion problems facing the oil and gas industry today. These are zone isolation issues for which operators used to count on the primary cement job alone to address. Operators and cement service companies valiantly tried many techniques to improve zone isolation including multiple scratchers and centralizers, improved mixing systems, altering flow rates, stage systems, reduced weight and high early gel strength cements and additives for fluid loss control. Still, operators were frequently required to conduct costly remedial cementing operations to correct zone isolation problems (microannulus, channeling, hydrocarbon contamination of cement, thief zone isolation, etc.), after primary cementing. Inflatable casing packers (inflatables) were designed to address these zone isolation problems and were first run in the early 1960s. They have since become a standard part of the casing string for many operators as a technical addition to conventional cementing. Inflatables have an external element that is inflated with cement, mud, brine or produced fluid to provide a positive mechanical seal between the outside of the casing and the wellbore. Inflatables can be placed above or near the critical zone in question or in the lap of the liner to help eliminate these costly zone isolation problems. Zone isolation in a well does not require that the annulus be completely filled with cement. An inflatable effectively seals the annulus resulting in a reduced or eliminated need for a cement column. Using an inflatable within the cement column results in a non-channeled section of cement immediately below the element. This phenomenon is the result of the inflate element's expansion in the cement column. The net result of these is a superior completion and a cost saving and, since the cost of the packer, in most cases, is substantially lower than the cost of cementing materials, equipment and service. Most horizontal wells today are produced via open hole techniques which do not easily allow for control of sections that are producing water or unwanted gas. The lack of isolation also limits the ability to clean up the hole and conduct remedial stimulation prior to production. Other factors such as changing permeability and variations in reservoir pressure can result in production losses. Inflatables are increasingly used to isolate sections of the horizontal hole to overcome these limitations. Large scale manufacture, sale and service of inflatables started in the early 1980s with several companies producing a variety of sizes, ranging from 2 3/8 inch to 20 inch, and lengths ranging from three feet to 40 feet. How well have these inflatables performed? Two initiatives are underway to explore the application of inflatables. In the early 1990s British Petroleum recognized that with the increasing number of horizontal wells being drilled around the world and with the take off of multi-lateral wells, there was a strong case for examining the effectiveness of inflatables. In 1994 BP Exploration Technology Provision completed an investigation into the effectiveness of inflatables based upon the combined worldwide experience of BP and ARCO Alaska.

Improved Primary Cement Jobs With a Unique Spacer Design

This article is a synopsis of paper SPE 36486, "Improved Primary Cement Jobs Through the Use of Unique Spacer Design Technology: Gulf of Mexico Case History Study," by J.P. Schumacher, SPE, R.W. Bell, and S.E. Morrison, Vastar Resources, Inc., and A.F. Chan, SPE, and R. Wydrinski, SPE, Arco E&P Technology, originally presented at the 1996 SPE Annual Technical Conference and Exhibition held in Denver, Colorado, 6-9 October.

Advances in Cement-Plug Procedures

Operators set cement plugs for a variety of reasons: abandonment, sidetracking, lost-circulation control, or remedial work. However, as important as plug cementing can be to the overall success of a well program, the process often is performed without regard to wellbore conditions. The additional rig time and material costs quickly add up as multiple plugs are set. The industry average is approximately 2.4 attempts per kickoff. Studies have highlighted many of the problems encountered in plug cementing. Implementation of systematic, controlled procedures has established a near 100% success rate where used for establishing kickoff plugs. Recommended Plug Procedure Recent work has determined that cement plugs require the same degree of planning as primary cement jobs, plus special considerations for plug stability. A joint team of operators and a cementing service company evaluated the problems and mechanics of plug cementing. The team developed a recommended plug procedure (RPP) to alleviate problems. The procedure provides a reliable plug-setting procedure and develops a method to monitor success rates. The RPP addresses communication, temperature estimation, mud removal, slurry design, slurry volume, and plug stability. Understanding the relationships between these variables is vital to the success of spotting a balanced cement plug. Job Design Communication. To design a cement-plug job properly, communication among all personnel responsible for the job design is essential. It is important that personnel discuss options for each job so that assumptions are not made about equipment availability and/or capabilities. Sharing data from the field is also important. Detailed pre-/postjob data sheets have helped to build a database that has been instrumental in finding the causes of both successes and failures. Temperature Estimation. One of the most important design variables is placement time, which is governed by pumping rates and bottomhole circulating temperatures. In most cases, little attention is paid to plug-cementing temperatures; most laboratories use published cementing schedules. At times, temperature estimates are also adjusted upward to increase the safety factor, resulting in over-retardation. The use of computer simulation or temperature surveys for temperature predictions can help ensure that the slurry will not be over-retarded. Also, a more realistic waiting on cement (WOC) time can be estimated if compressive-strength thermal-recovery schedules are slow enough to match wellbore conditions, reaching American Petroleum Inst. bottomhole static temperature only after 24 to 36 hours have elapsed.