External Casing Packers Research Articles

Testing and Evaluation Method Investigates Cement Expansion in Cased-Hole Wells

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 208679, “Cement Expansion in Cased-Hole Environments: A Novel Laboratory Testing and Evaluation Method With Successful Field Implementation,” by Vasilii Sukhachev, Amir Salehpour, SPE, and Ilshat Akhmetzianov, SPE, Schlumberger, et al. The paper has not been peer reviewed. Preventing bulk shrinkage of cement in cased-hole wells is important when dealing with the risk of sustained casing pressure (SCP). Current studies based on membrane tests suggest that, even with a high-percentage content of expanding agents, cement systems show little or no expansion in dry media. An alternative laboratory method for measuring cement expansion, followed by a successful field application, was used to evaluate the total bulk volume change of the cement based on curing in a dry environment and in water. Optimal cement-slurry properties were obtained. The developed cement system, which was successfully implemented in the field, provided long-term zonal isolation with no indication of SCP to date. Introduction For a major operator in the Caspian region, drilling development wells required passing through shallow overpressured permeable zones containing water and biogenic gas. The optimal casing design used to minimize the likelihood and severity of SCP consisted of isolating the shallow-soil zone by use of a cemented 24-in. liner followed by a 20-in. surface casing cemented using a two-stage method (Fig. 1). During the first stage, the cement was pumped inside of the 24-in. liner. Then, an external casing packer placed in the 20-in. casing was inflated against the 24-in. liner before performing the second-stage cement job. The second-stage cementing operation brought the cement above the top of 24-in. liner and provided sufficient length to isolate against the shallowest distinct permeable zone. Cement is considered a primary wellbore barrier element. However, the cement placed between the 24-in. liner and the 20-in. casing and in the annulus of the 30-in. conductor and 20-in. casing is subject to shrinkage. This shrinkage leaves a potential leak path all the way to the wellhead on an offshore platform. The cement systems chosen consisted of the 1.92-SG (16-lbm/gal) slurry for the second stage cementing of the 20-in. casing because this stage was the system most susceptible to shrinkage. This slurry was placed in the annular space of the 20-in. casing and both the 24-in. liner and the 30-in. conductor. The curing temperatures and pressures in the field are 32°C and 6.74 MPa at the bottom of the well and 28°C and 2.48 MPa at the top of the cement. The top of the cement will be in direct contact with the spacer, a fluid with 89% water content; however, the remainder of the cement column will not have access to excess water during curing. If acceptable results could be achieved with the 1.92-SG cement system, then the same blend could be used for the 24-in. liner tail and the first-stage tail slurry of the 20-in. casing. This method is a possible solution to obtain a more-robust system that prevents the risk of SCP.

Flow simulation for a horizontal well with slotted screen and ICD completions based on the wellbore–annulus–reservoir model

A flow is observed in the pipe for the horizontal section of slotted screen completion and inflow control device (ICD) completion, and an annulus flow exists between the pipe and the borehole wall. Based on the principles of mass conservation and momentum conservation, a model for variable mass flow in an oil reservoir to simulate wellbore–annulus–reservoir state in the horizontal section of slotted screen completion and ICD completion is proposed. Consequently, based on the newly established formation transient seepage model and wellbore and annulus variable mass flow model, an accurate prediction of the production rate of a horizontal well as well as optimized design parameters for slotted screen completion and inflow control device (ICD) completion are achieved. The predicted flow profiles of the established model are confirmed using the simulation software from Computer Modeling Group Ltd. When external casing packers are not considered, findings show that the predicted production rates of both slotted screen completion and ICD completion, which are obtained using the variable mass flow models without annulus flow modeling, are higher than the rates obtained using the variable mass flow models with annulus flow modeling. Both models show that the pressure profile and flow profile of the borehole wall are more uniform in wellbore–annulus–reservoir in horizontal wells. The flow model for horizontal wells with annulus flow modeling should be established to improve the accuracy of the predicted production.

Flow Simulation of a Horizontal Well with Two Types of Completions in the Frame of a Wellbore–Annulus–Reservoir Model

Well completions are generally used to connect a reservoir to the surface so that fluids can be produced from or injected into it. With these systems, pipe flows are typically established in the horizontal sections of slotted screen completions and inflow control device (ICD) completions; moreover, an annular flow exists in the region between the pipe and the borehole wall. On the basis of the principles of mass and momentum conservation, in the present study, a coupling model considering the variable mass flow of the central tubing, the variable mass flow of the annular tubing and the reservoir seepage is implemented to simulate the wellbore–annulus–reservoir behavior in the horizontal section of slotted-screen and ICD completions. In earlier models, only the central tubing variable mass flow and reservoir seepage flow were considered. The present results show that the closer the heel end, the greater is the flow per unit length in the central tubing from the annulus. When external casing packers are not considered, the predicted production rate of the slotted screen completion, which is obtained using the variable mass flow model not taking into account the annulus flow, is 9.51% higher than the rate obtained using the (complete) model with annulus flow. In addition, the incomplete model forecasts the production of ICD completion at a 70.98% higher rate. Both models show that the pressure profile and flow profile of the borehole wall are relatively uniform in the wellbore–annulus–reservoir in horizontal wells.

U-Shaped Re-Entry Drilling Revitalizes Depleted Reservoirs Offshore Congo

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191436, “Extended-Reach U-Shaped Re-Entry Drilling in Shallow, Depleted Fractured Reservoirs in Congo’s Oldest Offshore Oil Field,” by Mike Tony Chembou, Bruno Valeri, Lois de Crevoisier, Michel Akue, and Vincent Rodet, Perenco Congo, and Gabriele Ghia, Achille Mouamba, and Ali Lazzem, Schlumberger, prepared for the 2018 SPE Annual Technical Conference and Exhibition, Dallas, 24–26 September. The paper has not been peer reviewed. Against the background of a low-oil-price environment, a redevelopment project was launched to give a second life to a shallow, depleted, mature offshore Congo oil field with viscous oil (22 °API) in a cost-effective manner. The solution selected was to drill U-shaped side tracks (inclination at total depth=115°) from the original boreholes on an existing platform at a water depth of 60 m. The objective was to create a second drainage area. The project team used innovative, low-cost techniques to overcome many challenges. Geological Context and Objectives Under 27 platforms (four to five well-heads each), an accumulation of heavy, viscous oil is trapped in three reservoir layers. The field was produced with a combination of cold mode followed by a period of hot mode from steam injection. The consequence is a depleted (0.3-sg) and highly steam-fractured reservoir where fluid loss presents one of the primary challenges for infill development. The pilot project consists of re-entering the current producers and then deepening them in a U shape to access the same shallow reservoirs more than 200 m away from the initial production leg. All reservoirs share the same water table identified below an impermeable formation underneath the target layers. To avoid water breakthrough, the trajectories were planned with up to 18°/30 m to prevent the well from entering the water-bearing layer, with minimum 30-m true vertical depth standoff from the oil/water contact. Well Design and Architecture The well architecture is selected to match the existing mother-well construction. All selected re-entry candidates are producing wells showing the following well architecture: 9 5/8-in. casing set as intermediate casing at approximately 100 m measured depth (MD) below the rotary table A mixed string composed of cemented blank 7-in. casing and uncemented 7-in. slotted liner in front of the pay zones. An external casing packer (ECP) was installed between the two strings, and a cementing job was performed above the ECP. The float shoe at the bottom, therefore, was uncemented and prone to be untorqued during re-entry The completion system consisted of progressive-cavity-pump or sucker-rod-pump strings, depending on the wells. To fulfill the geological and reservoir objectives, the wells were re-entered by drilling a 6-in. hole section from a 7-in. float shoe to the U-shaped total depth before a 4½-in. liner was run. The sand-face completion evolved slightly from the first two wells (blank perforated) to the last three wells (slotted liner).

Technology Update: Characterizing a Coal-Seam Gas Reservoir by Interpreting Permanent DTS Data

Technology Update In Australia’s Surat Basin, gas is contained in hundreds of coal seams, which have highly variable properties and are grouped into four distinct reservoir zones of similar qualities. Economically producing these wells from multiple reservoir units is generally favored and as a result, understanding the relative contribution to production by different zones at different times in the well’s life—and whether production is dominated by a single zone—adds value to planning future wells. The well designs are quite simple. An 8.5-in. wellbore is drilled from surface casing through the target coal seams. A 7-in. production casing and preperforated liner with an external casing packer and a cement stage tool is run to total depth. The external casing packer is deployed at the top of the reservoir, and the 7-in. casing is cemented in place through the stage tool above the packer. No external packers are installed between groups of coal seams (zones) to segregate production from each zone through the preperforated liner. Production tubing is installed in the well, which typically runs to the base of the preperforated liner, and a progressive cavity pump (PCP) is installed in the tubing to lift the water produced with the coal-seam gas (CSG) [dewater the well]. Gas production comes from the coal seams and flows around and through the preperforated liner, then up through the annular space, between the production liner/casing and the production tubing, to surface. The water flows to the bottom of the completion, where it is lifted up the production tubing by the PCP as shown in Fig. 1. Understanding Zonal Allocation Normally, production logging tools (PLTs) are run to obtain an understanding of zonal allocation in commingled wells. However, running PLTs in CSG wells can be expensive as it requires the PCP to be pulled out and the well to be lifted with gas. The switch to gas lift at shallow depth is not a normal operating condition and may affect the result. An additional issue is the unsegregated, openhole completion. With no external packers, neither the PLT tools nor the distributed-temperature sensor (DTS) fibers inside the liner can measure flow in the space between the liner and the sandface.

Deepwater Gas-Zone Shutoffs With Wireline in Openhole-Gravel-Pack Completions

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 170789, “Deepwater Gas-Zone Shutoffs With Wireline in Openhole- Gravel-Pack Completions,” by Claudia Zettner, Hank Bensmiller, and Tom Lane, ExxonMobil, prepared for the 2014 SPE Annual Technical Conference and Exhibition, Amsterdam, 27–29 October. The paper has not been peer reviewed. An operator successfully executed two wireline through-tubing gas-shutoff (GSO) workovers in high-angle openhole-gravel-pack (OHGP) completions to isolate high-gas/ oil-ratio (HGOR) zones, resulting in significantly increased oil production. This paper summarizes the GSO concept, completion modeling, job planning, completion-equipment testing, job execution, and production results from one of these two wells (the processes and results associated with the second well are detailed in the complete paper). Introduction All producers in the field of study were drilled from a 36-slot tension-leg platform (TLP) at a water depth of just over 1000 m. OHGPs are the preferred completion option in this field. It was recognized during the project-design phase that controlling unwanted gas and water in the future would be challenging. The well-work solution proposed and described in this paper can address that challenge by providing lower-GOR oil and additional reserves recovery. Although the long-term depletion plans for most reservoirs in the field rely on waterflooding, some producing reservoirs have been used to store surplus gas until gas-export facilities were operational. As these injected gas caps expanded toward producers, GORs increased to the point at which processing facilities were gas constrained. Producer-well seriatims made on the basis of GOR are used to optimize oil production. The highest- GOR wells are typically cycled to manage GORs and then shut in when cycling is no longer effective. Engineering principles and field experience have shown that gas breakthrough in any zone in a well can affect overall production significantly. High gas mobility, coupled with good injection support in the gas-producing interval, can result in an HGOR, and thus a noncompetitive, producer. The completion diagram in Fig. 1 illustrates the general design of the lower completion. External shunt tubes prevented external casing packers (ECPs) on early wells. Later wells have internal shunt tubes that allow ECPs in the gravel-packed section of the well. Completions include gravel packs to minimize sand production from the unconsolidated reservoirs. Gravel-pack screens are shunted to help ensure gravel is transported and placed along the length of the screen. Gravel placement is generally effective, and sand production is rarely a problem in this field. Oil producers are directionally drilled because most reservoir objectives are not directly underneath the TLP. Reservoir penetrations are often at a high angle from vertical to provide the permeability thickness necessary to deliver target rates.

Technology Focus: Cementing/Zonal Isolation

Technology Focus In 2015, more papers were devoted to well construction in shale plays than in any prior year. Those shale topics also covered a diverse range of subjects within the sphere of optimizing construction efficiency and performance. Our industry’s demonstrated ability to innovate and continually improve well-construction technology will be all the more valuable to all plays if low oil prices persist, but especially so for shale and other high-cost-per-barrel plays. With rig counts decreasing, smart, effective workovers of existing wells will be even more important to maintaining production levels. Some examples of effective construction and workover techniques are provided within the papers provided here. I hope you find them of interest. In paper SPE 170789, I was surprised to see the level of production improvements achieved with the use of wireline stackable straddle systems. This was accomplished in an openhole gravel-packed completion without external casing packers or consolidation of the gravel pack, a significant simplification. Paper SPE 171015 is a good example of the widespread, innovative efforts to improve cost efficiency in shale wells. Case histories demonstrate the successful use of biodegradable, temporary diverting agents, rather than cement squeezes or mechanical tools, to simplify and reduce the cost of fracturing and refracturing operations. With fewer new wells being drilled, refracturing may offer a viable option to slow the decline of existing shale wells. The industry has been working to relate cement mechanical properties to success/failure with annular isolation in the actual well for approximately 20 years; however, there are still no American Petroleum Institute standardized cement-testing and -evaluation protocols for cement mechanical properties, and there is much room for improvement. The investigative paper SPE 168650 relates how anelastic-strain and impact-resistance testing may enhance real-world predictive abilities. JPT Recommended additional reading at OnePetro: www.onepetro.org. SPE 169514 Effect of Well Downspacing on Estimated Ultimate Recovery for Shale Oil Formations by Susrut Gautam Bharali, University of Houston, et al. SPE/IADC 170480 Challenges of Casing Design in Geothermal Wells by Angelito Torres, Chevron SPE 170712 Cement Evaluation—A Risky Business by Glen Benge, Baker Hughes

管外封隔器组合注入工具研制

目前，在完井作业尤其是水平井的分段完井或分段卡封中，现有管外封隔器的坐封工艺不能保证坐封良好，因此本文设计了一种管外封隔器组合注入工具，利用其上、下两端的胶筒实现密封，中间的注入孔道实现对管外封隔器胀封液的注入，可实现管外封隔器的有效坐封，注入水泥则可实现其永久坐封，提高分段完井或分段卡封工艺的有效期。通过现场应用表明，该工具可靠有效，能够适应分段完井或分段卡封工艺的长期有效应用。 Now, in the completion operation, especially in the staged completion and staged plugging, the seating process can’t promise successful sealing. So the combined injection tool for external casing packer is designed. The top and bottom packers are used for sealing; the middle hole is applied to inject fluid for seating packer. If the fluid is cement, ECP (external casing packer) is seating for permanent. The validity of segmental completion and segmental plugging is longer. Through the field application, the tool is reliable and effective in segmental completion and segmental plugging technology.

Technology Focus: Well Integrity (January 2015)

Technology Focus Cementing operations represent one of the more critical aspects concerning well integrity. Despite the large amount of research and the huge number of operations throughout the years, the industry still faces well-integrity problems during and after cementing operations. These occurrences have been experienced by the petroleum industry worldwide and can happen at any moment of the well life cycle, from the drilling phase to abandonment after the well’s production life. Here, I have categorized these well-integrity issues according to the moment at which they manifest: during the cement displacement inside the well (minutes); after the cement placement (hours to days), and after the cement has been cured (months to years). The first category may result in serious well-control problems, including blowouts (the Macondo blowout was related to cementing operations). According to a survey published by the former Minerals Management Service, during the period between 1992 and 2006, the leading factor contributing to blowouts in the US offshore area was cementing (18 out of 54 blowouts reported). These well-control problems are normally caused by improper design of the cementing operation in terms of hydrostatic pressure of the cement slurries or preflushes, failure when mixing the cement slurry to achieve its planned density, lost circulation during the cement displacement, or failure of casing float equipment. In my opinion, well-control courses must dedicate more time to discussing well-control problems during cementing operations. The second category encompasses those issues normally associated with the loss of hydrostatic pressure of the cement slurry during its initial hydration period and consequent gas flow inside the annulus. This condition also can cause well-control problems, pressure buildup in the annulus between casing strings, and zonal-isolation problems later on. The industry has several ways to mitigate these occurrences that include, but are not limited to, the use of gas-block additives, the design of cement slurries with short transition times, the application of surface pressure on the annulus, the use of external casing packers, and the implementation of multistage cementing operations. Despite the application of these mitigation measures, annular gas flow after cementing is still a recurrent problem, and remedial solutions are normally expensive and difficult. The last category refers to long-term problems normally caused by poor cementing practices, with detrimental effects on zonal isolation. Inadequate drilling-mud removal during the cement-slurry displacement in the annulus, insufficient cement height that may lead to casing leakage and corrosion problems, and the channels that result from the gas flow previously mentioned are some of the factors that can contribute to long-term well-integrity failures. Again, remedial solutions are normally expensive. JPT Recommended additional reading at OnePetro: www.onepetro.org. IPTC 16592 Mitigation of Deepwater Shallow Hazards With Simplified Cement System: South China Sea Case Study by Todd B. Ellis, Baker Hughes, et al. OTC 24369 Well-Integrity Analysis Applied to Workover Prediction by T.C. da Fonseca, Petrobras, et al. SPE/IADC 163474 Automated Alarms for Smart Flowback Fingerprinting and Early Kick Detection by Tarab H. Ali, Baker Hughes, et al.

The Water Control Technique of Horizontal Well Completion Strings With an Inner-located Nozzle in a Nonhomogeneous Bottom Water Reservoir

Horizontal well has been used successfully in small block and offshore reservoirs and reservoirs with bottom water. But with the oilfield development, horizontal well has also exposed some questions gradually. Vertical well has a long water cut production period, but water cut of the horizontal well increases dramatically after water breakthrough, which affects horizontal well development seriously. The coupled model was established and solved according to the characteristics of the completion strings with inner-located nozzle. The authors found that compared with a simple implementation of blind pipe or adjust the size of the nozzle, the implementation of external casing packer or the implementation of external casing packer in conjunction with the implementation of blind pipe (or adjust the size of the nozzle) can adjustment the production profile by a wide margin. Because the high-permeability zone is the major water flooded zone, and also the major producing zone, therefore, unduly limit of the liquid producing capacity may not be able to achieve preferable results. The best results can be obtained when coefficient of variation is about .6; the effect of these measures is not obvious when coefficient of variation is too small or too large.

Ultralightweight Proppants: An Effective Approach To Address Problems in Long Horizontal Gravel Packs Offshore Brazil

Summary Operators developing reservoirs and producing them from deep and ultradeepwater wells are pushing the technical limits regarding horizontal extension. Deepwater wells completed in unconsolidated formations usually have low fracture gradients, severe leakoff zones, and/or significant washouts. Long horizontal open holes, therefore, may become technically difficult or economically unfeasible to gravel-pack with the use of conventional fluids and gravels. Typical completions in offshore Brazil start from a 9⅝ - or 10¾-in.casing, in which a 5½-in. premium screen and tubular string is hung along an open hole drilled with an 8½- or 9½-in. bit. Horizontal extensions range from 980 to 4,000 ft. A variety of openhole gravel-pack techniques proved to be complex and costly, but ultralightweight (ULW) proppants have enabled simpler and more-cost-effective gravel packing in these longer horizontal open holes. The reduced gravel density allows a significant reduction in pumping rate that avoids fracturing the formation, minimizes fluid loss, and eliminates the risk of premature screenout caused by excessive gravel settling. ULW-proppant technology was introduced to Brazil in 2005 and has been applied successfully to gravel pack wells under extreme conditions such as low fracture gradient, severe fluid loss, and washed-out zones. ProppantULW-1.25 has proved to be effective for packing wells with narrow sections through the openhole interval, frequently found in horizontal wells completed through shale zones that are isolated by reactive packers and/or mechanical external casing packers. ULW-1.75 was introduced in Brazil in 2007 and has largely replaced ULW-1.25 for gravel packing wells in which an improvement in the operational pumping window is required. A combined package comprising ULW-1.75 during the alpha-wave phase and ULW-1.25 during the beta-wave phase is also discussed. This paper summarizes the procedures and results of almost 60 wells that have been gravel packed with the use of ULW-proppant technology pumped for a local operator.

Well-Completion Effects on the Performance of Horizontal and Multilateral Wells

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 96530, "An Evaluation of Well-Completion Impacts on the Performance of Horizontal and Multilateral Wells," by L.-B. Ouyang, SPE, and B. Huang, SPE, Chevron Energy Technology Co., prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October. Well completion is critical in well design and the performance of the well for its entire life. The major objective for this study was to provide guidance in the design of completion configuration with a series of simulations with different completions in different flow and reservoir environments. Completion options including open hole, slotted liner, inflow-control devices, intelligent-well completions (i.e., downhole instrumentation and control system), perforated/cemented liner, wire-wrapped screen, external casing packers, gravel pack, and frac pack were reviewed. Introduction With many advanced well-completion options deployed in new wells, especially in deep- and ultradeepwater environments, well-completion details often are not taken into account in reservoir simulators. Reservoir simulators should be connected with wellbore hydraulics and tubing-performance prediction software regarding the ability to model complex well hydraulics, including an appreciation of the influence on deliverability of reservoir effects and completion design. This study evaluated the performance under different completion designs for two proposed gas wells and one existing oil well. Several potential factors that could affect well production were evaluated including pressure drawdown, wellbore damage, non-Darcy effect, zonal isolation, wellbore-pressure drop, fluid flow in the annulus, and well position. Simulation Tool A commercially available completion-modeling and well-planning simulation tool was used that models production fluids flowing from the reservoir through well completions into a wellbore. It is used for well-placement and -completion screening and/or design studies of local variations in reservoir properties. It allows scaleup and honors complex reservoir-description information from an Earth model to compute multiphase flow from the reservoir through the well completion, into the wellbore, and up to the wellhead. Through alternative well placement, the well behavior can be estimated for the given reservoir description and well-completion design. The steady-state oil-, water-, and gas-production rates as well as the production profile along the length of the horizontal wellbore can be calculated. Completion Option Different completion designs were proposed for the two gas wells, including openhole gravel pack (OHGP), cased-hole gravel pack (CHGP), standalone screen (SAS), cased-hole frac pack (CHFP), and expandable sand screen (ESS). For a CHGP or CHFP completion, an isolation string could be required. The detailed completion parameters for all the completion options are given in Table 1 in the full-length paper. Skin factor is a measure of the amount of additional pressure draw-down encountered because of mechanical or turbulent effects. The higher the skin factor, the larger the extra pressure drawdown, resulting in reduced well production. Mechanical skin is a factor closely related to well completion and independent of flow rate. The skin caused by turbulent effects (normally called non-Darcy effect, or non-Darcy skin) depends primarily on flow rate. Typically, non-Darcy skin is trivial and can be ignored for liquid wells or low-rate gas wells. However, the non-Darcy skin for high-rate gas wells could be as significant as the mechanical skin.

Real-Time Monitoring and Control of Water Influx to a Horizontal Well Using Advanced Completion Equipped With Permanent Sensors

Summary We have tested new technologies for real-time monitoring and control of water influx to horizontal wells with sand-control completions. In a thin oil column in Indiana, we drilled a horizontal well and completed it openhole with sand screens and a gravel pack. External casing packers (ECPs) subdivided the annulus into three zones. An electrical valve, which also records the annular and tubing pressure, controls inflow to each zone. Twenty-one centralizers acted as electrodes to form a resistivity array that spans the 694-ft-long completion. The well was also equipped with a fiber-optic distributed-temperature-sensing (FODTS) system. The well has been produced since November 2001 and provides real-time data that are shared across a geographically distributed network and used to optimize the production of oil from the well. The data from the pressure sensors and the resistivity array have been jointly interpreted to dynamically update the static reservoir model, which was initially based on observations in offset vertical wells. The pressures recorded from the three electrical valves provide high-frequency data to characterize the near-well heterogeneity of the formation. These data are critical to computing an optimum production strategy. Zonal well tests, combined with interference testing between zones and wells, enable the estimation of communication between zones and the productivity index (PI) of each zone. The resistivity data enabled detection of water-saturation changes both in the formation and in the wellbore. The completion technology tested in this well offers the potential to intelligently operate horizontal sand-control completions by combining real-time monitoring with downhole inflow control.

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.

Evolution of Production Practice And Reservoir Management of the Winter Field

Abstract Actual production data of Winter Field were examined for production rates, oil cut, cumulative oil produced and reserves per well in relation to well length. The log oil cut vs. cumulative oil production per well of groups of wells plots showed that the reserves at a 2% oil cut was the same despite the different lengths of these wells. Published data were next examined to establish the relationship between well length and reserves. It is obvious that the relation between reserves as a function of well length is not a linear relationship for the entire well length examined. This relation shows that as the well length increases from 200 m to roughly 500 m there is a linear increase in reserves. The slope of the line is less than one (0.7); as the length increases beyond 600 m there is very little increase in the reserves. This could explain why the Winter wells all have the same reserves. These groups of wells varied in length from 574 m to 1,110 m; that is, they are all in the length range (greater than 500 m) that gives the maximum reserves(1). In order to verify this conclusion and utilize it to increase the reserve from existing and future wells a series of well workovers and treatment programs were carried out. Newly drilled wells were completed in such a way as to use the conclusions and recommendations of these programs. Introduction The Winter field (Figure 1) has been developed utilizing horizontal wells to produce heavy oil (13.7 API oil of 2,800 – 3,800 cp. viscosity) in a 12 m thick Cumming Sand underlain by a very strong aquifer. The oil cut vs. oil cum. per well plots for each phase (wells drilled in a specific year) are shown in Figure 2. It is obvious that the reserves per well at an economic oil cut of 2% are essentially the same for the different phases. It is interesting to notice that the average well length for the different phases ranges from 574 m to 1,111 m. Data for over 250 horizontal wells producing oil over water reservoir in Saskatchewan published in SEM publication were analysed and the reserves as a function of length are shown in Figure 3. This figure illustrates the non-linear nature of the relationship between reserves and well length. For example a well of 200 – 300 m length has a reserves of 9,000 m3 while a well of 1,000 – 1,100 m has a reserves of 15,000 m3; rather than the 30,000 – 40,000 m3 expected in a linear correlation. Detailed analysis of every well in the Winter Field was carried to identify potential reasons for better or worse performance. A series of water shut-off treatments and workovers were carried out. External casing packers were utilized for formation isolation and proved to be effective. Finally, the information gained from all of the above is being tested in some of the 1995 drilling program through a new completion practice targeting reserves maximization with minimum effect of initial rate.

Monitoring and Analysis of ECP-lnflation Status Using Memory-Gauge Data

Summary The current surface instrumentation for monitoring the external-casing-packer (ECP) -inflation status has been identified as unsatisfactory, causing a significant degree of uncertainty in the evaluation of ECP performance. Coupled with some unreliable practices in the installation process relating to the use of the instrumentation, data interpretation is often difficult. To combat the inaccuracy of surface measurement, memory gauges have been used for the first time as a retrospective tool to monitor ECP status downhole in west Shetland. The memory gauges, which are mounted on the workstring close to the ECP, remove the damping effect of the fluid column in the workstring, and are capable of measuring the squeeze pressure below the ECP caused by inflation. It is demonstrated in these operations that the following have been achieved. • ECP status has been identified unambiguously and reliably in several wells. • Some problems in job design have been identified, such as hydraulic lock (which may result in partial inflation) and incorrect setting of pressure shear-pin levels for inflation, leading to the formation being fractured. • Insight has been gained in pipe-movement-induced swabbing and pressure surge, which act adversely on the formation. Certain information on the mud (such as solid settlement and pressure/volume relations) was also obtained. • Valuable data was gained (both from the memory gauges and the surface gauges) that were a cornerstone for setting certain guidelines in interpreting ECP status by surface instrumentation. This paper presents a detailed analysis of the data with examples and case histories. Key considerations in operations, lessons learned, and recommendations are discussed before the conclusions are reported.

Zonal Isolation and Evaluation for Cemented Horizontal Liners

SummaryThis paper discusses the novel application of technology in the cementing and bond evaluation from the world-record breaking ERD (Extended Reach Drilling) wells in Wytch Farm, where horizontal liners of the order of 800m to 1300m at TvD of ca 1600m have been successfully cemented and perforated.Detailed analysis of the conditions by a multi-disciplinary team provided some practical procedures which enabled us to achieve our objectives of zonal isolation and cement bond evaluation successfully. Important aspects of zonal isolation, such as the use of spiral-blade centraisers, rotating the liner, and trials of the ECPs (External Casing Packer) are discussed in detail. Cement bond evaluation is also detailed, involving CT (Coiled Tubing) deployment and various bond logging tools, including ultrasonic tools. The CBL was found to be surprisingly reliable if used correctly.

Inflow Performance of Partially Open Horizontal Wells

Summary When a horizontal well is selectively completed, the productive length maynot be the entire drilled length of the horizontal section. The productivity ofthe well will be affected by the total length and productivity of the well willbe affected by the total length and distribution of the open intervals. Thispaper presents a method to calculate the inflow performance of a horizontalwell that is selectively completed. Introduction Completion of horizontal wells as open holes or with slotted (Figs. 1a and 1b) leaves operators with little or no opportunity to perform diagnostic orremedial work. perform diagnostic or remedial work. Many horizontal wells thathave been producing for several years are now producing for several years arenow experiencing production problems that can be attributed to the lack ofcompletion control. This is particularly true in areas where the targets arethin and coning n a potential problem. It is inevitable that certain portionsproblem. It is inevitable that certain portions of the well will be closer tothe fluid/fluid contact than others and that hydraulic isolation of thoseportions would significantly improve long-term performance. Also, when drillingcontrol or sufficient geological knowledge is absent, portions of the well maynot even lie within the reservoir. Considerable knowledge has been developed onhow to complete horizontal wells successfully; what is missing is a method forpredicting the performance of different completion strategies. It may be thatit is not practical or cost effective to open the entire practical or costeffective to open the entire length of the well within the reservoir. Figs. 1c and 1d are schematics of a selectively completed well. The well in Fig. 1c was completed with external casing packers (ECP's) that had alternate slotted andunslotted sections. Fig. 1d shows that the same effective completion wasachieved with a cemented liner that was subsequently perforated. For thepurpose of inflow perforated. For the purpose of inflow calculations, thesecompletions are identical. As horizontal well technology has developed, severalinflow performance formulas for horizontal wells have been discussed in theliterature. In this paper, we expand the work of Goode and Kuchuk to includethe effects of having only a portion of the well open. They present a solutionfor the inflow performance of a horizontal well producing from a reservoir ofuniform producing from a reservoir of uniform thickness within a closed, rectangular drainage region. The well can be placed arbitrarily within thedrainage volume, provided that the distance from any part of the well (open toflow) to a lateral boundary is large compared with the scaled of the reservoir. In practice this is not an unduly restrictive assumption, unless the verticalpermeability is extremely low. It is much less permeability is extremely low. It is much less restrictive than the geometry required by Giger el al. and Karcher el al, where the well must be short enough, compared with the boundedregion, to permit the development of radial flow before the effect of thelateral boundaries is felt. The formulas presented by Babu and Odeh and Goodeand Kuchuk are for a well placed inside a drainage volume with no flux crossingany external boundary, while the formulas presented in Refs. 3 through 5 assumea constant pressure at the external lateral boundaries and no-flux conditionsat the top and bottom. The no-flux condition on all external boundaries is themost relevant for practical purposes and is the boundary condition used in thiswork. Mathematical Model We consider a horizontal well of length 2L 1/2 centered at (x w, y w, z w)and producing from a rectangular region of dimensions Lx and Ly, through n popen intervals, with Segment i of length 2L i centered at x i (Fig. 2). Thedistribution and number of open interviews is arbitrary, as is the position ofthe well within the drainage area, provided that the distance from any openinterval to a lateral is large compared will the scaled reservoir thickness h(kx/k z) 1/2. With this restriction, the pressure will be vertically equilibratedbefore the influence of any lateral boundaries is felt, and we may derive theinflow formula by writing the pressure drop as a sum of two terms. We firstpressure drop as a sum of two terms. We first consider a 2D fracture problemthat is analogous to the horizontal well problem at long times. We then accountfor the pressure drop in the third dimension, z, by including a pseudoskin, SzD, determined by solution of pseudoskin, S zD, determined by solution of a 3Dproblem (not 2D as in Refs. 3 through 5) that excludes the lateral boundaries. The inflow performance of a well is related to the long-time behavior of theconstant-rate pressure. At long times, when no flux is permitted to cross theexternal boundaries, the difference between the average pressure in thereservoir and wellbore pressure pressure in the reservoir and wellbore pressureapproaches a constant value that we call the inflow pressure. JPT P. 983

Use of External Casing Packers for Zonal Segregation in the Wilmington Oil Field

External casing packers have been used with great success in more than 500 development and injection wells in the Wilmington oil field to segregate zones, to exclude wet sands, and to include more than one producing zone in a common wellbore. The use of these packers has saved the Long Beach Unit considerable money by reducing the number of wells required to develop the field. Introduction The Wilmington oil field, located in the southwestern portion of Los Angeles County, Calif., is composed basically of seven productive zones consisting of more than 60 different horizons or sands that have varying characteristics. The major zones are the Tar, Ranger, Upper Terminal, Lower Terminal, Union Pacific, Ford and 237 (Fig. 1). Four sand and fluid Pacific, Ford and 237 (Fig. 1). Four sand and fluid characteristics that have a notable influence on production and waterflooding are permeability, oil production and waterflooding are permeability, oil gravity, zonal pressure and gas saturation. The absolute permeabilities vary between 1,500 and 500 md within the Ranger Zone alone, and API oil gravities vary as much as 12 degrees from flank to crest. When the older portion of the Wilmington field was being developed, zonal pressures were essentially at hydrostatic; however, within the Long Beach Unit area, initial pressures encountered in the Ranger zone varied from pressures encountered in the Ranger zone varied from 50 to 95 percent of hydrostatic and as much as 25 percent between subsands of the completion interval. percent between subsands of the completion interval. As a result of the different degrees of pressure depletion, significantly different production GOR's were observed. Water injection was started originally in the Wilmington oil field in May, 1953, with pilot floods in several areas and zones. These pilot floods were extended to major waterflood operations in 1958 upon unitization of the field and as a major subsidence control measure. From the beginning, wide variations in the characteristics of the sands caused serious overflooding and fingering. The original wells were not specifically drilled and completed for future waterflooding, so control of the flood front depended on such major remedial work as redrilling. As a result of the economic success of the waterflood operations of the older portion of Wilmington, as well as their success in halting subsidence, the unit agreement for the Long Beach Unit required that development drilling be followed immediately by injection to maintain reservoir pressures and to avoid subsidence. This, coupled with the provision that the Long Beach Unit be developed from a limited number of drillsites contained within given limited areas, posed the problem of how to fully develop the field, posed the problem of how to fully develop the field, keeping the number of drilled wells to a minimum, maintaining complete control over water injection, and isolating gassy stringers. Several methods of segregation were considered: cementing, using plastic, setting through and milling out, etc. However, each had its disadvantages. In a review of various methods in use, the inflatable external casing packer was recognized as one of the more effective tools, with the added advantage that no foreign material was required that might damage the formation. In Sept., 1965, the first Long Beach Unit well to be equipped with inflatable external casing packers was successfully completed. The packers were used in this well to isolate intermediate packers were used in this well to isolate intermediate water. JPT P. 1101