Casing is cemented into the wellbore to provide zonal isolation of producing zones, protect fresh water zones from contamination, prevent casing collapse caused by moving salts or sloughing clays and isolate the casing from corrosive brines. In other words, casing is cemented to create annular isolation. Historically, the major physical property of the cement used to determine whether these results would be attained for the life of the well, was the unconfined compressive strength of the set cement. Recent studies have shown that there are other "strengths or mechanical properties" that are even more important to consider. These strengths include tensile and flexural. This paper discusses why tensile and flexural strengths must be considered in slurry design, along with the interrelationship of compressive, tensile and flexural stresses that occur in wells, and provides Appalachian Basin field examples, where reduced, unconfined compressive strength cement, with enhanced tensile and flexural strengths has been successfully used. Introduction The main purpose of any primary cementing job is to provide zonal isolation and hold the casing in place. There are many factors that influence the cement's ability to achieve these objectives. Hole conditioning, flow regime and pipe reciprocation are a few of the mechanical techniques which can be employed. These and others have been investigated and reported in various studies1–4. Physical and chemical properties of the unset cement slurry also have a role in the success of the primary job. Christian, et al5 and Beirute, et al6 showed how cement dehydration and its control effect the primary cementing. Sutton, et al7 demonstrated the relationship between gel-strength transition time and gas migration. The American Petroleum Institute (API) has established standards for cement slurry properties8. Historically, the only physical property of set cement that was tested was the unconfined compressive strength. Originally, it was felt that the set cement required a compressive strength at least equal to that of the producing formation9. In 1957 Craft10 published a study of west Texas and east New Mexico producing formations. He found that compressive strengths ranged from 8,215 psi to 22,500 psi. However, most set cements will only exhibit an ultimate compressive strength in the range of 5,000 to 9,000 psi. Since primary cementing jobs had been reasonably successful, the comparative compressive strength theory was dispelled. However, it was still generally felt that more was better. It had also been demonstrated that the tensile strength of the setting or set cement is of primary importance. Tensile strength relates directly to the ability of the cement sheath to hold tubulars in place. Farris11 showed that as little as 8 psi tensile strength is adequate to accomplish this requirement. Since the ratio of compressive strength to tensile strength in most cements ranges from 8 to 12, a compressive strength in the range of 100 psi is all that is needed to hold many casing strings in place.

The Vikulov formation in the Tyumen District of southwestern Siberia consists of incised-valley deposits and shallow-marine delta-front sands, which form oil reservoirs in the area of the Krasnoleninsk dome. Reservoir quality varies considerably depending on the depositional facies. In places, high permeability channels and bars were deposited, whereas the more distal sands have much lower permeability and must be fracture stimulated to produce economically. To compound the situation, the Vikulov sands are in the transition zone, and in many places, wet sands are in close proximity to the oil-productive sands. For this reason, many of the initial completions within the acreage had poor results. To improve field performance, a multi-disciplinary team was assembled. The team consisted of a geologist, petrophysicist, completion, production and reservoir engineers, facilities personnel and service company engineers. Their task was to better understand the properties of the Vikulov and the reservoir, determine well locations with maximum production potential, optimize stimulation treatments and provide infrastructure to produce the oil. This paper will review the initial completion efforts and explain the methodology and changes implemented by the team to describe and define the reservoir, modify stimulation methods using a grid-based, non-coupled fracture simulator and optimize well productivity. Production increases in excess of five fold have been realized for many wells. East Kamennoye Overview The East Kamennoye field is located approximately 100 kilometers northwest of the city of Khanty Mansiysk and covers 876 sq km (see figure 1). Since its discovery in 1962, more than 200 wells have been drilled on the East Kamennoye license. East Kamennoye produces from both Cretaceous and Jurassic formations, but the majority of the production and reserves is currently from the shallow Cretaceous Vikulov reservoir. The field is part of a much larger hydrocarbon accumulation which also includes the West Kamennoye license area. The Vikulov formation consists of normally pressured, low to medium permeability sandstones with a low gas-to-oil ratio. The producing wells require artificial lift. Standard completion consists of fracture stimulation followed by installation of submersible or beam pumps. Water injection has been initiated in the Vikulov and an early response is noted. Vikulov oil production for the month of May, 2006, averaged just over 22,000 bpd. Geology East Kamennoye consists of a number of independent producing formations (see figure 2). These include the shallower Cretaceous Vikulov (VK) reservoir encountered at 1,420 to 1,465 meters that contains the majority of the proved reserves, the deeper Jurassic reservoirs (Abalak, Tyumen and Sherkalin) at depths between 2,350 and 2,600 meters, and the underlying weathered and fractured Paleozoic Basement.

Nine (9) wells have been successfully drilled, cemented and fracture stimulated in the tight gas sands of four (4) separate fields on the Kenai Peninsula, Alaska utilizing an industry unique Casing-Conveyed Perforating System (CCPS). For this nine (9) well program, 124 CCPS modules have been run, cemented in place, detonated and fracture stimulated. Of the nine (9) wells the initial five (5) wells were stimulated with an oil-based fluid while the most recent four (4) have utilized a water-based system. While the project has been an overall success, the drilling and completion team continues to utilize new and innovative technologies to optimize well performance and economics. The normally-pressured middle and lower Beluga sands in the Kenai Gas (KG) and Beaver Creek (BC) areas exhibit significant vertical sections frequently exceeding 1,700 ft. The vertical pay quality is quite variable and consists of stacked fluvial sandstones 5 ft to 30 ft thick. The mineralogical composition of the sands is complex including a high percentage of quartz, clays, volcanics, coals, and fines with permeability ranging from 0.01 to 3 millidarcies. The sandstone packages are bounded by discontinuous shale, siltstone, and coal beds and present a challenging fracture stimulation environment. Produced gas is lean with a specific gravity of 0.56 with no condensate. As mentioned above one of the most robust changes to the project has been a shift from a crosslinked oil-based (diesel) fracturing fluid to a "new-generation" aqueous based guar-borate system. This step change was made at the conclusion of extensive laboratory studies on core sections and has provided significant improvement with HSE, completion operations, well performance and ROI. This case history paper reviews the revolutionary casing-conveyed perforating system, provides an overview of the nine (9) wells completed to date and describes the laboratory test procedures and results used to validate the use of a water-based fracturing fluid. Project cost savings are also discussed pertaining to the Total Cost of Service (TCS) differences between hydrocarbon and water-based fracturing fluids in a cold weather environment. Introduction From 1995 to 1998, a multidisciplinary team1 undertook an exhaustive reservoir characterization study of the Beluga formation in the Kenai Gas Field in an effort to improve well performance. During this study, it became apparent that conventional completion techniques were not optimally developing the Beluga Sand resource. Conventional completion approaches and a finite resource base resulted in a "high-grading" of the best sands in a well for stimulation typically restricting coverage to 100 ft - 150 ft net. Selective perforating strategies including limited entry techniques proved to be ineffective leaving many of the lower-quality sands unstimulated. This by-passed pay was identified as a potential 70 BCF recoverable target so the team was challenged to develop the resource. Working from the reservoir characterization platform, the team considered a variety of techniques for improving recovery and economics from the Beluga sands before settling on the CCPS. The CCPS was developed specifically for Alaska and has subsequently been employed on nine (9) wells across several fields. To date CCPS performance has been excellent and well production robust with well performance at or above anticipated production levels. As of the writing of this paper additional CCPS wells are being planned and drilled.

In the last several years, interest in developing unconventional oil and gas reservoirs has grown tremendously. Most of these unconventional reservoirs have very low permeability which makes them unable to produce at economic flow rates without massive stimulation treatments or special recovery processes. Bakken Shale play is one of these reservoirs which horizontal wells with hydraulic fracture treatments have been proven to be an effective method for its development. In this study, to evaluate the performance of hydraulically fractured horizontal wells in the Bakken Shale play, a rigorous analytical model has been developed to predict the productivity of a tight multi-layered reservoir drained by a horizontal well with a longitudinal fracture. This model rigorously couples flow in the matrix to flow in the fracture, and then to flow in the wellbore to account for the fracture conductivity and wellbore hydraulics, respectively. History matching of production data for Bakken wells reveals that the developed model provides a reliable tool for predicting the productivity of this type of well-reservoir configuration. Moreover, using this model to study the key factors influencing the well performance indicates that length of fractured portion of the lateral is the primary factors affecting the well productivity, while conductivity of fracture has an insignificant effect on productivity, which means using better proppant or fluid has minimal effect on productivity. Introduction The Bakken formation of eastern Montana and western North Dakota has been experiencing significant development during the last several years due to its tremendous oil accumulation. This formation is comprised of three distinct members - lower and upper shale beds, and a lithologically variable middle member which is the main productive interval and the target of the current development. The upper and lower shale have almost the same characteristics. The upper shale is comprised of a black, organic-rich, pyritic shale with measured total organic content (TOC) up to 40%. It is the primary source of hydrocarbons for the Middle Bakken. The lower shale is comprised of a black to brownish-black, fissile, non-calcareous, organic mudstone or shale. It has TOC of up to 21% (Wiley et al. 2004). Both upper and lower shale have a low porosity with extremely low permeability which can act as a seal to the generated hydrocarbon. The Middle Bakken generally is a marine sandstone or siltstone with considerable percentages of carbonate grains and cements. The Elm Coulee field in the Richland County, Montana Bakken play, is developed in a very dolomitic facies where porosity and permeability are relatively high due to partial dissolution of interlocking replacive dolomite rhombs. The North Dakota productive Middle Bakken exhibits comparable depositional characteristics but has more of a clastic framework of quartz, feldspar, and reworked fossiliferous carbonate grains and smaller amounts of dolomite. Primary porosity with reduced amount of secondary porosity is the main driver in the reservoir system in North Dakota (Cox et al. 2008). Production from the Bakken has been reported as early as the 1950's. Since the discovery, the play has experienced three development periods (LeFever 2004):–Conventional vertical drilling (1953–1987),–Horizontal drilling in the upper Bakken Shale (1987–2000),–Horizontal drilling in the Middle Bakken (2000-present day).

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