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In overbalanced drillng (OBD), a mud weight is selected that provides a hydrostatic pressure of 200 to 1,000 psi above the reservoir pressure. In UBD, we select a fluid that provides a hydrostatic pressure of around 200 psi below the initial reservoir pressure. This provides a good starting point for the selection of a fluid system. During the feasibility study, this drawdown is normally further refined, depending on the expected reservoir inflow and other drilling parameters. This first look provides an indication if the fluid should be foam or gasified or if the well is drilling with a single-phase fluid (Figure 1).
Two of the biggest oilfield service companies in the world reported earnings this week and reiterated that while things are getting better, a total recovery from the pandemic-driven downturn is not on the agenda in the short term. Halliburton is coming off a relatively hot quarter and reported $227 million in profits, a 33% increase over the previous period. After reporting a total revenue of more than $3.71 billion, the company's earnings amounted to 26 cents per share which beat most analysts' expectations of 22 cents. The needle moved the opposite direction for Baker Hughes which reported an adjusted quarterly net income of $83 million, a 9% drop from the first 3 months of the year. Baker Hughes finished the quarter with earnings per share of 10 cents which missed the market estimate of 16 cents.
The process of drilling and completing coalbed methane (CBM) wells is similar to wells in conventional reservoirs. Coring, however, can pose special challenges. The first step in creating a drilling program for a CBM well involves gathering information about existing wells in a given area. After these data are gathered and analyzed, a preliminary drilling and completion prognosis can be drafted with the input of field operations personnel. An important aspect in drilling frontier or appraisal wells is to keep the drilling procedures relatively simple.
Producing formation damage has been defined as the impairment of the unseen by the inevitable, causing an unknown reduction in the unquantifiable. In a different context, formation damage is defined as the impairment to reservoir (reduced production) caused by wellbore fluids used during drilling/completion and workover operations. It is a zone of reduced permeability within the vicinity of the wellbore (skin) as a result of foreign-fluid invasion into the reservoir rock. Typically, any unintended impedance to the flow of fluids into or out of a wellbore is referred to as formation damage. This broad definition includes flow restrictions caused by a reduction in permeability in the near-wellbore region, changes in relative permeability to the hydrocarbon phase, and unintended flow restrictions in the completion itself. Flow restrictions in the tubing or those imposed by the well partially penetrating a reservoir or other aspects of the completion geometry are not included in this definition because, although they may impede flow, they either have been put in place by design to serve a specific purpose or do not show up in typical measures of formation damage such as skin.
Most primary cement jobs are performed by pumping the slurry down the casing and up the annulus; however, modified techniques can be used for special situations. Conductor, surface, protection, and production strings are usually cemented by the single-stage method, which is performed by pumping cement slurry through the casing shoe and using top and bottom plugs. There are various types of heads for continuous cementing, as well as special adaptors for rotating or reciprocating casing. Stage-cementing tools, or differential valve (DV) tools, are used to cement multiple sections behind the same casing string, or to cement a critical long section in multistages. Stage cementing may reduce mud contamination and lessens the possibility of high filtrate loss or formation breakdown caused by high hydrostatic pressures, which is often a cause for lost circulation.
Conventional well completions in soft formations (the compressive strength is less than 1,000 psi) commonly produce formation sand or fines with fluids. These formations are usually geologically young (Tertiary age) and shallow, and they have little or no natural cementation. Sand production is unwanted because it can plug wells, erode equipment, and reduce well productivity. It also has no economic value. Nonetheless, formation sand production from wells is dealt with daily on a global basis.
Early U.S. settlements commonly were located near salt lakes that supplied salt to the population. These salt springs were often contaminated with petroleum, and many of the early efforts to acquire salt by digging wells were rewarded by finding unwanted amounts of oil and gas associated with the saline waters. In the Appalachian Mountains, saline water springs commonly occur along the crests of anticlines. In 1855, it was found that petroleum distillation produced light oil that was, as an illuminant, similar to coal oil and better than whale oil. This knowledge spurred the search for saline waters containing oil. With the methods of the salt producers, Colonel Edward Drake drilled a well on Oil Creek, near Titusville, Pennsylvania, in 1859.
Unlike conventional reservoirs, coal seams are the source, trap, and reservoir for CBM. A comparison of the two reservoir types shows profound differences in reservoir properties, storage mechanisms, flow mechanisms, and production profiles. CBM reservoirs are layered and contain an orthogonal fracture set called cleats, which are perpendicular to bedding. Because the coal matrix has essentially no permeability, CBM can be produced economically only if there is sufficient fracture permeability. Relative to conventional gas reservoirs, coal seam permeabilities are generally low and may vary by three orders of magnitude in wells separated by distances of less than 500 m.
The most comprehensive data-acquisition systems present at the rigsite are provided by service companies such as mud-logging, Measurement while drilling (MWD)/Logging while drilling (LWD)), and wireline vendors. Real-time data-acquisition systems typically are connected to a suite of surface and downhole sensors that enable live monitoring of the rig-equipment operation and the well-construction process. Service-company systems are typically capable of accepting Wellsite Information Transfer Specification (WITS) inputs from other vendors so that sensor readings from all data-acquisition systems may be collated into a single real-time data set that may be provided to the operator at the end of the well. The combination of surface and downhole sensors with networked graphical data logs and text outputs enables the operator's supervisory staff, service company, and rig contractor to maintain an accurate picture of the drilling or well-services operation, and track well progress to ensure that the new-wellbore placement or completion meets the operator's safety, geologic, and production requirements. Rig-contractor personnel may use any number of commercially available electronic tour-sheet applications that enable them to complete their Intl.