Thursday, August 31, 2017

Wirelene /LWD consideratons

Analysis indicates that wireline measurements are advantageous when:

  • Equity decisions are a concern. Because wireline measurements remain the accepted standard, both from technical and legal standpoints , partners may shy away from relying only on LWD measurements when there is a possible equity debate. Some operators view LWD as less desirable in equity decisions because of the need to depth match it with wireline. Depth matching LWD to wireline is often straightforward, but may be complicated when invasion or borehole conditons cause large differences between LWD and wireline logs, or when driller's depth varies nonsystematically with wireline depth. This can happen because of pipe stretch, compression or yo-yoing, or miscounted pipe stands. Absolute depth correction of LWD logs is sometimes done using a gamma ray from the cement bond log when casing is set-usually one to three days after LWD logging. This delay in absolute depth correction does not stall drilling-related decisions based on LWD information. The relative depths of features on the LWD log are used to reference formation tester sample, core and casing points.
  • High temperatures (greater than 320oF (160oC) ) are encountered. Wireline tools typically have a higher temperature rating than LWD tools, which are limited mainly by their use of batteries.
  • Hole size is very large. The current maximum hole size for the CDN tool is 13 3/4 in. 

Monday, August 28, 2017

LWD/ Wireline Comparisons

In the several years since LWD technology became available, the industry has found five main applications for these tools:

  • Insurance logging, in case the well is lost, can't be logged with wireline tools or will yield poor-quality wireline logs.
  • Logging before invasion, which may reveal hydrocarbon zones that might be missed by wireline time. In some high permeability formations, borehole fluid displaces hydrocarbon from the near wellbore rock, making the well look like a dry hole by the time of wireline logging. This effect may be more common in horizontal than vertical wells because the drainhole is exposed to full hydrostatic mud pressure for the long period required to drill the lateral section.
  • Geosteeering and enhancement of drilling effciency.
  • Savings in rig time in settings requiring the TLC (Tough Logging Conditions) system and offshore. 
  • Multiple pass logging. Comparison logs made at different times can help distinguish pay from water zones, locate fluid contacts and identify true formation resistivity and density.
LWD is cost-effective when :
  • Rig cost is high. Rig cost high enough to make LWD attractive exists almost entirely offshore and where time-consuming TLC logging would be required. Most of the additional expense of a TLC operation is in rig cost, which run about $5000/hour in the North Sea. Amoco is looking to MWD/LWD as a means to cut this cost. Use of LWD may also accelerate selection of coring and casing points and perforation intervals, which can contribute to savings in rig time.
  • Water-base muds are used. These typically yield poorer borehole conditions by wireline time than oil-base mud (OBM). Wireline tools may therefore be difficult to get down the hole, may get stuck or yield poor logs.In the UK sector of the North Sea, as OBM use continues declining for environmental reasons, Amoco expects LWD use to increase. Use of OBM is banned in exploration wells in Norway and the Netherlands. 
  • The well is in an area known for operational difficulties -swelling shales or , most commonly in the North Sea , overpressured zones. Under these conditions, LWD offers the advantage of insurance logging. But more importantly, real-time data can accelerate decisions about well control and how the well should be driled and completed. Amoco finds that real-time data provide "an effective means of minimizing risk and reducing excessive operating costs" in exploration wells. Most of this savings is related to savings in rig time. To illustrate this point, Walsgrove cites an instance in which LWD reduced operating costs by allowing more accurate location of coring points within a sand/shale sequence. 
  • When real-time access to pore pressure analysis (in undercompacted formations) and petrophysical data are needed for drilling decisions and planning a wireline logging program and completion strategy. Real time access to petrophysical data has led to a new application, called geosteering- using real time measurement.

Wednesday, August 23, 2017

Logging While Drilling Perspective chapter 1

Basic LWD measurements - resistivity, neutron and density porosities and photoelectric factor - have not changed since their introduction, but tool technology has undergone several refinements. These include a range of engineering improvements - from more robust sensor design, to more secure mounting of connectors and integrated circuits. These improvements have led to increased tool durability.

Because the tools are contained in drill collars, hardware takes up space inside the collar, reducing the cross-sectional area available for mud flow. This reduction in area, and erosion of tool components by sand and lost circulation material, mean mud flow rates are lower than in plain collars. However, demand for LWD measurements has increased in wells that require higher flow rates for effective hole cleaning. In response, the maximum mud flow rate for the 6 1/2 -in. tools was recently increased from 450 to 600 gallons per minute (from 28 liters/sec to 38 liters/sec). This upgrade makes the tools practical in wells where mud rate requirements might have precluded them in the past. The upgrade was accomplised by redesigning internal tool parts to allocate more cross-sectional area to mud flow, and by increasing the tool diameter. In 1991, the outside diameter of the CDR (compensated dual resistivity) tool was increased from 6 1/2 and 8 in. to 6 3/4 and 8 1/4 in. , tool is rated to 1200 gal/min (76 liters/sec).

The most fundamental change in the nuclear tool is detector design. The first generation used a combination of helium (He) detectors, also used in wireline tools, and Geiger-Mueller detectors. Compared to Geiger-Mueller detectors, He detectors, have a broader dynamic range, do not need correction for spurious activation, are less affected by borehole salinity and have better statistics, permiting a higher rate of penetration (ROP). But they were not thought to be as rugged as Geiger-Mueller detectors. Field experience proved otherwise, and since 1990 the CDN tool uses helium detectors only. Older tools are being retrofitted.

The CDN tool has a 7.5-curie americium-beryllium neutron source and a 1.7 curie cesium density source, bot connected to a source retrieval assembly. In the first version of the tool, the sources and retrieval head were connected with a flexible steel cable. This has been replaced with a flexible titanium rod, giving more reliable retrieval and more accurate placement of the sources. Also improved is the density detector shielding, which eliminates sensitivity to spurious signals from the mud.

The CDN tool uses a full-gauge stabilizer with windows cut in the blades in front of the density source and gamma ray detectors. When the hole is in gauge, the blades wipe away mud from in front of the sensors, thereby minimizing borehole effects. A locking mechanism is being retrofitted on the stabilizer to increase its resistance to slippage under high torque and jarring.

The caliper is used to correct the density and neutron porosity measurements for borehole effects and can be used as borehole stability indicator. It can be used for downhole detecton of free gas-gas bubbles, not dissloved gas-through a combination of formation and "faceplate" echo signals. The faceplate echo is measured at the surface of the tool, at the mud/window interface. It is affected by gas content in mud, with echo amplitude increasing with gas content. The smallest amount of detectable gas is less than 3% volume of free gas. Real-time transmission of this information can shorten the time needed to detect gas influxes while drilling. This can simplifiy kill operations.

Thursday, August 17, 2017

Vertical Exploration Well : Case Study

Elf Aquitane embarked on a series of trials to determine whether coiled tubing could be used to drill slimhole wells, cutting exploration drilling costs. The goal of the first well was to demonstrate that a CTU can drill a vertical well sufficiently fast, cut cores and test formations. Elf envisions initially drilling these slimhole wells with a single openhole section-avoiding the need for casing - with the surface casing set using low-cost, water well rigs.

This first trial involved the re-entry of well Saint Firmin 13 in the Paris basin. The plan was to use the CTU to set cement plugs across the existing perforations at 2120 ft and then drill a 2105 ft vertical section of 3 7/8-in. diameter. Directional measurements using a coiled-tubing conveyed survey were to be taken every 500 ft. Then a 50-ft itnerval was to be cored and logged. Finally, a zone was to be flow tested by measuring pressure between two straddle packers.

The trial was carried out by Dowell Schlumberger using a trailer-mounted CTU with a reel of about 6000 ft (1830 m ) of 1 1/2-in tubing. To avoid the need for costly modifications, standard surface hardware, like injector head with stripper and BOP stack, were used. A workover rig substructure was installed over the existing wellhead to act as a work platform.

The operation encountered difficulties at the outset-not with the drilling but with the integrity of the well 30-year old casing. After cement plugs were set, the would not hold the 360 psi aboye hydrostatic pressure required to withstand the anticipated formation pressures. Because of this, drilling depth was limited to 2955 ft which allowed limestone coring but did not extend to a high-pressure aquifer.

The drilling BHAs employed a high-speed, low torque motor with PDC bits. For coring, a high-torque motor was used. The drilling and coring assemblies were made to hang vertically by incorporating heavy drill collars into the BHA, creating a pendulum assembly. At the start, the deviation at the casing shoe was 2o and, as expected, the BHA did not build angle at 2362 ft and 2795 ft, the deviation angles were 2 3/4 o and 2 1/4 o respectively.

During drilling, the rates were comparable to those drilled by conventional rigs at work in the area. This showed that a CTU can drill vertical wells a commercial rates. Two cores were cut and retrieved with good recovery-meeting the second objective of the trial.

Because the program had to be revised to avoid high-pressure zones, no oil-bearing formation could be tested. To prove testing technology and meet the third objective, a drawdown test was carried out on a zone between 2221 ft and 2331 ft . The FSTS Formation Selective Treatment System was deployed with its two packers straddling this zone. The formation was successfllly isolated and , if it had been a reservoir, would have produced into the coiled tubing.

In addition to proving that coiled tubing can be used to drill wells, the trial pointed out how procedures could be changed and where future hardware development is required. For example, rate of drilling could be increased by incorporation of measurement-while-drilling tools to make directional surveys, improving surface handling and weight-on-bit (WOB) control techniques and better optimization of the BHA.

  • Equipment needs - The Elf job utilized a workover rig substructure. In the future, a purpose-built substructure will be employed. Standing 10 ft off the ground and over the wellhead, this substructure will act as the drill floor to make or break the BHA and also to support the injector head. 

Lateral Re-Entry : Case Study in Pearson Field

Last year, Oryx Energy Company re-entered a vertical well in the Pearson field, Texas, USA, completed in Austin Chalk. Horizontal drilling in Austin Chalk using mud commonly encounters almost total lost circulation. To reduce mud losses, formation damage and costs, water is often used as drilling fluid. This decreases bottomhole hydrostatic pressure to less than formation pressure - underbalanced drilling. To combat annular pressure from formation flow during drilling, conventional rigs use a rotating stripping head or rotating BOPs to seal the annulus. The wells are killed each time a trip is made.

By using a CTU (coilded tubing unit) , which has its annulus sealed throughout drilling by the stripper, Oryx was able to run in and out of hole without killing the well. This imporved safety and avoided the expense of potential damaging effects to the formation of pumping brines to kill the well prior to tripping.

To prepare the well, Oryx used a conventional service rig to remove the existing completion hardware, set a whipstock and sidetrack out of 4,5-in. casing at a true vertical depth of 5300 ft (1615 m). Drilling was the continued using 2-in. coiled tubing, downhole mud motors, wireline steering tools, a mechanical downhole orienting tool and 37/8-in bits. An average buildup rate of 15o/100 ft was achieved and a horizontal section drilled for 1458 ft (444 m). The main bottomhole assembly (BHA) components were :

  • Drillstring -Oryx employed a reel comprising 10,050 ft (3060 m) of 2-in. outside diameter coiled tubing with 5/16-in. mono conductor cable installed inside the tubing. 
  • Orientation tool - Because coiled tubing cannot be rotated from surface to alter drilling direction, a downhole method of changing tool face orientation is needed. To achieve this, Oryx deployed a mechanical tool that converts tubing reciprocation into rotation-compression rotated the tool face to the right, extension to the left. Once adjusted, the tool face was locked in place using a minimum 250-psi differential pressure across the tool.
  • Directional survey tool - The survey tool inside a nonmagnetic collar relayed directional information to surface via the wireline. 
  • Directional BHA - Two assemblies were used, depending on the build rates required - a double bend assembly consisting of a conventional 2 7/8-in. bent housing mud motor coupled to single bent sub, or a steerable assembly comprising a single bend motor.
  • Bit - Thermally stable diamond bits were used to drill the curve and build sections and polycrystalline diamond compact (PDC) bits to drill the lateral section. 
Oryx motive for drilling this well was to prove that coiled tubing could be used to drill a lateral well in a controlled manner. This was achieved - the final wellbore trajectory came within a 50-ft vertical window along the horizontal section.

Tuesday, August 1, 2017

The Nuts and Bolts of Well Testing

Well testing is a dynamic process. At its simplest, a test discovers if a formation can flow and permits sampling of the produced fluid. Analysis can yield further information like the extent of formation damage near the borehole, reservoir permeability and heterogeneity, and initial productivity index. For this , engineers induce pressure transients by changing the rate that formation fluids enter the borehole and recording the resulting downhole pressure versus time. Transient tests can also reveal the reservoir's areal extent and vertical layering. 

Testing hardware has to perform a range of tasks. First, the formation being tested must flow. If the well has not already been completed, it needs to be temporarily completed-that is, to have a packer set above the test zone to isolate it from the wellbore fluid's hydrostatic pressure. 

To induce pressure transients, the engineer needs to control the well. The easiest method is surface shut-in. But during pressure buildup, the column of fluid between the point of shut-in and the formation has to be compressed by inflowing formation fluid-the so called wellbore storage effect. Data analysis usually requires that pressure be recorded until wellbore storage no longer dominates. 

When the wellbore volume is large (as in deep or horizontal wells) or the wellbore fluids highly compressible (as in gas wells), the wellbore storage effect cant last a prohibitevely long time. One way to minimize wellbore storage places a test valve downhole, as close as possible to the formation. Pressure gauges must be located below this test valve. 

Data gathering is not an exclusively downhole activity. On surface, after the fluid has been controlled and separated, flow rate can be measured. Taking a sample of the produced fluid is also important. Detailed analysis of samples not only sheds light on the composition of the produced fluid but also offers insight into the reservoir itself. The dynamic performace of a reservoir is both a function of the formation and the formation fluid. 

Openhole Testing- The first tests were conducted in open hole with the tools conveyed into the well on drillpipe-openhole drillstem test (DSTs). while the earliest DST hardware back to Johnston tools of the 1920s, the modern era of testing really started in 1950s. Then, multiflow evaluation tools were introduced, making possible repeated flow and shut-in cycles rather than the single flow and buildup offered before.

Today, multiflow evaluation tools are still used in the majority of openhole DSTs. If hdyrocarbons are detected in either cores or cuttings during drilling or indicated by logs, a DST may be used to rapidly assess the production potential of the formation. Drilling information or a wireline caliper log are used to locate a suitable packer seat- a section of openhole that is in gauge and looks capable of facilitating a good seal. The test string is designed so that the packer is opposite its seat when the perforated anchor is at the bottom of the well. 

The packer is traditionally a solid unit of rubber that expands when some of the weight of the string is set down onto the anchor. The test valve is also opened and closed by setting down and picking up on the string. Therefore, to ensure that pipe manipulation does not unset the packer, a tool above it hydraulically maintains the downward force. The packer can be unset only by an extended pull for several minutes. After the test has been completed and the test string pulled out of hole, drilling continues and the process can be repeated on subsequent hydrocarbon shows.