HTHP Gas Production Casing Cementing

HTHP Gas Production Casing Cementing Michael Davis, SPE, Drill Science Corp.

Abstract

A good cement bond on the production curve. Get the mud rheology right. Flat casing of a new wellbore is always the gels in the mud left in the hole. This desired result yet until now there hasn’t means the gel strengths don't increase been one paper written that compiles over time or else the mud will clabber tried and true methods for achieving up. The high tech term is Erodability. these results. Nowhere are the Clabbered mud has low erodability. Flat consequences for poor cementing of the get mud has high erodability. Find the production casing more important than expert cement engineer with a tight gas HTHP wells. These wells are reputation for great bond logs. Let him typically fracture treated and a good make the recipe. bond for zonal isolation of the fracture is 5. Take extra time to circulate with the critical. Also a micro-annulus becomes casing on bottom. Make sure the mud is not only a production issue yet a well still flat rheologically even if it was control issue. before running casing it now may be clabbered up again. Treat it all over Introduction again. Sure time is money yet the Good cementing rules of thumb for measure of drilling a well really boils HTHP gas production. down to the cement job. Take the extra 1. Drill a gauge hole. Gauge holes are time if the mud isn't exactly right and easier to centralize casing in and treat it if necessary to match the displace mud ahead of cement. hierarchical design of the cement job. 2. Cement with flowrates as high as The mud, spacer, cement must be in possible in turbulent flow. A gauge hole hierarchical rheologic order. will maximize annular velocities. 6. Get the mud engineer and cement 3. The purpose being to displace all of engineer to design a hierarchical the mud ahead of the cement and thus cement design. This means the mud you get all cement and no mud and thus ahead of spacer, the spacer, and then great cement bond. Turbulent flow the cement all have a certain rheology displaces mud better. As long as the so that the mud is displaced by the mud, spacer, cement are in increasing spacer and the spacer by the cement if hierarchical rheologic order. Rheologic the fluid ahead of the cement is too means, density, yield point, and viscous the cement channels. viscosity. 7. Find a cement design expert with a 4. The concept is ERODABILITY of the track record of excellent cement bond mud. Condition the mud BEFORE logs. Let this expert design the cement. running production casing. Stop Factors might include: thixotropic slurry, watching the clock and Days vs. Depth a low Young's modulus slurry, and expansion additives. Have them run the 15. Get a caliper log on the hole before cement job hydraulics and ensure that the cement job. This helps correct turbulent flow can be achieved with cement design and proper centralizer consideration to ECD's and formation placement. Gauge hole gives best integrity as an upper bound on cement bond for two reasons, better flowrates. centralization and mud displacement. 8. Design the hole and the casing to 16. A centralizer that lands across a create an annulus that will have the washout isn't a centralizer. If it doesn't optimum geometry and annular touch the sides of the hole it can't velocities to create the best cement job. centralize. Hence the importance of the 9. Don't start the cement job until the centralizer designs in conjunction with mud has the right rheology. Repeated the caliper log and a diligent pre-job for emphasis. assessment of the formation’s probable 10. Displace the cement with the lightest pre-cement state using offsets logs and fluid possible. This will minimize casing all available science to predict the hole OD during cement hardening and allow diameter at each centralizer depth. the cement sheath to harden snugly 17. Reciprocation of the casing has close to the casing. been proven to help in getting more 11. Make sure the float equipment can cement to fill in gaps that might be hold back the lift pressure of the cement bypassed in many cases. Rotation is job. Must calculate this pressure. also thought to improve cement bonding 12. On HTHP wells use latch down high as well. pressure double float equipment to 18. Hesitation squeezes the last several ensure that the high lift pressures can barrels of cement. This means stop be held. pumping. Allow the cement already in 13. The reason for this is so that the the annulus time to set up a bit. Then casing can be left open internally and pump half the remaining cement and allowed to contract as the cement repeat. Static circulation pressure is hardens. If valve on the rig floor on the higher than dynamic if the cement sits a casing is closed the cement exothermic few minutes and begins to dewater. This reaction will build internal pressure, the is believed to form better bond, casing will expand, the cement will especially at the shoe area. harden, the pressure will be bled off 19. Sand blasting the casing prior to leaving a microannulus between the running it is believed by some to allow outside of the casing and the cement. cement to bond to the casing better. This will give a bad cement bond log There is at least some laboratory validity andperhaps allow fluids to channel. to this seen in test using lab equipment 14. Proper centralizer placement. If you that shows “erodability” increases on don't know how to calculate this then equipment that is sandblasted. Also, ask the cement company for an expert. sandblasting increases the “rugosity” of Get this done. All centralizers are the surface of the casing that helps different the designer must know this. cement adhere to it and it is also noticed that the rugosity creates localized cement jobs and erodability. Better turbulence that adds in mud erosion. Cement Jobs SPE papers include: SPE 20. Pre-tension the casing beyond the 23927, 9284, 17441, 107701, 28441, weight that will be landed in the 14135, 26982, 38130, 14197, 3809, wellhead hanger while the cement is 23987, 24571. One famous cement setting up. Many times the production blend: Tail Slurry: Premium H + 35% casing is landed in the wellhead with the Silica Flour + 50 lb/sk Hemitite + 0.3% weight of the string “as cemented”. This Dispersent + 0.4% 1st Fluid Loss + is the buoyant weight of the casing 0.6% 2nd Fluid Loss + 0.5% Anti GFAC string in the cement or cement and fluid additive + 0.4% Synthetic Retarder + above it in the annulus as well as the 0.2% Retarder (19 ppg; 1.57 cu.ft/sk; fluid on the inside of the casing. To get 5.27 gal/sk) anymore string weight than this without Spacer: Oil Base Spacer mixed @ 18.5 moving the casing, the amount of ppg Displacement: 20 bbls clay fix reactive force from the centralizers as Water @ 8.4 ppg followed by 10 ppg drag will need to be carefully calculated. NaCl brine This response was posted in This can easily be done by obtaining the 2006 by the late Larry Flak, as a post to details of the starting and running forces an SPE drilling engineering technical of the exact type of centralizer and forum: In our vertical monobore accounting for variances in actual completions in South Texas in HTHP callipered hole sizes to be encountered. environments (18.1 ppg Hematite oil This number can be calibrated as soon mud at ~15,000 feet with 350 - 375 F as the casing reaches bottom before the BHT environment) these are the things cement job by picking up off bottom and we typically do: 1. Drill a gauge hole. noting the difference between the pick This is likely the most important factor. up and slack off weight and the force As we are limited in circulation rates required to get the casing moving up the with 5-1/2" x 4-1/2" monobores (9-5/8" hole. Simply stay below this hook load. 53.5# to 11,500 with 7-5/8" 29.7 liner This means two things, too much 11,300 to 12,400, 6-3/4" hole) or we tension will move the pipe, too little will initiate ballooning. 2. One bow spring allow the OD of the casing to shrink centralizer in middle of joint (we use 4- once the cement sets and the tension is 1/2" 15.1# Q-125 casing to near top of hung off in the casing hanger in the 7-5/8" liner then XO to 5-1/2" 26# T-95 wellhead. Once the heat from the (0-8000) and P- 110 casing (8000- producing well hits the casing it will lose 11400). 3. Sand blast all 4-1/2" casing even more tension and contract the OD (much better cement bond to pipe seen more perhaps losing the tight cement in bond logs) 4. We use the following bond. In HTHP wells this is very difficult cement: Tail Slurry: Premium H + 35% to model yet important to. Figure the Silica Flour + 50 lb/sk Hemitite + 0.3% tension needed to prevent buckling and Dispersent + 0.4% 1st Fluid Loss + slack off the weight on the hanger to 0.6% 2nd Fluid Loss + 0.5% Anti GFAC allow for the OD to expand. There are additive + 0.4% Synthetic Retarder + many papers (SPE) on the subject of 0.2% Retarder (19 ppg; 1.57 cu.ft/sk; 5.27 gal/sk) Spacer: Oil Base Spacer success. Best production cement mixed @ 18.5 ppg Displacement: 20 insurance is a "GAUGE HOLE" with all bbls clay fix Water @ 8.4 ppg followed of these other methods. > 2. Cement by 10 ppg NaCl brine 5. Carefully model slurry design and cement job operation. ECD and limit displacement rate as The cement slurry should be at least 4 required to keep wellbore from breaking ppg over the mud weight so this down. Typically cementing at 3 BPM. 6. shouldn't be difficult to achieve Reciprocate casing through the job till depending on how high up the cement is plug bumps (we use top and bottom needed (how high the upper HC or other plugs). 7. We use 10,000 psi HTHP float problem zone is). Also try Sodium equipment and displace cement with 10 Silicate in the pre flush. It coats the ppg brine with clay fix water ahead of permeable zones and makes the brine. We do not want brine to contact cement flash set as it touches it. This cement. Once plug is bumped with coats the zone and prevents losses. Try ~8,000 psi, we bleed off the internal rigid blade centralizers across the pay pressure to zero, close the annular BOP zones (w/20-30 degrees angle need and WOC. 8. We multi-zone stage frac stabilization). Hesitate squeeze the job. from 13,000 to 14,700 with up to 4 Check w/your cement company, yet zones and 4 fracs comingled. stop 30 bbls (or so) short of the Production is up the monobore. SITP is complete displacement wait couple of around 11,000 psi limited by cross-flow minutes and then pump 10 bbls; repeat during shut-in. 9. Total cost of wells is two more times. Worst thing that can around $5,000,000. Wells cum 6 to 12 happen is to get couple of hundred feet BCF. We get perfect bond! 1. Mud of cement left inside (drills quick). properties Condition the mud prior to This tends to fill channels especially if running casing. Looking to get mud to a combined with reciprocation and rotation condition that will allow it to be moved (try with a casing running tool than can by the cement that doesn't channel yet rotate and pump cement) Also, micro displaces the mud ahead of the cement annuli form if there is pressure held slurry completely. If I did the math right, while the cement is setting up. Use float your mud weight is 12.0 ppg. This is equipment, with redundant valves, and typical of almost every Gulf Coast appropriate pressure ratings to allow the Intermediate casing job. I hope this gets cement displacement with a fluid much someone with more cement and mud less than the previous mud weight. Try property expertise involved yet I would using fresh water to displace the cement imagine that lowering the viscosity and plug. Once the plug is bumped and fluid loss of the mud would be a great latches closed bleed the pressure off start. Gel Strength should be minimized making sure that the valves hold. This I would imagine. This shouldn't be too will allow the cement to 'contract' around costly. The wellbore is very important. If the casing as the casing itself decreases washed out, the best of actions after diameter. Once the pressures go up the drilling might not have a chance of pipe will fit like a glove within the cement job. > 3. Casing handling practices during /prior to cement job. Rotate pipe weight is very difficult yet vital especially (need special running cementing tools), in hot hole regions. Unfortunately, water reciprocate, use up jet float equipment. encroaches at precisely the same time Pay attention to the pressures used as the reservoir, and thus internal while running a CBL. Pipe expands casing pressure, decreases, thus the under pressure and contracts under casing contracts and there is a greater tension. How much tension to pull up on chance for the casing/cement the pipe is a different subject. microannulus to form. Drill the hole Tensioning the pipe while the cement gauge. The best way is oil based mud or sets will have an effect. The trick is to highly inhibitive and low fluid loss tension the pipe properly and not create systems. With a gauge hole the other a 'microannulus'. My belief is minimize methods work to make a 'state of the art' internal pressure and get the completion. Hope this starts a tension in the pipe while cement sets discussion with smarter and more up. Depending on how high the cement experienced people that frequent this is calculation of the casing setting chat.