Evaluation of deepwater kicks and future countermeasures

Transcription

1 WELLS AND WELL INTERVENTION Evaluation of deepwater kicks and future countermeasures Paal Skalle, Per Holand 2 and Sigbjørn Sangesland Norwegian University of Science and Technology and 2 SINTEF/ExproSoft Abstract Well control in deepwater is more complex than in coventional wells. The wells are drilled in younger formations with a narrower fracture-pore pressure margin, requiring more casing strings, nevertheless resulting in more frequent losses and gains. This is also seen in our background data which stems from 83 wells that were drilled in waters deeper than 400 m (32 ft) in the US Gulf of Mexico (GoM) in 997 and 998. Totally 48 kicks were reported, resulting in 0.67 kicks for every exploratory well. Kick killing operations in those 83 wells lasted from a few hours to more than a week, averaging to 2 days per kick, totaling to 95.8 days. Additionally 87 days were spent after establishing hydrostatic control until they were ready to resume drilling (time lost due to stuck pipe, mud losses, abandoned well etc). Kick handling and its after match represent thus 4.5% of the total drilling time. Some contractors/operators had less kicks and better handling than others. Such splendid performance, in terms of kick avoidance and handling, should be made transparent to everyone. The paper also discusses general problems associated with drilling and well control in deep waters. Potential systems for reduced well cost and improve well control are also discussed. Introduction This work is based on a project supported by US Minerals Management Service, from which interesting data were picked out. Eighty-three wells were drilled in the US GoM OCS in deep waters as shown in Table. The paper Table. Overview of the 83 wells vs. water depth. Water depth (m) No of wells Table 2 shows the mean time between kicks (MTBK) found in this study related to number of BOP-days and number of wells drilled. Twenty-five of these wells were listed as development

2 wells and 58 as exploration wells in the MMS well file 2. The frequency of deepwater kicks is high. It should be noted that the main criteria for defining a well control incident as a kick in this study is that the BOP was needed to control the event. This means that only kicks after installing the riser were studied. It also means that the majority of the "ballooning" backflows from the formation have not been regarded as a kick (since BOP was not involved). Table 2 Mean time between kicks in GoM (not including shallow kicks) Type of well wells kicks MTBK (wells) MTBK (BOP-days) Development wells Exploration wells Total As expected there are more frequent kicks in exploration drilling than in development drilling. Also nearly all the exploration wells were drilled with floating rigs, while the majority of the production wells were drilled from fixed installations. In 998 a similar study was carried out on wells drilled in the Norwegian Continental Shelf (NCS) *, as shown in Table 3. Table 3. NCS overall mean time between kicks (based on all wells drilled from )* Type of wells wells kicks MTBK (wells) Exploration wells Normal (< ft TVD) Deep ( > ft TVD) HPHT wells Development wells Total * Internal SINTEF report When comparing the results of exploration wells shown in Table 2 and 3 it is seen that the overall kick frequency in the US GoM found in this study is in the same range as in comparable wells (deep/hthp wells, but in shallower waters (50 to 200 ft)) drilled in the NCS. Kick causes First we tested kick occurrences against the actual performers involved in order to check if there were any significant relationships. The performers are the Operators and the Drilling Contractors. Table 4 shows mean time between kicks vs. operator (operator shown only as a number) while Table 5 ditto vs. drilling contractor. Table 4. Operator vs. mean time between kicks

3 Operator kicks BOP-days MTBK (BOP-days) Total Table 5. Drilling contractor vs. mean time between kicks Contractor kicks BOP-days MTBK (BOP-days) Total

4 The average MTBK varies highly. It is here important to note that each of the companies is represented with relatively few days in service. The confidence bands overlap for all the operators, indicating that a statically significant difference in kick frequency cannot be stated. It is also important to note that different wells have different difficulties while drilling, like different formations etc, leading to random statistical variations. The average MTBK should therefore not be used for ranking operators. Still, however, it is worth to note that operator and 2 (Exxon and Shell Deepwater Production) has experienced only one kick in 350 and 238 days of drilling respectively while other operators have experienced several kicks with similar number of days in operation. It should be investigated why there is such a difference. If improved drilling procedures is the cause of the observed low kick frequency, other operators should consider an adjustment of their own procedures. All the Exxon wells were drilled in waters deeper than 4000 ft! Contractor no (Transocean) carried out 2% of the drilling operations but experienced only 8% of the kicks. Here it can be stated with a degree of 90% certainty that the observed difference in kick frequency is not caused by random statistical variations. Further we tested reported kick data against two groups of causes; Depth and Operation.. Depth related causes: Increasing water depth will result in a reduction of formation strength due to reduced overburden compared to same total depth onshore. Within a selected narrow range of casing shoe depths, we found this to be true as shown in Figure, even at this large TVD (~ ft). Figure. Fracture strength decreases with water dept. The data are recorded in 7 different wells, all data are from the same depth interval (~0 000 ft below RKB) However, no significant relationship between kick frequency and water depth were found (since the kicks come from different depths / formation strength). The equivalent fracture strength (found through LOT) increases with increasing formation dept (TVD of casing shoe) as shown in Figure 2. The same goes for mud weight (or pore pressure) as shown in Figure 3.

5 Figure 2. Increasin g fracture strength as casing shoe depth increases Figure 2. Mud weight (or pore pressure) vs. well depth Figure 3. Mud weight (or pore pressure )vs. well depth Comparing the two data sets (Figure 2 and 3) the difference is only ppg or less in 50 % of the cases, especially at the shallowest well depths. Lower safety margins are compensated for by increased frequencies of flow checks. Flow checks are probably the only effective ways to detect a kick in deepwater. In such situations it is difficult to avoid taking kicks since the mud weight must be kept low. This fact explains the high kick frequency in deep water/hthp drilling operations. Many operators take for this reason regular flow checks at every 0.5 stand (every 45 ). Cautious operators seemed to have fewer kicks than average. In the situation described above, characterized by a narrow path between mud pressure and fracture pressure the formation is bound to be fractured, either fully (observed as losses) or partially (observed as ballooning). Ballooning is occurring more frequently in WBM since total losses are more readily generated in OBM. Most ballooning cases are distinguishable from real kicks as loss rate decreases with time. Ballooning is classified as a kick in those cases when the operator chose to close in the well. If not closed in the primary barrier would still be active. By lowering the ECD the ballooning and losses ceased in most cases. Surge and swab pressures are for these reasons also a significant concern for all deepwater drilling operations (especially

6 in conjunction with casing operations). Surge / swab pressures should be calculate through good hydraulic programs before tripping in order to optimize drilling and drilling fluid parameters. 2. Operation and activity: An evaluation of the operations and observations listed in the Daily Drilling Report prior to the kick led to the kick causes listed in table 6, i.e., ongoing operation and activity when the kick was detected and shut in. Table 6. Operation activities when the 48 kicks occurred Operation Activity Prod. drilling Expl. drilling Abandon well Out of hole (displacing mud in riser) Casing running Cementing Circulating Circulating only Stuck pipe Drilling activity Actual drilling 2 9 Making connection 7 Circulating 5 Trip out of hole 2 3 Tripping in hole Weighting up mud Well testing Fracturing, Circulating Total 9 39 As expected the majority of the kicks occurred during drilling operations. Of these incidents the majority were observed when drilling new hole (actual drilling, meaning bit is on bottom and rotating). Eight incidents were observed during connection. Six of the incidents were listed as occurring during circulating mud. Five incidents were observed when tripping out of the hole while only one when tripping in. Table 7 shows the most abvious / probable cause of the kick for both development and exploration wells. Table 7. Most probable cause of the 48 kicks. Barrier Total Annular losses 9 Annular losses 3 Annular losses (ballooning) 6 Gas cut mud 3 Gas cut mud 8 Gas cut mud, drilling break 3 Gas cut mud, too low mud weight 2 Poor cement 2 Poor cement, too low mud weight Poor cement, formation breakdown Swabbing 5

7 Swabbing 2 Swabbing, ballooning Swabbing, gas cut mud Swabbing, improper fill up Too low mud weight 9 Too low mud weight Too low mud weight (external riser leakage) Too low mud weight, drilling break 5 Too low mud weight, gas cut mud 2 The main problem was the low mud weight applied necessary to avoid fracture. Untypical many kicks were associated with gas cut mud. We guess that in deep wells drilled out gas will expand significantly, enough to influence bottom whole pressure. Kick handling Handling the 48 kicks are viewed in different perspectives below. General kick statistics. Killing duration distribution is presented in Table 8. Killing operations lasting longer than a day (> 50 % of all kicks) indicates inadequate handling. Table 8. Killing duration distribution of 48 kicks. Killing duration (days) < No. of kicks Pseudo-oil-based mud (POBM) were applied mainly in the ~3 section and below. No relationship existed between mud type & no. of kicks in Table 9, although mineral oil and synthetic oil are compressible, non wetting, show no spurt loss and tend to fracture the formation at a lower pressure than WBM. Table 9. Type of drilling fluid applied during 48 kicks

8 Casing section ( ) 20 6 ~3 ~0 ~7 Total Pseudo-oil based Unknown mud type Water based Most kicks were reported as gas kicks. We therefore expected to see a linear relationship between kick size and SICP in Figure 4. Since no such relation ship was dominating, the kicks could not all have been pure gas. Figure 4. SICP vs. kick size Problems during kick handling: The observed problems noted in the Daily Drilling Reports (DDR) are summarized in Table 0. Table 0. Distribution of problems during 40 of the 48 killing operations Ballooning/losses while killing Ball. Hydr. P.tr. DP Gas mig. Frac. Cem Hydrate problems Pressure transmission 3 Drill pipe problems Gas migration through cement Fracture during killing Cementing to kill the well Total Additionally some other problems mentioned together with the problems listed in Table 0 were: Took a second kick (), stripping drill pipe (3), sidetrack (2),WOW (), and jarring/fishing ().

9 Table 0 can be read horizontally to see the combined occurrences. The above-presented problems can partly be explained by the most probable related reason behind them; Shoe strength is very low in deep waters, and kill mud weight should be kept low. However, in many instances kill mud weight was not kept low, and this explains the many losses/ballooning problems during killing. Ideally the kill mud weight safety factor must be related to the pore pressure (through SIDPP): SF kill mud = (Kill MW MW) / (SIDPP/ (0.052 *TVD)) Figure 5. Relationship between kill mud safety factor and the difference LOT-strength and MW The safety factor should typically be.05 (i.e. 5 % above the pore pressure). However, instead of leveling off at around.05, the safety factor is much higher (see Figure 5). It is unwise to take out all the fracture strength in kill mud weight but rather keep it as a back up for the MAASP. Alternative solutions for deep water pressure control operations In addition to kick detection, there are two potential areas of improvement; a). Long choke/kill lines require procedure modifications due to high choke line pressure losses and b). The riser. The simplest modification needs no equipment modification; Both the initial shut in casing and drill pipe pressure must be reduced by a pressure equal to the choke-line pressure loss. The annular pressure is thus approaching static annular pressure. Another simple modification is to use a larger choke line or two or more choke-lines simultaneously to reduce choke-line pressure losses. The riser is in addition of being a handling problem also a large safety problem: If gases have entered the drilling riser before the BOP could be shut, the mud may be displaced which in turn could threaten both the internal integrity of the riser (collapse) and the external; the pressure may exceed the pressure rating of the riser and the diverter system. In deep water it is necessary to clean the BOP area after a kick; sweep the stack, fill riser with kill mud and U-

10 tube/displace kill & choke lines. This work seems to be routine work in the GoM area, taking approximately 2 to 5 hours. In the following a Conventional system is used for comparing alternative systems, alternatives which involves serious modifications of the drilling system. In this example, the Conventional system is characterised as follows: Conductor and surface casing is drilled without riser to a dept of approximately 2600 below mud line. Before drilling through the reservoir, which is located at 4400 TVD, the mud density is reduced in order to reduce formation damage. Figure 6 illustrates pore pressure, fracture pressure gradient and casing program using a conventional 8 ¾ wellhead system. From the figure it can be seen that the well can be completed using a 3-3/8 and 9-5/8 casing and 7 liner. Figure 6 Casing for the conventional system (8 ¾ wellhead) Now the alternative systems: High pressure riser with surface BOP Figure 7 illustrates pore pressure fracture pressure gradient and a typical casing program for a conventional 3 5/8 wellhead system. I t can be seen that this well can be completed using a standard 3 3/8 surface casing, a 9-5/8 and 7 casing with 5 liner. A high pressure drilling riser and surface BOP systems have been used on floating units in areas with benign weather conditions by Unocal and Shell 3. A pressurized riser being able to contain the greater formation

11 pressures, implies either exotic materials or a reduced diameter riser. As a result of a smaller diameter riser, smaller wellhead and production trees must be designed. However, a 2 pressurized composite drilling risers made of exotic material could possible mitigate this problem but this solution is at least for the time being economically not a viable option. Figure 7. Casing program for surface BOP systems (3 5/8 wellhead) However, the well control issues are simplified since such a system have eliminated the long lengths of the kill- and choke lines to the subsea BOP and trapped gas in/above BOP is eliminated. In many areas with harsh weather conditions, a system without a subsea BOP have its limitation. When it becomes necessary to leave the location this will require some type of subsea shut-off device. In order to re-connect the riser after an emergency disconnect, the subsea shut-off or disconnect BOP must be designed with considerable attention. New development with expandable tubular may increase the application of high pressure riser systems. Dual gradient drilling systems Dual gradient drilling systems are based on returning the drilling fluid back to the drilling vessel through a separate conduit using a subsea located pump and using a sea water filled standard marine drilling riser. A sketch of this system and resulting well pressure are shown in Figure 8. Several of the dual gradient systems are now being tested and commercialised 4.

12 Figure 8. Dual gradient drilling system and its implication on the well pressure (after 4 ) Figure 9 illustrates the seawater gradient, mud gradient, pore pressure gradient and fracture pressure gradient for a dual gradient drilling system. It is seen that this well can be drilled and completed using a standard 3 5/8 wellhead with 3 3/8 surface casing, a 9-5/8 casing and a 7 liner. This system allows deep water wells to be completed with a reduced number of casing strings. Still, well control is an issue since any kick have to be diverted through the relatively small conduits to surface and be handled by the pumping system. The main advantage with these systems is that the mud density can be designed so that wells can be drilled with larger safety margin. This can be seen from Figure 9 where the mud density is higher and hence more parallel to the pore-pressure gradient. Figure 9. Casing program for dual gradient systems (3 5/8 Wellhead)

13 Low Riser Return and Mudlift system (LRRS) in combination with a pressurised riser, surface BOP and a subsea closure device. The main element in such a system is a pump connected to a high pressure riser section. The mud level is dropped down to a level considerably below sea level and the level is continuously being adjusted by the mud lift pump. As a consequence the bottom hole pressure will also be continuously adjusted, which will reduce the needs to adjust mud-weights while drilling. Details of this system is presented in another DOT paper 5. Figure 0 illustrates the mud gradient, pore pressure gradient and fracture pressure gradient for a single gradient drilling system. It is seen that this well also can be completed using a standard 3 5/8 wellhead with 3 3/8 surface casing, 9-5/8 casing and a 7 liner. The system offer increased flexibility, i.e., the need to adjust mud-weights is reduced and the ECD effects can in many ways be neutralized. Adjusting the mud weight and the hydrostatic level in the riser allows for more optimized pressure conditions in the borehole as illustrated in Figure 9. Drilling depleted reservoirs allows simple drilling fluid system to be used, i.e., no need for light fluids such as foam, air, etc. The well control issue is simplified since the annulus in the pressurized riser is used for kick circulation. Figure 0. Casing program for new mudlift system (3 5/8 Wellhead) Discussion Counting up the two most obvious water depth related problems we fond 4 hydrate problems and 8 pressure transmission problems. These data points were too few to detect any trend (vs. increasing water depth). Hydrates can plug BOP / kill / choke lines, interfering with effective well control. Although not many signs of gas hydrate were seen, the risk of loosing operating control

14 of the BOP is always present, and mud systems should be formulated to suppress gas hydrate formation. A clear indicator of pressure transmission problems was the cases when no shut in pressure was seen on drill pipe or annulus, but still the well started to flow when the annular preventer was re-opened. This unexpected flow was either caused by gas in the annulus, and its potential pressure was hidden or unable to be transmitted through the long choke. Sometimes we also saw a lower SICP than SIDPP. A strange behavior was seen by gas kicks when they surfaced. Very seldom pure gas was seen, especially in deep water or long wells ( ). When large kicks reached surface they showed up only as gas cut mud, typically the mud was cut down 3 PPG. This can only be explained by axial dispersion of gas on its way up. Such behaviour of the gas, stretching out as it moves, is advantageous. It suppresses the pressure peak when gas arrives at the choke manifold and makes it possible for the Poor Boy degasser to separate out the gas from the mud. Early kick detection is important in deep wells due to the gas expansion potential of even small kicks. Large kicks are difficult to deal with in deep water due to the long choke lines and low margin. Since flow checks are time consuming, we must focus on early detection methods. More accurate flow measurements (electromagnetic meters) in the return line increase both the well safety level and the well economics. Long kill and choke lines contribute to the added concerns of being able circulate out the kick without exceeding the formation strength. This paper seem to confirm this concern in that formation ballooning and losses was experienced in more than 75 % of the kicks. Probably several of the cementing jobs that were done, came as a result of not being able to circulate out the kick or as a result of losses to weaker formations. Hence, the added problems as a consequence of long choke lines and weaker formations are the contributor to the majority of problems associated with well-control procedures in deep waters. With regards to simple alternative systems not yet considered extensively, one is to install a pump at the seabed in order to boost or pump the return fluid up the chokeline thereby letting the pump compensate for the chokeline friction, as in the dual -gradient method. However, caution should be raised as the ability of the pump system to handle large amounts of gas, hydrates and other problems associated with kicks. Secondly, this will introduce added difficulty for the rig crew to handle a kick scenario with large amount of gas into a subsea pumping system. One option could be to decrease the pump-rate during kick circulation. A too low pump rate might, however, introduce other hole problems like hole cleaning. The killing method with least chance of fracturing weaker formations is the volumetric method. However, this method is time consuming and difficult, and most operators and drillers tend to avoid this method as can be read from the results. The method was reported applied only in one case, although more than 50% of the well killings experienced losses or other problems due to exceeding the formation strengths. By using the dynamic volumetric method; i.e., letting the gas expand to surface under constant volume, while circulating down kill-line up choke-line at the same time, could possible have prevented some of the severe hole problems experienced. However this method also becomes increasingly difficult due to the extreme length of chokelines. Conclusion Although this study is based on few wells (83), clear trends with respect to deep water well control aspects are confirmed. The fundamental understanding and handling of deep water well control problem is at an acceptable level in the GoM area. Some operators and some

15 contractors, however, had a far better record with respect to kick frequency and effective kick handling. Obviously there is a potential for improvement, and this can be achieved through experience transfer. There was no indication that the well depth or the maximum theoretical shut-in wellhead pressure were linked to the likelihood of kick occurrences. The most probable cause behind kicks were gas cut mud and/or too low mud weight. This occurred in 32 of the 48 kick incidents. Kicks occurred most frequently during actual drilling. These facts support the main explanation behind the high kick frequency while drilling in deep water; operating on the boarder lines of the narrow path between pore and fracture pressure. During killing operations 29 cases of ballooning/mud losses were reported. This also supports the main explanation behind high kick frequency; border line drilling. Simple countermeasures exist, like adjustment of the riser or apply alternative killing procedures. A fancy method like the volumetric method is in little use, although it produces no friction and thus the theoretically least wellbore pressure during killing. In spite of being a practical challenge the method needs to be reintroduced for deep water drilling purposes. In order to mitigate and compensate for the specific subsurface conditions encountered in deep water, new development in equipment and procedures will be needed. The one main conclusion is that serious re-thinking of the use of a large size marine drilling riser and a subsea BOP should be undertaken. The use of a pressurized drilling riser and a surface BOP should be revisited. Several new developments are underway to mitigate the narrow margin between pore pressure and formation strength. Although all methods claim to be able to at least maintain the same level of well control safety, a conscious note should be raised as to the practicality of well control procedures with several of these new methods. References. Holand, P. and Skalle P.: "Deepwater Kicks and BOP Performance" SINTEF Report STF38 AA049, Trondheim, Well Information, US GoM OCS, Borehole file 3. Gallagher, T. and Bond, D.F: Redefining the Environmental Envelope for Surface Bops on a Semi-Submersible Drilling Unit, SPE/IADC paper 67709, proc at the SPE/IADC Drilling Conference, Amsterdam, 27 February March Schumacher, J.P., Dowell, J.D., Ribbeck, L.R. and Eggemeyer, J.: Subsea Mudlift Drilling: Planning and Preparation for the First Subsea Field Test of a Full-Scale Dual Gradient Drilling System at Green Canyon 36, Gulf of Mexico, SPE paper 7358, proc at the 200 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-3 October Sangesland, S. and Fossli B.: Riser lift pump system, proc. At the XIV Deep Offshore Tech. Conf., New Orleans, Nov. 3-5, 2002.