ENERGY AND POWER DMCC

PT-WELL 6240 Case Studies
  Abstract 

A high ratio of success has been seen in removing formation damage from older heavy oil wells using an asphaltene suspending agent in conjunction with a selective stimulation tool. Treatment involves spotting the agent at the formation face and in the immediate well bore region, allowing it to soak for a minimum of 16 hours, and then over flushing with a high volume of light crude at sub fracturing pressure. Results are shown from a number of wells from three different fields. Incremental production has been as high as 8X and has been sustained for as long as 18 months. 
 
Introduction 

Determining whether or not a well is producing to its maximum potential and, if not, how to remedy the situation is never a simple task. Notwithstanding, there are certain factors which can make a given problem within a given field more likely to occur than others. An excellent example is asphaltene problems in heavy oil wells. Asphaltenes are highly aromatic compounds containing small amounts of sulfur, nitrogen, and oxygen which give rise to a molecule with a partially positive charge. The resulting structure is held together through n-n, hydrogen and acid-base bonding whose molecular weight has been reported to be a function of its environment: environments that favor dissociation of the individual units, such as higher temperatures and higher degrees of solvent aromatic, result in lower molecular weights and thereby result in suspension; conversely, environments that favor association, such as lower temperatures and less aromatic solvents, result in higher molecular weights and thereby result in flocculation and precipitation.! Typical Lloydminster heavy crude 
 
PT-WELL 6240 Case Stories
 
contains between 12% and 15% asphaltenes by weight, although it can contain as much as 22% in some fields. Essentially insoluble in oil by themselves, asphaltenes are held in suspension in oil by natural surfactants called resins. However, the bond holding the resins to the asphaltene is rather weak; resins can be stripped from the asphaltene through contact with light end alkanes as well as through variations in temperature and pressure. Thus, asphaltene precipitation can occur through the production process itself (due to decreased temperatures) or can be induced through the use of loading fluids containing high amounts of light end alkanes. When asphaltenes do precipitate, it is likely that they will crystallize on a negatively charged solid, such as sand or clay. If the crystal is produced along with the sand. this precipitation does not represent a production problem (although it may cause a subsequent treatment problem). If, on the other hand, the sand/asphaltene conglomerate is not produced and enough sand is held together by this asphaltene type 'cement', the wellbore can eventually clog. Producing heavy oil through this blockage would be similar to filtering cold molasses through a high mesh filter. 
 
Methods used to correct inflow problems due to asphaltenes have typically involved re-perforating or the use of solvents, either alone or in a 'blend' with oil. Historically, re-perforating heavy oil wells gives a short term increase in production. And, as was stated previously, non-aromatic light ends cause precipitation of asphaltenes. Thus, using solvents which contain light ends will likely exacerbate rather than cure inflow problems. Aromatic solvents, on the other hand, while able to dissolve asphaltenes to a much greater extent, typically only give short term results and if improperly used, can cause major swelling problems of stator compounds. Moreover, highly aromatic solvents must be used with caution due to their low flash points and the fact that they are a health and environmental hazard use of molecules which mimic the natural resins in oil can greatly enhance any solvent's ability to remove asphaltene damage by restoring the asphaltenes to their initial suspended state. Further, when used with a non or low-aromatic carrying fluid, they can do so without the negative effects of aromatic solvents.   Lab Testing  The fluid contains PT-WELL6240, a high molecular weight molecule tailor made by ProTec to mimic resins. Tests performed demonstrate that precipitation of asphaltene from oil, induced by contact with ethane, can be dramatically reduced through the addition of 4% by weight of PTWELL6240. To test the ability of PTWELL6242 to resuspend asphaltene, we added asphaltite (gilsonite ground with a mortar and pestle) to Husky's Cutter Stock E alone and with PTWELL6242 and left the mixtures to soak at room temperature and ambient pressure (Tables 1&2). First, 1.5g of asphaltite was added to 700mL Cutter Stock E and left to soak for 24h before being gravity filtered through a 100mesh screen. All 1.5g of asphaltite was recovered on the filter, indicating that none of the asphaltene had been suspended. When the test was repeated with 15% PTWELL6242 in Cutter Stock E (equal to stimulation fluid), only 0.3g was recovered, indicating that 1.2g of the asphaltite had been suspended in the blend. Suspecting that saturation had not been reached in the initial test due to a shortage of exposed surface area on the remaining asphaltene (i.e. the remaining particles were too big), the test was repeated with 10g of asphaltite. In this case 6.4g of asphaltenes was recovered after a 24h soak in fluid, indicating that 3.6g was suspended. Table 1 depicts the effects of using differing concentrations of PTWELL6242 on suspending 10g asphaltite. While the data in Table I suggests that using concentrations much higher than 15% PTWELL6242 would give better stimulation results, the costs of doing so would be much higher. Fortunately, the same effect can be achieved through the use of longer soak times. As is shown in Table 2, the longer the fluid is left to soak, the more asphaltite is suspended.  After five days of static soaking, 17.7g of asphaltenes was suspended Tests to determine the saturation point were under way at the time this paper was submitted.
  Treatment Technique Fluids were pumped using a Standard C&A triplex pumping unit with a pressure chart recorder and a barrel counter. An opposable cup-type selective stimulation tool (Figure I) with a 30cm wash interval was used to help ensure complete coverage of the formation with the chemical. Also, given that most wells in the Lloydminster area cannot hold a full column of fluid, a fluid control valve was used to maintain hydrostatic pressure. This helped to ensure that the chemical was metered out evenly and avoided the risk of having an entire tubing volume sucked into a single 30cm Stage. Pressure testing the tubing and tool was performed with Wainwright crude. The perforations were then found by pressuring to 4MPa and moving the tool toward the anticipated perforation interval until the pressure bled off. The crude was then injected into the formation in equal volume Stages at a constant rate while pumping AS-l at surface. The volumes for this injection test were calculated such that once the last stage was complete, all of the oil would have been pumped out of the tubing and the fluid would then be at the formation. For all wells treated, the volume of fluid used was between 0.1 - 0.2m3 per 30cm interval. If-a formation porosity of 33% is assumed, these volumes would provide an effective radius of treatment of approximately 0.5 - 0.7m.  Once the fluid was injected, the tools were pulled and hung above the perforations overnight while the formation soaked for a minimum of 16 hours. The injection test was then repeated, followed by an overflush through the stimulation tool with 1 - 2m3 per 30cm interval with Wainwright crude at maximum rates under fracturing pressures. The intent behind this overflush was threefold:  1. Overflushing with 1 - 2m3 of oil per 30cm increases the radius of treatment (2 - 2.6m with 33% porosity);  2. Overflushing serves to disperse the suspended asphaltenes in the same manner that rinsing your car after scrubbing it with soap disperses the suspended dirt particles;  3. Overflushing at a high rate and pressure ensures that the previously cemented sand particles are mechanically separated and move more easily.  
(This effect is reduced due to the decreased flow rates permitted by the fluid control valve used.)
 
Case Histories  All wells reported are in the Tangleflags, Gully Lake, and Rush Lake areas of Saskatchewan. Although some wells were treated without the selective tool or without any significant soak period and subsequent overflush, no real successes were seen from these stimulation techniques. Thus, the case histories below are only from those wells treated through a selective tool using a full two-day technique. All wells reported have been on production for at least nine months since treatment, and many for more than twelve months. 
 
Case History # 1 -

1st Tangleflags Well  This well was newly completed in the General Petroleum formation in November, 1979. As of July, 1995 its cumulative oil production was 16,401m3. The average production from the well for the ten months prior to stimulation was 189m3 oil per month (6.3m3/day) with highs of 300m3 and 290m3 in March and April, 1995 respectively. Production declined dramatically in June and July when the well produced 66m3 and 68m3 respectively. This decline corresponded to a large inflow of clay and sand and to the frequent servicing required to remove this inflow. In an attempt to correct this inflow problem, a fluid treatment was performed on August 3 and 4, 1995 using 2.0m3 of fluid over 8.9m of perforations.  In the two months after treatment, the well produced 149m3 and 176m3 of oil respectively. The oil produced after the treatment contained very high sand and clay cuts, indicating that the treatment had been effective in freeing up the immediate formation. In the following month, however, production dropped back to 64m3 when the well sanded-in with the same type of deposits. Given the short term success that was seen from the initial treatment, a second treatment was performed on November 17 and 18, 1995. Although this treatment was unable to return production to the highs seen March and April, the well has averaged 111m3 since this second treatment.  Given the type of deposits and the degree of 
success seen from the treating of this well with fluid, it is likely that the inflow problems associated with this well are due more to the difficulty in producing sand with very high clay content than to solely asphaltene problems. As such, this well is a not-so-gentle reminder of the difficulty encountered in differentiating inflow problems that result from mechanical flow aberrations from those that result from chemical anomalies! 
 
Case History #2 –

1st Gullyy Lake Well  Originally completed in the Sparky formation, this well was plugged back and re-completed in the Waseca in June, 1988. The tubing was changed from 73mm to 89mm and the pump from a jack type to a high torque rotary in February, 1995. The production after these equipment changes increased from less than 1m3 to slightly over 2m3 oil per day for a two-month period before declining to initial rates. In the ten months prior to treatment, the well averaged 39m3 oil per month (1.3m3/day) with 50% down time. The cumulative oil production from this zone ,vas 8555m3. The treatment was performed on August 30 and 31, 1995, using 2.7m3 AS-lover 6.7m of perforations in two intervals. Despite having bailed 9.5m of sump before the job, sand was encountered on the second day near the bottom of the lower set of perforations, indicating that approximately 0.2m3 of sand had entered the well. In the month after stimulation the well produced 210m3 oil (7m3/day). Over the following 10 months, the well produced an average of 304m3 oil per month (10.lm3/day) with only 5% down time. A high of 506m3 (16.3m3/day) was reached in the month of September, 1996 with the aid of a tandem pump. The total incremental oil production from this well since the time of treatment has been over to 5500m3. Water production, on the other hand, has remained at approximately the same rate as that prior to treatment resulting in a greatly decreased percentage cut of total fluid.
 
The high quantity of sand liberated by the treatment suggests that the sand particles had been 'cemented' together by asphaltenes which inhibited production. Treating the asphaltene buildup with PT-WELL6242 re-suspended the asphaltenes and other high molecular weight hydrocarbons, 
 thus allowing the sand and, therefore, oil to be produced Because no other changes or modification were made to the well (i.e. no equipment changes or re-perforations were made) at the time of treatment, the resulting success is an excellent indicator of the potential of the fluid treatment for stimulating production and has been a strong justification in Husky incorporating this fluid stimulation treatment as a significant part of their production optimization strategy.
 
Case History #3 -

2nd Gulry Lake Well  This well was completed in the Waseca in March, 1971. The average oil production from the well for the ten' months prior to stimulation was 44m3 per month with 19% down time. The cumulative oil production was 15819m3. The treatment was performed on October 5 and 6, 1995 usingO.75m3 of AS-lover 1.8m of perforations.  After producing 99m3 in November and 55m3 in January, the well was shut-in for most of the following year. Given the slight increase in production following the stimulation, it is possible that not enough fluid chemical was used in the time frame allowed to remove sufficient damage from the formation to stimulate production. However, the possibility that the well did not have damage that could be removed with fluid can not be ignored Given the well's high cumulative oil production from a thin zone, this scenario includes the possibility of a depleted reservoir. 
 
Case History #4 -

3rd  Gulry Lake Well  This well was completed in the Waseca in August 1979. The well's cumulative production as of October, 1995 was 8776m3. Upgrading the equipment to 89mm tubing and a high torque rotary pump in June, 1995 increased the production from 7m3 oil per day to an average of 12m3 over the following two months. A treatment using O.85m3 of AS-lover 2.5m of perforations was performed on O:tober 16 and 17 after production had declined back to previous rates. After sandingin in late November, the well was re- perforated and a pump surface was performed With only 6% down time in the ten months after treatment, this was one of the few times the well was serviced as compared to 16% down time in the ten months prior to treatment. The production over the ten 
 
months after treatment averaged 322m3 oil per  month (10.7m3/day), as compared to 219m3 (7.3m3/day) before. This increase represents 1029m3 of incremental oil production during this period 
 
Case History #5 -

1st  Rush Lake Well  This well was newly completed in the General Petroleum in June, 1988 and had cumulatively produced 11274m3 of oil as of November. 1995. The well produced an average of 206m3 oil per month (7.0m3/day) for the ten months prior to treatment. Approximately eight months prior to treatment the well had been producing 6m3 of oil per day with a high fluid level (80 - 150 map). It was found that by loading the well with 4m3 of lease crude, the production would increase to 11m3 for a few days before pumping dry. However, when the pump was slowed back to 6m3 per day, the well would no longer retain a fluid level. In June, 1995 the well's tubing and pump were upgraded to 89mm and to a high torque rotary respectively. No significant increase in production was seen as a result of these changes. This information, along with the knowledge that offsets had very high production rates, suggested that the well had an inflow problem. In an effort to save rig time and minimize costs. A fluid treatment was performed in conjunction with a re-perforation on November 22, 1995. The treatment used 3.5m3 of AS-lover 1.9m of perforations.  Since the treatment, without the aid of the loading program, the well has produced an average of 623m3 oil per month (20. 1m3 /day) over a period of fifteen months, with a high of 1080m3 in December, 19%. The total incremental oil production during this period was over 6200m3. 
 
Case History #6 -

4th  Gulry Lake Well  This well was initially completed in the Waseca in September, 1984 but had been shut-in from November, 1992 until June 22, 1995. At this time, 89mrn tubing and a high torque rotary pump were installed. In the following six months the well averaged 191m3 oil per month (6.4m3/day). On Jan 11 and 12, 1996 a treatment was performed using 2.3m3 of fluid with 20% PTWELL6242 (versus the normal 15% blend) over 1.0m of perforations. Sand clean was performed on 
 
February 1, 1996. To better keep up with sand inflow, the well was re-perforated on May 15, 1996. 
 
Since the treatment this well has averaged 284m3 oil per month (9.5m3/day) with a high of 411m3 in October, 1996. The incremental production from this well since treatment is over 1350m3.
 
Case History #7 –

2nd  Rush Lake Well This well was newly completed in the Sparky in May, 1981. In the ten months prior to treatment, this well averaged 96m3 oil per month (3.2m3/day). A fluid treatment using 2.2 m3 over 15.3m of perforations was performed in conjunction with a re-perforation and a pump upgrade on June 5 and 6.  Since the treatment, the well has produced an average of 106m3 oil per month (3.5m3/day). This slight increase in production has occurred despite the fact that the well has not been serviced since the treatment (i.e. no down time) as compared to 60% down time in the ten months prior to treatment.  From these results it obvious that the treatment did little to increase oil production. However, whether the ineffectiveness of the treatment was due to the well not having asphaltene damage, or to an ineffective method of treatment (i.e. the quantity of fluid used and/or the time it was left to soak was insufficient to remove the asphaltene damage present) is impossible to determine. 
 
Case History #8 -

5th  Gully Lake Well  For the ten months prior to treatment. this well averaged 117m3 per month (3.9m3/day).4 A fluid treatment was performed in conjunction with an equipment upgrade on June 13 and 14, 1996 using 1.5m3 of AS-lover 4.4m of perforations.  Since the treatment the well has produced an average of 281m3 oil per month (9.4m3/day) with a high of 443m3 in July. The incremental production from this well since treatment is over 1600m3. 
 
Case History #9 –

6th  Gully Lake Well  This well was newly completed in the Waseca in July, 1981. For the ten months prior to treatment. the well averaged 175m3 oil per month (5.8m3/day). Its cumulative production as of May, 1995 was 15 392m3. A fluid treatment was performed in conjunction with a tubing and pump upgrade on June 15 and 16, 1995 using 1.0m3 of fluid over 3m of perforations.  Since the treatment the well has produced an average of 258m3 oil per month (8.6m3/day) over a nine-month period. The represents over 750m3 of incremental production during this period.
 
Conclusions 

Given that more than one change was made to the well at the time of treatment to many of the wells treated, it is difficult to draw any definite conclusion from the information above. Nevertheless, the first well treated in Gully Lake demonstrates that the treatment is capable of increasing oil production through the removal of blockage effecting sand inflow. And, given the nature of the chemical involved the blockage removed is likely asphaltenic in nature. (Tests to measure the difference in asphaltene content within oil produced from a well before and after treatment were underway at the time this paper was submitted) A more obvious conclusion that can be made is that not every well treated results in increased oil production. This being said, many of the wells treated produce slightly more than they had previously, while a few of the wells treated such as the well just mentioned, produce a great deal more than they had previously. Also, given the volume of incremental oil produced in these latter cases, only a very few dramatic successes are required to justify treating a number of wells. Overall, twenty-nine wells were treated with fluid over a 6-month period on the Saskatchewan side of Lloydminster using a two-day technique and a selective stimulation tool. Eighteen of these wells had sufficient incremental production within the first six months of treatment to more than offset the cost of treating the well. (Although this does not include the cost of the equipment installed on these wells, it is assumed that this equipment can be utilized elsewhere in the cases where the treatment is unsuccessful.) Of these eighteen wells, five have shown incremental production for at least one year, resulting in over 6,500m3 of increased production. Assuring a net profit of at least $90per cubic meter of oil over this 
 
period, these five wells alone have generated over $1.5M in sales over and above their previous production. For the previously mentioned eighteen wells, the total incremental oil production is over 29,000m3. Using the same figure for net profit, this represents $2.6M in incremental sales thus far. 
 
Although it is tempting to attribute the above results entirely to the effectiveness of fluid, to do so would be erroneous: it is obvious that having open perforations and a pump that can keep up with sand (and clay) production is just as important to successful oil production as having an unplugged wellbore. However, the results from wells, such as the first Gully Lake well (which was not reperforated and where the pump was not changed at the time of treatment) are an important testimonial to the benefits of stimulating heavy oil wells with fluid.  To further increase the success ratio of the treatments, some treatment modifications are proposed:  1. Extending the duration of the soak period is the most cost effective method of increasing the potency of the treatment because the additional time maximizes the advantage of the slow acting nature of the chemistry involved.  By performing the first day of the treatment on a Friday, leaving the rig on the hole with the tool hung above the perforations, and returning the following Monday to perform the over flush, a soak period of approximately 72h is utilized.  From the lab test results, the effectiveness of the chemical and, therefore, the probability of success would be greatly enhanced over this time. 
 2. A faster method of ensuring a more effective job, though not as cost effective is either to increase the volume of fluid used and/or to increase the percentage of PTWELL6242 in the blend.  Using a greater volume of fluid is the most efficient of these two methods because it ensures both a greater amount of asphaltene suspension over a given period of time and a greater radius of treatment for nearly the same cost as doubling the PTWELL6242 in the blend With the degree of success seen in the work performed to date, increasing the volume of fluid used to a minimum of 0.2 - 0.3m3/30cm interval could be easily justified where time is a factor. 
 

Tank Cleaning Case Studies

  7 Crude oil storage tanks:

  Petroplus Tank storage, Milford Haven, Wales, U.K.

 Scope of work:uShore tanks No's 01,02,05,06,09, 10 and 11 contained residues amounting to a total in excess of 25,000 cubic metres at varying depths from 1.20 meter to 3.55 meters
The crude oil residues were from varying types of crude oil being mainly Maureen crude, Brent crude, Soviet export blend crude and Arabian heavy and light crude oil. 
Specifications:
All tanks were to be cleaned and 95% of residues to be removed in order to regain maximum shore tank available space. All crude oil residues were to be suspended into a state that allows it to be pumped out and remain suspended during shipping to the client’s Antwerp refinery where the resultant mixture would be blended by the refinery and sent to the refining units.

We injected our chemicals into the first tank and then added crude oil in order to have a liquid in which to suspend the residues. The tank contents were then re -circulated using circulating nozzles through the floating roof seals and floating roof leg supports until it was established that residues had been suspended. The tank contents were then pumped to the next tank requiring cleaning and the process was repeated. More chemicals and crude were added as and necessary in order to speed up the cleaning process. It took only 63 working days to complete the whole contract (7 tanks).
Conclusions:

We successfully completed the contract utilising the cleaning system and chemicals. All suspended residues were shipped to the clients Antwerp refinery for refining. At the time of this operation crude oil prices were approximately $33 -$35 per barrel and our client received into the refinery in excess of 155,000 barrels for processing. This in itself, if estimated at $26.00 per barrel would be a return of in excess of $4,000,000.

CRUDE OIL TANK
Ardmore, Olakhoma
Scope of work
This tank had 2000 barrels of sludge (458 Tons) that consisted of paraffins, asphaltenes, and other sediments. The tank was to be cleaned for hot work. The extracted sludge was to be centrifuged by customer’s centrifuge plant.
Specifications:
Customer specifications required that oil from circulation be stripped at less than 0.5% BS&W and transferred to another tank. Bottoms were to be hauled to the centrifuge plant.
TexChem Performance:
TexChem injected our chemical into the tank and circulated the slurry and hydraulically jetted clean oil back to the tank. Recovered oil not needed for recirculation was pumped to the adjacent tank. After stripping the clean oil to the other tank, bottoms were pumped from the tank to a filter roll off box. Slurry from the filter was hauled by vacuum trucks to the plant centrifuge. TexChem pulled the tank seal and washed the tank until clean.
Conclusion:
TexChem cleaned and processed the oil of this tank utilizing our patented tank cleaning system in record time without the use of heat in the tank cleaning operation , without the use of cutter stock, with no measurable organic vapor emissions. This 150 foot diameter tank with external floating roof was cleaned up in 9 calendar days including mobilization and demobilization.

Phillips Refinery Tees Side  England
Tank P602F Heavy Fuel Oil Tank
The tank was 62 metres in diameter  fixed coned roof containing 800 M3 of heavy fuel oil residues and crude oil steam treated  residues  with a pour point in excess of +34 degrees celsius.  The tank was to be cleaned for change of use to contain chemical grade Naphtha.
2,700 metres in length of steam heating coils were to be removed and the internal 36 inch internal import diffuser line removed.
All residues were reclaimed into refinery book stock and the tank was returned to service in the condition required.
Time taken was 43 days from initial mobilisation and the first meter of  Naphtha transferred to the tank passed all laboratory analysis without any bottom flushing being required.

Petroplus Tank Storage Milford Haven Wales 

56 Metre diameter floating roof crude oil tank to clean for the storage of Aviation Kerosene. The tank contained 3,400M3 of crude oil residues which were fluidised and returned to book stock and the tank internally below roof level and above roof level to include roof seals removal and removal of internal pipework not required.
Tank floor epoxy coatings and below roof  coatings were to be removed and left in condition suitable for recoating.
Leaking pontoons were to be repaired.
All tank surfaces were inspected and chemically wall washings taken and analysed by the onsite laboratory to verify that the tank met the required standards.
Total time taken for the project to include mobilisation, removal of epoxy coatings and demobilisation was 53 working days.

Vopak Oil Terminal Europoort Rotterdam 

The terminal had suffered from an accident where the 62 metre diameter floating roof crude oil storage tank had a damaged floating roof due to the roof water drain valve that was left in the closed position resulting in the roof collapsing due to the weight of water. The Dutch health and safety Executive forbidden tank entry into the tank due to the serious instability of the tank roof.
We were asked to help as the tank also contained 4,200M3 of crude oil residues.
All residues were extracted in a liquid form and transferred to tank storage.
We were also contracted to remove the damaged roof ready for a new floating roof to be constructed.
Total time taken for the cleaning of the tank, making the roof safe and final removal of the roof in sections by crane was 64 working days.
Upon successful completion of this hazardous operation the terminal offered two more tanks of the same size for cleaning to hot work standards to be undertaken during 2004 which we completed in a total time of 67 working days.

Novopolotsk Refinery Belarus

4 tanks to clean and to reclaim all residues to refinery book stock. Total residues removed 7,900M3 of Russian export blend.
Tanks were to be cleaned for maintenance purposes with the requirement for hot work.
All four tanks were cleaned with the residues being transferred from tank to tank with the final residues being transferred to an underground storage tank for further processing and blending to refinery specifications.
All tanks were of the fixed roof type being 36 metres diameter.
Total time taken to include delays incurred in order to fit in with operational requirements was 98 working days.

Gomel Refinery Belarusu

2 tanks to clean to hot work specifications
Total residues reclaimed 4,600 M3 and time taken 42 days.
The tanks were of the fixed roof type.

Shell Nigeria - Bonga
2 tanks Slop Oil Tanks with severe naphthenate issues – residue was rock solid.
Took 10 days to complete the work

Shell Nigeria – Sea Eagleu

2 tanks Slop Oil Tanks with severe naphthenate issues – residue was rock solid.
Took 10 days to complete the work and two additional weeks to cut and remove sections out.