When completion or workover operations are conducted on a well (perforating, gravel packing, etc.), the fluid present in the wellbore must minimize the impact on the near-wellbore permeability. Several decades ago, engineers realized that the use of drilling fluids during completions was inappropriate because fluids caused severe damage to the productive zone. A wide variety of fluids are now available as completion or workover fluids. This page focuses on formation damage issues related to these different types of completion and workover fluids. A list of fluids used for completion or workover is provided in Table 1.
Fan, Songlin (Petroleum Engineering Research Institute of Petrochina Dagang Oilfield) | Wang, Xiaofang (Petroleum Engineering Research Institute of Petrochina Dagang Oilfield) | Dong, Jun (Petroleum Engineering Research Institute of Petrochina Dagang Oilfield) | You, Qiuyan (Petroleum Engineering Research Institute of Petrochina Dagang Oilfield) | Yang, Xiaochun (Petroleum Engineering Research Institute of Petrochina Dagang Oilfield) | Zhao, Junfeng (Petroleum Engineering Research Institute of Petrochina Dagang Oilfield)
Dagang Oilfield is a part of oil-gas reservoir with various reservoir types, broken fault block, high heterogeneity and complex geological situations. For example, in low pressure and high permeability reservoirs, permeability is higher than 2000 mD and pressure coefficient is less than 0.5. The salinity of formation water in low permeability reservoir is as high as 30000 mg/L, and the pour point of crude oil is as high as 40 °C. The statistics show that the average recovery time of the well yield after remedial work is over 7 days, and the average recovery rate of the well yield is less than 87% in Dagang Oilfield, which have an influence on the stable production and the benefit development of the oilfield. The problem above has not been effectively resolved for a long time because of the factors of technology and cost. In this paper, a series of low cost formation protection technology were developed. First, the low-cost nitrogen microbubble temporary blocking technology, which can block 2 mm aperture, was developed by improving preparation technology of nitrogen microbubble working fluid and adding degradable temporary blocking material. Second, the formation protection for complex low-permeability reservoirs was developed by enhancing the temperature of workover fluid and adding the high efficiency surfactants. The results show that the temperature of workover fluid increases by 20-50 °C. Finally, the low-cost workover operation technology with formation protection was developed. The cost can be reduced more than 50% while protecting the formation. So far, the all technologies were successfully applied in 2135 wells. After the application of technology, the average recovery time of the well yield is 3.5 days, the average recovery rate of the well yield is 96%, and the total production loss is 15.7 ° 104t. The problem of the formation pollution during the workover has been effectively resolved, which provides technical support for the production stability of complex fault block oilfield.
Jia, Hu (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Yang, Xin-Yu (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Zhao, Jin-Zhou (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University)
Hu Jia*, Xin-Yu Yang, and Jin-Zhou Zhao, State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University Summary Foams can be used as well-killing fluid for workover operation in low-pressure oil and/or gas wells. However, foams usually come from gas injection under high pressure or high-speed stirring, which is complicated, expensive, and hazardous. In addition, the foam's stability is still limited by the current method of adding viscous polymer or the single crosslinking between the polymer and single crosslinking agent. This systematic study consists of optimization of different foaming agents, gel bases, and the effect of the GPC compositions (carbonate and acid) and their quantity, a macroscopic comparison of the stability and rheological properties of the double crosslinking and the common single crosslinking systems, with further investigation of their stability differences through microscopic research, and a coreflooding experiment to evaluate working performance. Within 4 days, the density of this novel foamed gel varies from 0.711 to 0.910 g/cm This is because of the function of the GPCs and foaming agent, which means that finer foams can be obtained to achieve target low density. Meanwhile, on the basis of the double crosslinking, a more compact gel structure is formed; thus the stability can be effectively improved. Results also demonstrated that this foamed gel shows a favorable performance of low fluid loss and temporary plugging, and the gas-permeability-recovery rate is up to 93.90%, which proves the gel to be effective for formation-damage control. This study suggests that the novel in-situ-generated foamed gel has the potential to achieve favorable well-workover performance in low-pressure and low-temperature reservoirs. Introduction In the later stages of mature oil-and gasfield development, workover is a frequent job for oil and gas wells. For safety consideration, pumping killing fluid into the wellbore is often a prerequisite to providing well control, even in ultralow-pressure reservoirs.
Jia, Hu (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation at Southwest Petroleum University) | Chen, Hao (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation at Southwest Petroleum University)
Using mature Cr3+/partially hydrolyzed polyacrylamide (HPAM) gel can reduce filtration for water shutoff in the fractured reservoir. Whether the mature gel can act as a fluid-loss-control pill for well-workover operation is worth investigating. In this paper, we start a systematic experimental study to reveal the physical process and fluid-loss-control mechanism of the Cr3+/KYPAM (salt-tolerant polymer) gel used for overbalanced well workover. The polymer gel used in this study is formulated with a combination of 0.4 to 0.6 wt% KYPAM and added 0.02 to 0.04 wt% chromium acetate, which can provide a gelation time between 2 and 4 hours, and with a maximum gel strength of Code G at a temperature of 30°C. Results show that the mature Cr3+/KYPAM gel can withstand positive pressure of 10 MPa for a period of 120 minutes with average fluid-loss volume of 15 cm3 for the core permeability between 9.18 and 217 md, indicating a favorable fluid-loss-control performance. The regained-permeability recovery can reach up to 85% for different core permeabilities. Scanning-electron-microscope (SEM) pictures show that a dense structure was formed in the gel filter cake during fluid-loss experiment. The wettability results show that the core has a greater potential to increase its water-wet ability after interacting with Cr3+/KYPAM mature gel. Field test shows that a small amount of gel leakoff was observed during each reperforation process, whereas water cut decreased from 89.1 to 52.1% and oil production increased from 0.15 to 1.11 m3/d. This study suggests that the mature Cr3+/KYPAM gel can act as a fluid-loss-control pill in high-water-cut oil wells, which can provide an avenue to bridge the design philosophy of well workover and water shutoff.
The work completed was a comprehensive approach of understanding and treating formation damage to further redevelop a mature asset through successful remediation operations. The identification of skin was completed with slickline techniques and reservoir and production flow profile monitoring. Primary formation damage mechanisms were naturally occurring scales in the near wellbore, damage caused by workover fluids and water blockages. Redesigned completion fluids, acid pumping and innovative coiled tubing tools were used in the remediation works which were all first in the basin. A modified decline curve analysis technique was used to economically justify treatment of nearly all wells in the field and led to substantial production increases.
In 2003 an Association was formed to manage a mature Romanian gas field producing since 1970. Production skin was evident and in 2010 a well failed due to halite formation; consequently, liquid and solid sampling tools were deployed within suspect wellbores. In 2010 a new workover fluid formulation was introduced but despite improvements formation damage was still induced. From 2010 to 2013 there has been an increased focus on understanding and treating calcite, halite and water block damages to boost field wide productivity.
Formation damage was observed as being both naturally occurring and induced in the field. An initial assessment and pilot treatment of 10% of the wells led to a near 40% incremental gain in those wells. After which the campaigns were further expanded to over 75% of the field. Technically, the investigation into formation damage changed the development plan for the field going forward. Operationally, the intervention procedures introduced were new to the basin and have been adopted by the Association partners in other assets.
A major limit on ultimate recovery from depleted hydrocarbon reservoirs is declining well productivity. Salt formation, scale deposition, and water blockage restrict flow: reducing production rates and ultimate recovery of reserves. Therefore, economic skin management is an essential tool for extending field life, increasing profitability, and improving recovery of aging assets. Impressive results led to a strategic shift in local field production management and the techniques are useful worldwide in similar fields.
Dragomir, A. (OMV Petrom SA) | Precupanu, L. (OMV Petrom SA) | Arsenoiu, V. (OMV Petrom SA) | Tippel, P. (OMV Petrom SA) | Radulescu, G. (OMV Petrom SA) | Sava, D. (OMV Petrom SA) | Zosmer, C. (OMV Petrom SA) | Tudorin, O. C. (OMV Petrom SA)
Brine workover fluid has a confirmed damage for gas condensate wells generated by both water blockage and fines presented in it. Studied reservoir is a gas condensate field where workover operations performed for replacing downhole equipment have induced severe damage.
Formation damage for brine workover fluid was tested on core for both hydrocarbon flowing phases (condensate and gas) and revealed up to four times decreasing in permeability.
Laboratory research was then oriented to identify the best solution to remove induced damage. It was tried to identify how much of damage was induced by water blockage and how much by fines present in workover fluid.
Tests revealed a good recovery of permeability for gas by using alcohol/surfactant fluids but not close to original permeability. On the other hand correctly formulated mud acid solution have removed induced damage and increased the permeability up to three times more than original permeability.
Results have been implemented on field Burcioaia and foam acidizing was used successfully in field tests. For very long perforated intervals foam was used as diverter. In some cases only acid solution was foamed and in other cases also neutral foam was pumped in slugs in between acid stages.
Case histories for performed removing damage jobs are also presented.
The Burcioaia Field was put into development in 1985 with one appraisal well drilled to a depth of 3519 m tvdss and which encountered gas condensate accumulations in Paleozoic, Basal Sarmatian, and Middle Sarmatian formations. Generally the main reservoir, Paleozoic, can be described as a tight gas reservoir, however because of big thickness and high density of fissures in some arias wells produced at economic rates without hydraulic fracturing.
After a first period of good production reservoir managers have encountered many challenges, like depletion, condensate blockage and severe corrosion of the equipment. Workover operations performed to replace completion induced severe damage because of big workover fluid (brine) losses.
Prior to continue with recompletion program it was decided to investigate as deeply as possible the nature of formation damage induced by workover fluid and also to find the best solution to prevent or remove damage.
Nature of damage has been investigated trying to identify how much is water blocking and can how much is mechanical damage and can be removed only by acidizing.
Based on XRD investigation a mud acid recipe was formulated and tested on cores measuring retained permeability for both phases (gas and condensate).
In parallel a comprehensive reservoir study was developed together with Schlumberger having as purpose a better understanding of reservoir and also to select best well candidates for recompletion and stimulation.
Field implementation of effective acid formulation was confronting with a new challenge; diversion for very long perforated intervals (up to 200m) as most of the wells completed for Paleozoic have. For diverting acid used was foamed and foam stability in high temperature condition of the reservoir was also a challenge. To improve diversion acid stages have been alternated with neutral foam slugs based on VES.
Li, Long (Research Inst. of Petroleum Exploration and Development) | Yuan, Xubo (Research Inst. of Petroleum Exploration and Development) | Sun, Jinsheng (Research Inst. of Petroleum Exploration and Development) | Xu, Xianguang (CNPC Drilling Research Inst.) | Li, Shuang (CNPC Drilling Research Inst.) | Wang, Lihui (CNPC Drilling Research Inst.)
Nanotechnology has the potential to introduce revolutionary change in the energy industries such as exploration, development and production. Nanotechnology can revolutionalise the additive properties by tuning particle characteristics to meet certain environmental, operational and technical requirements. Nanotechnology produces nanomaterials that are ultra fines in nature, usually smaller than ordinary micro particles and thus has very high specific surface area with enormous area of interactions.
Recent research has indicated that nanomaterials have unique properties for a broad range of applications in the field of oilfield chemistry, where fluid loss control, borehole stability, cementing quality of a well, remediation of damaged reservoirs, hydrocarbon recovery efficiency, oilfield wastewater treatment are of interest.
This paper presents an extensive literature review of assessing the applications of nanotechnology and nanomaterials in the field of oilfield chemistry, investigating the existing problems in the application of nanomaterials in oilfield chemistry, and evaluating the potential technical and economic benefits that nanotechnology and nanomaterials might provide to petroleum development and production.
Recently a contaminated cement squeeze was performed in the Gulf of Mexico using coiled tubing. The work was performed at 18,600 ft, 326°F bottom hole temperature, 12,000 psi pumping pressure and 9,000 psi chokeback pressure in a H2S, CO2 environment. Operationally this squeeze was a tremendous success and set several new benchmarks with regards to high-pressure coiled tubing operations.
This paper describes the reasons for using a contaminated cement squeeze under these harsh conditions, the standard procedure for this work, and the deviations from standard procedure made specifically for this well. The paper also discusses the importance of hydraulic modeling, fluid selection, the benefits of doing yard tests, and analyzing previous jobs to verify the models.
In 2001, the operator drilled an exploration well in Louisiana State waters just south of Marsh Island and Intracostal City in 10 ft of water. The well encountered many drilling problems, primarily lost circulation and geopressures. Through the use of lost circulation treatments (12 treatments were pumped) and additional casing strings, the vertical well was total depth at 18,703 ft md. A 4 1/4-in. hole had been drilled from 14,500 ft to TD using a 19.5 lb/gal synthetic oil-based mud system. Wireline logs in Figure 1 indicated over 70 ft of gasbearing sand on bottom and with a prolific water sand 84 ft above. A 3 1/2-in. production liner with a reamer shoe was reamed to bottom in 24 hr and cemented in place using 20 lb/gal cement without any returns to surface. Subsequently, a cleanout and tieback was performed, a packer was installed at 12,602 ft (with 32 ft of 1.968-in. throughbore), and 2 7/8-in. tubing was run from packer to surface. This left the well with the internal diameters of 2.323-in. to 12,602 ft, 1.968-in. to 12,634 ft and 2.75-in. to 18,703 ft as seen in Figure 2.
The well tested with high initial rates of gas and condensate. Shortly into the test, water encroached upon the producing horizon and shut-off the hydrocarbon production. Water was produced in the test at rates higher than 10,000 bwpd. It was reasoned that the water production was coming from the zone 84 ft above the desired horizon through the primary cement job. The gas produced contained 15 ppm of H2S and 5% CO2.
Several remedial treatments were investigated for isolating the producing horizon from the encroaching water production. The different options considered were:
Water Conformance Treatments
Bullhead Cement Squeeze
Coiled Tubing Contaminated Squeeze
Water Conformance Treatments
The well has a BHT of 326°F. The temperature coupled with the necessity to isolate the water zone without shutting off production from the gas sand ruled out the majority of the water conformance treatments.
Bullhead Cement Squeeze
This method would involve pumping cement from surface down the production tubing and squeezing the zone of interest and any channels from the producing zone to the water sand. The bullhead method posed several problems including the probability of leaving cement fairly high in the production tubing due to an early squeeze. This method would require the use of coiled tubing or snubbing to subsequently drill out the remaining cement in the wellbore. Pumping cement through the completion was believed to be possible but posed a drilling risk. Passing a coiled tubing milling assembly through a 1.968-in restriction and then drilling cement in a 2.75-in liner would require a 1 11/16-in drilling motor operating at 326°F, and using an under-reamer. It was believed that low motor life and therefore time required to drill cement, would be very high. In addition, in the event that fishing was required, it was believed that fishing in the 2.75-in. below the 1.986-in. restriction would be very difficult. The inability to fish the motor assembly below the 1.968-in. restriction increased the overall risk of losing access to the producing zone. Because of the high BHT, limiting the life of the motor and the risk of loosing the motor assembly due to the well restriction, a bullhead cement squeeze was not considered the best option.
This paper presents the methodology for characterisation (sampling and analysis) of formation water and scale prediction in the waterflooding project of a deep-water field, from Campos Basin, Brazil. A subsea well A, representative from an oil-producing sandstone reservoir of this field was selected for sampling. Bottom-hole sample was taken in the open hole well at the oil-water contact using a modular formation dynamics tester - MDT. After completion operations, both wellhead and bottom-hole samples (positive displacement sampling - PDS) were collected in the aquifer zone.
The gas from the bottom-hole samples was analysed using chromatography. Bicarbonate determination was performed at offshore laboratory using a controlled microprocessing titration.
As the water sample at the oil-water contact was similar to the composition of the aquifer, it was used to predict the scaling potential in the field. Two models were considered for prediction: the thermodynamic model OKSCALE and the geochemical code GWB. These models predict the precipitated mass and calculate the saturation index (SI) of the most common scales in an oilfield during waterflood operations (BaSO4, SrSO4, CaSO4 and CaCO3). The mass and SI of the insoluble compounds were calculated for the various injection and formation water mixture ratios, occurring over the field life. Precipitation of barium sulphate and strontium sulphate was found to be likely at produced wells (downhole and flow lines) and surface facilities.
The target oilfield of this study is located in the Campos Basin, Brazil. The subsea wells are horizontal or deviated, drilled in water depths of approximately 1800 m. The principal reservoir is a cretaceous turbidite sandstone with the oil zones at 3200 to 3500 m below the sea level. The pressure maintenance by seawater injection is considered fundamental for the field development. The mixture of the formation water that has high contents of barium, strontium and calcium with the sulphate rich seawater can result in a saturated system, causing precipitation and scaling of barium and strontium sulphates. Waterflood process will generate a huge volume of these mixture as produced water and depending on the thermodynamic conditions (pressure and temperature) in the production wells the precipitation and scaling can obstruct production tubing, risers and facilities causing a production decline.
The scale potential was predicted by two models. The OKSCALE(1) that is a thermodynamic model appropriated for high temperature and pressure and the geochemical code GWB-Geochemist s Workbench(2) used for low temperature conditions. One of the main applications of these models has been in the assessment of scaling formation in produced water. So, the calculated scaling potential allows to classify the water mixture brine systems (formation water/injection water) and identify how much severe the scale formation could be and how to prevent scaling(3,4,5,6,7).
Sampling and Characterisation of Formation Water
Modelling physical chemical processes as salt precipitation in oilfield operations requires accurate and complete analysis of fluids. In order to guarantee a reliable formation water composition there are fundamental conditions that should be followed: overcome drilling and workover fluids contamination problems, immediate chemical analysis of species known to rapidly change the concentration upon exposure to the atmosphere and stabilisation and preservation of species known to vary over time.
Formation damage, although limited to the near-wellbore regions of the reservoir, plays a major role in productivity impairment simply because all the produced fluids must flow through this region. This damage could consist of permeability reduction due to deposition of particulate matter (fines, mud solids, asphaltenes etc.) as well as wettability alteration. While the permeability reduction and its possible remedies have been well-characterized in laboratory core floods, the wettability alterations induced by the interactions between the rock and the various fluids used in drilling, completion and workover operations have remained difficult to characterize. This difficulty is mainly due to the uncertainty in the techniques we have been using to characterize wettability, which has led to an aura of skepticism surrounding laboratory measurements of wettability. Some of the reasons for this state of affairs are the lack of reproducibility of contact angle measurements even after using live reservoir fluids and long aging times, and the unrepresentative (or non-reservoir) conditions under which the Amott and USBM tests are generally carried out.
This paper presents the recently developed dual-drop dual-crystal (DDDC) technique which has been used successfully in several oil-field applications to generate reproducible measurements of both the water-advancing and water-receding contact angles at reservoir conditions of temperature and pressure using live reservoir fluids. Unlike the conventional contact angle tests, which require 30-40 days to complete, the new technique enables these measurements within 2-3 days while assuring measurement accuracy within about 2-3 degrees. The paper presents the methodology and salient features of the new technique, some of the recent results to demonstrate its accuracy and short run times, and actual reservoir cases involving serious wettability shifts caused by brine incompatibility, scale deposition, temperature variation and a workover fluid invasion. Due to its accuracy, short run duration and operability at reservoir conditions, the new technique offers excellent potential for detailed understanding of the influence of the various components of drilling/completion/workover fluids on wettability alteration, screening and optimization of fluids for field applications, and evaluation of remedial measures to combat formation damage.