Jain, Bipin (Schlumberger) | Mesa, Alvaro Martin (Schlumberger) | Kalbani, Sultan Al (Schlumberger) | Meyer, Arnoud Willem (Schlumberger) | Aghbari, Salim (Petroleum Development Oman) | Al-Salti, Anwar (Petroleum Development Oman) | Hennette, Benjamin (SHELL) | Khattak, Mohammad Arif (Schlumberger) | Khaldi, Mohammed (Petroleum Development Oman) | Al-Yaqoubi, Ali (Petroleum Development Oman) | Al-Sharji, Hamed Hamoud (Petroleum Development Oman)
Oman is a hotspot for drilling activity and wells are being drilled in different environments varying from Deep exploration and development for gas and oil and water injection/disposal. One challenge tops all other challenges: Lost Circulation. Due to the fractured/fissured nature of the formation and low existing reservoir pressures, all major operators are suffering from lost circulation challenges. Some of the challenges include: Mud losses while drilling leading to cost overruns and HSE concerns, primary cement job failure due to not getting the cement up to the desired height resulting in subsequent sustained casing pressure and corrosion, not able to perform work over activity on certain wells due to losses. Enormous quantities of water are required to maintain well control, and due to the limitation of water availability all over Oman, this becomes another critical issue. An Engineered fiber-based Loss Circulation pill has proved successful to address these challenges in multiple fields for Petroleum Development Oman.
Drilling shallow wells in Oman through the naturally fractured limestone formation of Natih, usually results in significant losses of up to 55 m3/h (346 bbl/h) even with a low density drilling fluid of 1,033 to 1,070kg/m3 (8.6 to 8.9lbm/gal). Packoffs are often observed due to the swelling shale section, which leads to several attempts with kick-off plugs and sidetracking. Engineered fibers pills enabled total returns to surface when no other loss circulation solution had worked before. This also enabled to bring cement all the way to surface using 1,410kg/m3 (11.8lbm/gal).
In another field, a work over rig was mobilized to perform a well kill operation and pullout. Due to total losses through perforations into the reservoir, the well kill could not be completed. In addition, every time the water level fell gas started to flow in the well. After 17 attempts and 8 loss circulation material pills, a total of 763m3 (4,800bbl) of well-supply water had been pumped. An engineered fiber pill at 1,474kg/m3 (12.3lbm/gal) was designed and bullheaded into the perforations. The pressures while pumping and squeezing rose to 11,031kPa (1,600psi). The well was shut and observed for 3 hours without any pressure increase indicating losses were cured and gas flow stopped.
Engineered fibers have proved their value in all sorts of lost circulation applications in North Oman. These pills have been successfully used to mitigate losses while drilling, while cementing, during mud circulation before cement job when the casing is on bottom and in work over jobs in depleted reservoirs. With the level of success achieved with such treatments, in some fields it has become a standard practice for curing losses.
Dupuis, Guillaume (Poweltec) | Al-Maamari, Rashid Salim (Sultan Qaboos University) | Al-Hashmi, Abdul Aziz (Sultan Qaboos University) | Al-Sharji, Hamed Hamoud (Petroleum Development Oman) | Zaitoun, Alain (Poweltec)
In a previous work (Zaitoun, et al., 2012), a study of the shear stability of different EOR polymers was reported. Shear stability was found to directly correlate to chain flexibility. Thus, for a flexible coil such as polyacrylamide, the presence of large monomer groups (e.g. ATBS, NVP) leads to an increase of its rigidity, hence enhancing its shear stability. However, these polymers remain highly shear sensitive in comparison to the rodlike Xanthan gum.
In this paper shear and thermal stability studies of different microgels are reported. Microgels are micrometric hydrophilic gel particles composed of partially cross-linked polyacrylamide-based chains. These microgels are already used for water shut-off treatments and conformance control. Because of their stability, they could be used in the future as sweep improvers EOR chemicals.
Comparative tests were performed with microgels and three different polyacrylamide-based EOR polymers in terms of shear and thermal stability. The impact of the internal cross-linking density, the size and the conditioning on microgels mechanical stability was investigated. For each microgel, solutions were prepared at different salinities and aged in ovens at 80, 105 and 140°C over one month in oxygen-free conditions to check their thermal stability.
Results showed that microgels maintain their integrity over a wide range of shear rate (up to 1.2x106 s-1) behaving like the rodlike Xanthan gum, whereas classical polyacrylamide-based polymers loose more than 50% of their initial viscosity at shear rate as low as 104 to 105 s-1. No difference in behavior is observed for the product prepared in powder or in emulsion form. Finally, at the highest temperature investigated (i.e. 140°C), thermal degradation is minimal for the microgels with low cross-linking densities and no thermal degradation has been observed for the microgels with the highest cross-linking densities.
The exceptional mechanical and thermal stability of the polyacrylamide-based microgels and their easiness to be tailored for the required application make these chemicals excellent candidates as future sweep improvers under harsh reservoir conditions in which other conventional polymers might fail.
Morvan, Mikel (Rhodia) | Degre, Guillaume (Rhodia) | Beaumont, Julien (Rhodia) | Colin, Annie (LOF (CNRS-Rhodia-Bx1)) | Dupuis, Guillaume (POWELTEC) | Zaitoun, Alain (POWELTEC) | Al-maamari, Rashid Salim (Sultan Qaboos University) | Al-Hashmi, Abdul-Aziz R. (Sultan Qaboos University) | Al-Sharji, Hamed Hamoud (Petroleum Development Oman)
Injections of polymer solutions have been used to improve oil recovery in heavy oil reservoirs (Zaitoun et al. 1998). Most of those polymer flood experiences refer to conditions where the polymer solution propagates through the porous media under low shear rate and exhibits mostly a Newtonian behaviour. On the other hand recent publications indicate injection of polymer solutions at concentration larger than conventional polymer flooding can result in higher recovery at field scale. Typically oil recovery of more than 20% OOIP compared to waterflooding has been reported for light oil (Wang et al; 2011). However injectivity issues have to be considered when injecting concentrated polymer solutions. This study examines whether non polymeric elastic fluids derived from surfactant solutions can represent an alternative approach to elastic polymer floods. The technology we have developed matches the rheological properties of polymer solutions in a broad range of reservoir conditions (temperature & salinity).
Bulk flow properties as well as rheology in a confined geometry have been used to compare flow properties of surfactant and high molecular weight polymer solutions. The elastic properties of both fluids have been characterized in terms of Weissenberg numbers. The data indicate the surfactant solution as opposed to the polymer one is highly elastic at low shear rates even in the presence of brine. Those results are confirmed by comparative experiments made using a Particle Image Velocimetry (PIV) technique. Injectivity of concentrated surfactant solutions has been tested in single-phase conditions and indicated a good in depth propagation of the fluid. A series of core-flood experiments has been performed using heavy oil reservoir cores. The surfactant slug has been combined with a conventional low-concentration polymer flooding to benefit from surfactant elasticity and improve oil recovery.
Degre, Guillaume (Rhodia) | Morvan, Mikel (Rhodia) | Beaumont, Julien (LOF (CNRS-Rhodia-Bx1)) | Colin, Annie (POWELTEC) | Dupuis, Guillaume (POWELTEC) | Zaitoun, Alain (Sultan Qaboos University) | Al-Maamari, Rashid (Sultan Qaboos University) | Al-Hashmi, Abdul-Aziz R. (Petroleum Development Oman) | Al-Sharji, Hamed Hamoud
Recent publications indicate that the injection of polymer solutions at concentrations larger than those conventionally used in polymer flooding can result in higher recovery at field scale. Typically, oil recovery more than 20% OOIP compared to waterflooding using these polymer solutions has been reported (Wang et al; 2011). However, injectivity issues have to be considered when injecting such concentrated polymer solutions. This study describes an alternative approach based on surfactant-based solutions. The technology has been developed to match the rheological properties of polymer solutions in a broad range of reservoir conditions (temperature & salinity) without any injectivity limitations even when considering very viscous surfactant solutions (i.e. up to 1000 cps) and low permeability cores.
Average first normal stress difference measurements have been used to compare the elastic properties of surfactant and high-molecular-weight polymer solutions. The degree of non-linearity in the mechanical properties for both solutions has been expressed by Weissenberg number. The surfactant solution has much higher Weissenberg number than the polymer solution at a shear rate corresponding to the fluid propagation in the reservoir, which indicates higher elasiticily of these surfactant solutions.
The potential of this surfactant-based technology is illustrated through a specific reservoir case involving heavy oil. A series of coreflood experiments has been performed in reservoir cores at reservoir conditions. The surfactant slug can be combined with a conventional low-concentration polymer flooding to further improve the process. Reduction in residual oil saturation in the range of 10 to 15% has been obtained. Complementary simulation study giving rise to economic analysis have been performed.
Morvan, Mikel (Rhodia) | Degre, Guillaume (Rhodia) | Beaumont, Julien (Rhodia) | Dupuis, Guillaume (POWELTEC) | Zaitoun, Alain (POWELTEC) | Al-maamari, Rashid Salim (Sultan Qaboos University) | Al-Hashmi, Abdul-Aziz R. (Sultan Qaboos University) | Al-Sharji, Hamed Hamoud (Petroleum Development Oman)
Recent publications indicate injection of polymer solutions at concentration larger than conventional polymer flooding can result in higher recovery at field scale. Typically more than 20% OOIP compare to waterflooding have been reported (Wang et al; 2011). However injectivity issues have to be considered when injecting such concentrated polymer solutions. This work describes an alternative approach based on surfactant-based fluids. The technology we have developed matches the rheological properties of polymer solutions in a broad range of reservoir conditions (temperature & salinity) without any injectivity limitation even when considering very viscous surfactant solutions (ie up to 1000 cps) and low permeability cores.
Average first normal stress difference measurements have been used to compare the elastic properties of surfactant and high molecular weight polymer solutions. The degree of non linearity in the mechanical properties for both fluids has been expressed by Weissenberg number. The surfactant solution has much larger Weissenberg number than the polymer solution at a shear rate corresponding to the fluid propagation in the reservoir.
The potential of this surfactant-based technology is illustrated through a specific reservoir case involving heavy oil. A series of core-flood experiments has been performed in reservoir cores. The surfactant slug can be combined with a conventional low-concentration polymer flooding to further improve the process. Reduction in residual oil saturation in the range of ?Sw = 10-15% has been obtained. Complementary simulation study giving rise to economic analysis have been performed.
Lakatos, Istvan Janos (U. of Miskolc) | Lakatos-Szabo, Julianna (Research Institute of Appllied Earth Sciences, UM) | Kosztin, Bela (Petroleum Development of Oman) | Al-Sharji, Hamed Hamoud (Petroleum Development of Oman) | Ali, Ehtesham (Petroleum Development of Oman) | Al-Mujaini, Rahima Abdul Rauf (Petroleum Development of Oman) | Al-Alawi, Nasser (Petroleum Development of Oman)
In frame of the project, one injector and two oil producers operating in different reservoirs having extremely high permeability were treated using the silicate/polymer method. The well selection based on analysis of production history, reservoir structure, and tracer test and production characteristics. The water cut in producers was close to or well above 90%. The chemical system was individually tailored to each well. The gel-forming solutions were sequentially injected into the wells using bullhead technique. The producers operating with sucker rod pumping were treated through the producing tubing or the annulus. In the latter case, a new "virtual" reactor concept was elaborated to mix the solution on the fly. Evaluating the results, it can be concluded that the project was successful. The cumulative daily oil production increased by 68 m3/d; meanwhile the water production decreased by 285 m3/d. Thus, on yearly basis, the incremental oil production might be as high as ~25,000 m3/y with water production less than 105,000 m3/y. The project clearly proved that the silicate/polymer technology could meet the requirements of the unique reservoir conditions (extreme permeability, faulted structure, and low formation temperature). In addition, great advantage of the composite methods is that easily available, cheap, and environmental friendly chemicals were used.
Background of arising problems in Omani hydrocarbon production can be traced back to unfavorable types of reservoirs and properties of oils. Most of the oil bearing formations are faulted, highly heterogeneous with extremely high average permeability. In addition, the formation temperature is often low and the crude oils have high viscosity. Hence, the early water breakthrough and high water cut are often characterizing the production. Under these circumstances, the recovery factor is low, and poor well performance usually jeopardizes the optimal oil rate. Recognizing and understanding the production problems and forecasting their detrimental effects on deliverability, substantial efforts had been made recently to avoid production decline and mitigate the damaging processes. Among others, IOR/EOR methods addressing the whole reservoir space and well stimulation technologies were tested and routinely applied at different fields. In the frame of these endeavors, ambitious pilot tests were carried out to restrict water production in oil wells and simultaneously, to improve sweep efficiency in injectors through flow profile control. Earlier, diverse techniques including cementing, perforation relocation, polymer, and gel treatment were tested with partial success. The basic goal of the extensive field programs was to select the most efficient methods, which are flexible enough to meet the requirements at different oil fields. That strategy made the field tests of the silicate/polymer methods possible treating two producers and one injector. The company's idea also determined the target wells operating in different oil fields, hence under different, sometimes harsh formation conditions.
Zaitoun, Alain (Poweltec) | Makakou, Patrick (U. of Pau) | Blin, Nicolas (Poweltec) | Al-Maamari, Rashid Salim (Sultan Qaboos University) | Al-Hashmi, Abdul-Aziz R. (Sultan Qaboos University) | Abdel Goad, Mahmoud (Sultan Qaboos University) | Al-Sharji, Hamed Hamoud (Petroleum Development of Oman)
An experimental study of shear stability of several high-molecular-weight polymers used as mobility control agents in EOR projects has been performed in well-controlled conditions. The shearing device was made of a capillary tube with ID of 125 µm, through which polymer solution was injected at controlled rate. The set-up enables a precise measurement of the shear rate to which the polymer macromolecule is submitted. The degradation rate was measured by the viscosity loss induced by the passage into the capillary tube. The shear rate was gradually increased up to 106 sec-1 while checking degradation rate at each stage.
Different commercial EOR polymer products were submitted to the test with polyacrylamide backbone and different substitution monomer groups. All macromolecules behave as flexible coils in solution. The parameters investigated were:
• Molecular weight (between 6 and 20x106)
• Nature of substitution group (Acrylate, ATBS/sulfonate, nVP/Vinyl-Pyrrolidone)
Polymer shear degradation increases with molecular weight and salinity, but decreases with the presence of Acrylate, ATBS and nVP. All results can be interpreted in terms of chain flexibility. The highly flexible polyacrylamide homopolymer is the most sensitive to shear degradation. Introduction of acrylate groups in the polymer chain induces some stability because of the rigidity provided by charge repulsion, which vanishes in the presence of high salinity (due to the screening of acrylate negative charges). ATBS and VP groups, which are larger in size, provide significant chain rigidity thus better shear stability. It is also shown that some very-high molecular-weight polymers, after passing the shearing device, attain a final viscosity lower than lower-molecular-weight products with the same chemical composition. This factor has to be taken into account in the final choice of a polymer for a given field application.
As a comparison, although less popular today than two decades ago, xanthan gum, which behaves like a semi-rigid rod, is shown to be much less sensitive to the shear degradation test than the coiled polyacrylamides.
Petroleum Development Oman, PDO, is planning to improve ultimate recovery of condensate from a retrograde condensate gas field by reducing the rate of reservoir pressure decline. This shall be accomplished by re-injecting into the reservoir some of the produced gas and all of the acid gas extracted from the sweetening process. The composition of the injected gas will vary over time, from 15% CO2 and 3% H2S to 56% CO2 and 10% H2S. These combinations of CO2 and H2S can cause the wells cement to deteriorate. Portland cement tends to strongly degrade once exposed to such acid gases by reacting with calcium hydroxide formed from hydrated calcium silicate phases. As carbonates are dissolved in a low pH environment, the cement-carbonation products will not act as a self-plugging agent / s in the cement sheath. The resulting decrease of compressive strength and increase of permeability could lead to loss of zonal isolation and casing corrosion. These requirements led PDO to investigate and trial CO2- resistant cement to enable zonal isolation and ensure long term containment of the reservoir fluids. The nominated new technology cement system was trailed in a deep gas well which penetrated a reservoir which has high concentrations of CO2 and H2S at a super critical condition. The CBL/VDL log which was run after well completion showed excellent results. The well-cement quality shall be re-logged prior to any zonal shutoff work-over or well decommissioning. This paper will discuss the design, execution, and evaluation of the first acid gas resistant cement in PDO in one of the high profile gas well in South of Sultanate of Oman.
This paper addresses challenges faced in Coiled Tubing (CT) intervention in slimhole horizontal wells in one of the most mature fields in Oman. An intensive production optimization program has been set by the reservoir management team. The optimization activity consisted of clean-out, saturation logging, perforation and stimulation. CT units utilization played the main role in this program. Large number of these wells were completed with 2 7/8?? cemented horizontal liner and 4 ½?? tubing equipped with gas lift system. These wells were sidetracked using CT drilling. The length of the horizontal 2 7/8?? section ranges between 1000 m and 1600 m, having the kick-off depth at about 1300 m.
CT intervention was very challenging in these well, as CT reach was limited in most of the cases. This is mainly due to the following factors:
Therefore some unsuccessful cleanouts or dummy runs were held. Hence, no logging and or optimization activities could be done.
A total of 22 wells were intervened in this project. At project midway success rate was 40% and at the end success rate was increased to 60%.This paper addresses the lesson learnt throughout this project and techniques used to enhance CT reach. The technique involved the use of CT force models and reach simulator to sensitize different factors. As more jobs were performed, models were compared with actual data and some learning could be gained. The main learning was that well flow rate was the highest contributor preventing a deep reach. Hence, the improvement techniques involved manipulating gas lifting flow rate to reduce well flow rate while CT runs in hole.
Al-Sharji, Hamed Hamoud (Petroleum Development Oman) | Ali, Ehtesham (Petroleum Development Oman) | Kosztin, Bela (Petroleum Development Oman) | Edwards, Clement (ADCO) | Neyaei, Fardin Ali (Schlumberger) | Shaheen, Tarek (Schlumberger Well Services)
This paper discusses the gas shut-off treatments carried out in a fractured carbonate field in north Oman and also describes the good practices and lessons learnt from a number of jobs. In addition to the technical analysis, the paper also addresses the economic value of the campaign.
Oil production from this field with complex geology and reservoir mechanism was negatively affected by gas breakthroughs in several wells. The constraints on gas handling capacity resulted in shutting-in a number of high GOR wells. These wells were required to be treated to shut-off source of the gas breakthrough in order to restore oil production. Challenges faced in shutting off these gas zones included: 1) Poor cement bond behind the liner shoe. 2) Massive fractures resulting in loss circulation. 3) Uncertainty with fractures volume estimation. 4) Fracture shut-off in open-hole sections. 5) Treatment execution under sub-hydrostatic conditions.
To overcome these challenges a robust chemical shut off methodology had to be innovated. This methodology consisted of the following main pillars: a) Utilize various reservoir diagnostics tools to identify fractures and sources of high GOR. b) Use of flowing cross-linked polymer gel combined with a ringing type of cross-linked polymer gel as a capping fluid. c) Utilize an on-fly mixing system that enables volume and concentration adjustment as plugging progression dictates. d) Utilize matrix diagnostics plot along with modified hall plot in real-time to continually estimate flowing gel volume. e) Deploy a fit-for-purpose gel placement assembly for treatment under Sub-hydrostatic conditions.