Wellbore clean up has become an integral part of well completion operation aiming to maximize well productivity from a near skinless wellbore. The awareness has become more widespread with more and more horizontal and sand packed openhole wells being completed with so-called non damaging Drill-In-Fluids (DIF). Although drill-in-fluids control fluid loss and saturation related damage to a great extent, they tend to leave a sticky filter cake containing polymers and Calcium Carbonate particulates which can severely restrict well flow. Acids, oxidizers, chelating agents and enzymes have been often used as wellbore clean up fluids with mixed success. This article demonstrates laboratory and field evidences on superior efficiency of some recently developed bio-enzymes and explains the reason of their not so satisfactory treatment result in some wells.Simulated Reservoir Condition Core Flow (RCCF) and return permeability measurement was the basis of laboratory evaluation and comparison of various clean up formulations, including inorganic/organic acids, oxidizing agents, various enzymes and combination treatments. Mud filter cake was developed by simulating drilling and reservoir parameters. Cleaning treatments were mimicked as per realistic field operation. Photographic evidences were produced on clean up efficiency and final conclusion was drawn based on return permeability.Well treatment methodologies are discussed and production data from over twenty wells/legs were produced, analyzed and compared. An effort is made to analyze unsatisfactory treatment outcome in some of the enzyme treated wells and to establish the best practice approach for wellbore clean up operations.
In a well integrity, repair for well AB, 9 5/8″ casing perforated to fix gas breakthrough problem behind 13 3/8″ casing, right after the casings perforation, contaminated cement circulated to surface from the annulus between 9 5/8″ and 13 3/8″ casing. Oil extracted from contaminated cement sample using two solvents, hexane and dichloromethane. The extracts analyzed using gas chromatography. Hexane and dichloromethane extracts, showed that the cement has hydrocarbons in the carbon number region from C8 to C30. Hard cementitious material milled and circulated out of hole from 900 meter downward to S formation at 1440 meter. Having contaminated cement in the top part of the cement column and hard cementitious material downward to the oil reservoir at 1440 meter, then outstanding cement downward to the section TD at 2530 meter, indicates that cement above this reservoir did not hydrate at all. Cement contaminated as a result of the losses encountered right after displacing the cement, the entire cement column form S formation upward to the top of cement contaminated with S formation oil, contaminated cement settled and compacted because of the hydrostatic head above it. Compacted solids prevent further influx to take place. This case history along with the detailed demonstration including the novel lab work will present in this paper.
Hematite and hausmannite Ore ground are the most common material for weighting cement, it most adequately fulfills all the requirements and achieves the highest effective specific gravity, they usually dry blend with oil well cement to prepare high-density cement slurries. Cement sheath made of Portland cement and high-density additive of metal oxide such as Hematite and or hausmannite Ore ground decomposes much faster than cement sheath made of net or low Portland cement when it exposes to hydrogen sulfide (H2S) and or wet carbon dioxide (CO2) during the Well-Life. Hematite and hausmannite Ore ground's pre-densified cement sheath breaks down into many compounds through series of chemical reactions often involve an energy source that breaks apart the bonds of compounds. It decomposes into metal sulfide and or carbonate and calcium carbonate with a small concentration of iron sulfide as a result of the metal oxide and or Portland cement content sulfidation and carbonation reactions. Cement sheaths made of net, high, or low-Portland cement without high-density additive of metal oxide decomposition rate is less than cement sheath made of Portland cement with a high-density additive of metal oxide when it exposes to H2S and or CO2. H2S alone does not drastically decompose cement sheaths made of net, high, or low-Portland cement without high-density additive of metal oxide. H2S has limited impact on these cement sheath type as it reacts with iron(III) hydroxide [Fe(OH)3] in which is a part of 10% of the cement hydration products. Carbonic acid reacts with 90 % of the cement hydration products (calcium silicate hydrate and lime) and degrades cement sheath thoroughly. Despite that net cement-sheath does not drastically decompose when it exposed to H2S alone, it does when expose to CO2 alone and the decomposition rate increase in the as H2S concentration increase; unfortunately, it is not a case of if, it is a case of when cement sheaths with or without a high-density additive of metal oxide decompose due to the Carbonation and or Sulfidation reaction under wet CO2 and or sour environments. The cement sheath deterioration not only prevents well production or injection rate by reducing the inner diameter of the tubing and restrict access to the well with surveillance equipment for data acquisition but also damage the well-integrity and allow hydrocarbons along with H2S and CO2 to break through to the surface eventually. Immiscible gas injection is the worst case scenario ever, Portland cement sheath whether it contain a heavyweight additive of metal oxide or not, low-Portland or high Portland cannot sustain the acid gas, and it will lose its integrity. These wells have to fail in a short period due to the cement sheath deterioration. This paper discusses the durability of different oil well cement formulations under H2S / wet CO2 environments and demonstrates why some metal oxide containing cement more stable than others under sour CO2 reservoir downhole conditions.
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.
Petroleum Development Oman (PDO) is drilling sour reservoir wells in the south of Oman. The challenge for these wells is that the completions are suffering from an iron sulfide scale formation during the production stage. Iron sulfide scale precipitation occurs from the reaction of hydrogen sulfide (H 2 S) and iron oxide (hematite or other metals oxides). The latter is usually used in the high density conventional cement slurries to cement the liner across the reservoir intervals. The iron sulfide scaling on these wells reduces the internal diameter of the liner and the tubing. The consequence of this is the restriction of access to the wells with surveillance equipment for data acquisition (for example production logging) and other tools. A new solution was found to eliminate the formation of the iron sulfide scaling in future wells. This solution is the implementation of an innovative optimized particle size distribution cement system, with low water content and high mechanical performance, that meets the well design requirement. The cement slurry formulation contains no iron and hence meets the cement system specifications. Extensive laboratory work was undertaken to engineer the slurry to the required specifications and yard trials were also performed. PDO and Schlumberger have worked very closely and have been able to execute the first ever metal-free cement system for such environments. This paper will cover the long term zonal isolation challenges that wells, with the risks of iron sulfide scaling, are facing. New technologies and techniques used to seal and cement these wells will be presented with case studies from well operations. BackgroundThe field N is a high profile field was discovered by exploration well A-1 in 1989. It is situated 40 km west of the NM field and 60 km north of the MM field in the South Sultanate of Oman salt basin in an area where no infrastructure was present at the time of discovery. To date thirty vertical wells, including one 4 hole multi-lateral, have been drilled in field N. The field contains the unique Athel silicilyte formation, some 4.5 km below the surface. The Athel reservoir has a gross thickness of up to 400 m and is fully encased in sealing salt as a result of which the reservoir is geo pressured to 80 MPa. Whilst porosity (23 Pu), net-to-gross (> 90%) and oil saturation (80 su) are favorable in field N, the permeability is extremely low. This is due to the fact that the rock consists mainly of micro-crystalline silica with a uniform size of around 2-3 m, which leads to extremely small pores and pore throats. The oil in field N is very light and volatile. It has a density of 0.622 g/cm3 at reservoir conditions, with a solution GOR of 410 sm 3 /m 3 and a bubble point pressure of 11600 psi, resulting in an API gravity of 48 at stock tank conditions. The oil is also sour, containing 1.5 mol% H 2 S and 3 mol% CO 2 , no formation water and under 1 %, by volume, water of condensation. Through special PVT experiments the oil has been shown to be miscible with hydrocarbon...
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