Managed pressure operations enable keeping the equivalent circulation density (ECD) within a narrow pore-frac pressure window during drilling and cementing while maintaining the wellbore stability and controlling formation pressures. The operation becomes more complex during a cementing job, where fluids with different density and rheology parameters are pumped downhole at varying rates, resulting in different friction pressure profiles. Proper numerical simulators must be used to model such variations and keep the downhole pressure between the pore and fracture pressures during the operation. Managed pressure techniques and technology were critical to the successful cementation of the 7-in. liner at 12,000 ft. in a gas field in Saudi Arabia, across formations ranging from a high-pressure zone with 2.36 SG (19.65 ppg) formation pore pressure to a depleted low-pressure formation with 2.44 SG (20.32 ppg) fracture pressure. The challenge in this job was to maintain the ECD at 2.40 SG (20 ppg) throughout the cement job to avoid any losses or flow from the formations. An automatic choke setup on the return flow line with a dynamic control system was used to drill the 8.375-in. open hole with KCl polymer mud. Precise cementing simulation was used to determine the ECD during cement placement. Numerous pre-calculations and simulations were run to evaluate various scenarios prior to the cement job to ensure effective manipulation of back pressure through managed pressure drilling (MPD) equipment to maintain ECD at the desired value throughout the cementation process. The detailed simulations run by cementing and MPD engineers prior to the job and a collaborative approach were instrumental in defining a final cementing plan, completing the layout of equipment used for the cementing job, and executing the job with real-time monitoring of all critical parameters affecting ECD and evaluation of the cement job.
Cement is extensively used for zonal isolation. This cement comes in contact with corrosive fluids during matrix treatments to the formation. Acids can react with various components present in cement and cause severe damage to cement. The damage depends on cement type, acid type and concentration, temperature, pressure, surface area, and exposure time. Previous studies on cement acid reaction are sparse and typically use a 2"×2"×2" cubes soaked in acid under static conditions. The objective of the present work is to examine the acid cement reactions under dynamic conditions. The reaction between regular cement (118 pcf) and HCl was examined using the rotating disk apparatus. Cement disk 1.5 inches in diameter and 0.6 inch in thickness were used. The effect of disk rotational speed (0 to 1,000 rpm), on the dissolution rate of regular cement was determined. The system pressure was maintained at 1,000 psi and the reaction was allowed to proceed for 120 minutes. Samples from the reaction vessel were collected at various times and were analyzed for various key cations using inductively coupled plasma emission spectroscopy (ICP). The results obtained indicated that HCl acid leached calcium, iron and aluminum from the cement disks. The concentrations of these ions increased with time. Calcium concentration was significantly higher than other cations. The reaction rate was controlled by diffusion of H+ to the surface of cement. This paper will discuss the results obtained and address their implication on field applications. Introduction Matrix stimulation of oil and gas producers includes injection of an acid below the fracture pressure of the formation. These acids can stimulate water-producing zones, which may lead to higher water production. There is a need to control water production. One of the techniques used to control water production includes placing a cement plug across the water producing zones. This technique will reduce water production in some cases only. Other mechanical and chemical techniques are also available. Selection of the treatment type depends on well characteristics and cost. Class-G cement is used to prepare cement plugs. Stimulation of the oil producing zones follows in some cases the placement of the cement plug. There is a large probability that the stimulating acid will contact the freshly set cement. Acids that are commonly used to stimulate carbonate reservoirs include HCI (15 or 28 wt%), acetic acid (13 wt%), formic acid (9 wt%) or combinations of these acids. Hydrofluoric-based acids are used to stimulate sandstone reservoirs. A literature survey indicated that significant numbers of cement squeeze jobs were found to break down or develop zonal isolation problems after HF-HCI acidizing. Field results showed that 75% of the squeezed wells broke down following acid treatments. A failure rate of only 30% was reported for cement squeezed wells that have not been acidized. Also, 17% of the 70 wells that have been stimulated with HCI/HF acid in the Eastern Operation Area of Prudhoe Bay Field, Alaska, showed zonal isolation problems after primary squeeze cement jobs.1 Similar zonal isolation problems were noted by Silva et al. 2 in certain fields in Brazil. Acids that contain HF react with regular cement resulting in a significant weight loss. Lab results simulating field conditions (high temperature/pressure) showed that regular cement was soluble up to 96% in full strength mud acid at high temperatures.3 Also; strong acids leach iron, which represents nearly 3.3 wt% of cement. The released iron (Fe(III)) may induce asphaltene precipitation which stabilizes acid/oil emulsions. These emulsions/sludges can adversely affect the productivity of the oil producing zones.4 Also, the reaction of HCI-HF acid with cement results in the formation of fluorite (CaF2), which precipitates, and may damage the formation.5 Brady et al.1 investigated the effect of pressure on solubility of cement in acids. The study showed that increasing pressure from atmospheric to 1,000 psi resulted in increasing the solubility of cement in mud acid by 25 wt%. According to their analysis, the high pressure would result in higher shear rates, which enhanced solubility of cement in acids. The objectives of this study are to:understand the nature of HCl acid/Class-G cement reactions, andexamine the effect of the disk rotational speed on these reactions.
There are many factors to consider in the design and execution of a cement job for deepwater operations in the South China Sea. These factors include the abnormally pressured sands with high probability of shallow flows, presence of gas hydrates, low-fracture pressure formation, low bottomhole circulating temperature, and low seabed temperatures. There have been 14 deepwater wells, offshore Sabah, Malaysia, that were successfully drilled to objective under these challenging conditions. This paper presents a few selected case histories from the project, describing the solutions-oriented approach to these problems. Also included is a discussion of the extensive laboratory tests performed to formulate the lightweight, gas-tight cement slurry at low bottomhole and seabed temperatures, and recommended practices for drilling and cementing. Due to low-fracture-gradients associated with the deepwater environment, lightweight slurries were required to complete the cementing operation without losses. To reduce the risk of destabilizing gas hydrates, the slurries were designed to generate low heat of during their hydration and setting. Slurries were also designed with low porosity, using special additives to prevent gas migration through them during the setting process. Because of the low temperature at the seabed 1.7°C (35°F), special additives were required to obtain a short critical hydration period (CHP), early compressive strength development, low set -cement permeability, low fluid loss, and zero free water and sedimentation. An engineered solution was used to predict and simulate the temperatures during the cementing operation, and the simulated results were applied to improve the design. Introduction In 1999, Murphy Oil Corporation became the third largest acreage holder in Malaysia by acquiring three offshore blocks, one of which is Block K in South China Sea (Fig. 1). Block K is about 120 km to the north of the offshore base in Labuan. It covers 1.6 million hectares (4.1 million acres) in offshore Sabah deep waters and represents the largest block ever awarded in Malaysia to date. Since then, Murphy has added five more blocks. Out of the eight blocks, four lie in deepwater East Malaysia. Murphy achieved tremendous success at the Kikeh prospect. Kikeh is the first deepwater oil discovery made in Malaysia, in a water depth of about 1,340 m (4,400 ft). Murphy quickly moved to drill two more wells to appraise the size of the structure. The average net pay of the three Kikeh wells and associated sidetracks was 122 to 183 m (400 to 600 ft). In 2003, Murphy has also announced discoveries at Kikeh Kecil and Kikeh #5, which are add-on discoveries to the Kikeh field. Background Early deepwater cementing practices involved nitirifed slurries. In order to achieve low densities, cements may be foamed, allowing adjustment of the slurry density at the wellsite, good fluid-loss control, and satisfactory compressive-strength development at low temperatures, although foaming operations require additional equipment plus liquid nitrogen. Despite successful foam-cement operations in deepwater wells, Operators began to seek simpler, safer, and less expensive alternatives to energized fluids and their ancillary safety and risk-management issues. Today, more and more Operators in the Gulf of Mexico are using non-foamed, engineered particle-size-distribution (PSD) slurries for cementing the surface casing strings in deepwater exploratory wells. In 2002, Murphy followed suit and became the first operator in Asia to apply the same optimized engineered lightweight slurry system in Malaysia. Challenges To successfully implement a deepwater exploration program offshore Sabah from the cementing point of view, a number of challenges linked to this hostile environment must be overcome. These challenges will be addressed in greater details in this paper.
Shallow gas-bearing formations in the Gulf of Thailand present numerous drilling and cementing challenges. In the first three wells drilled on platform WP11 in Bongkot field, initial cementing of surface casing did not achieve effective zonal isolation of the shallow-gas zone. Several techniques were unsuccessful, including the use of conventional lightweight gas-tight cement slurries, two-stage cementing operations with conventional gas migration control slurries, and injection of sodium silicate to damage the shallow gas sand. All methods failed to control the gas migration through permeable upper sand layers. This paper presents case histories describing the solutions-oriented approach to this problem, which resulted in changes to both the drilling program and the cementing operations. There is discussion of the extensive laboratory testing performed to formulate the lightweight gas-tight cement slurry at low bottomhole temperature, the best drilling practices learned, and changes to selection of drilling fluid. Results of post-job cement logs are also included. The new approach involved consolidating and damaging the formation with drilling fluid and using low-temperature, lightweight, gas-tight cement slurry. This water-reduced formulation required optimization of the particle size distribution, gas migration control, and short transition time. Modifications were made to drilling techniques and cementing practices, and an openhole external casing packer (ECP) was employed as an additional barrier. Successful zonal isolation was achieved in seven wells drilled from WP-11 Platform in the Gulf of Thailand with excellent cement coverage above and below the gas sands and no increase in wellhead pressure. Introduction Bongkot field is in the Gulf of Thailand approximately 600 km south of Bangkok and 180 km off the coast of Songkhla province (Fig. 1). Following discovery of the field in 1973, it was delineated by drilling 23 wells. In 1990 the concession development rights were transferred to a Joint Venture Group comprised of PTT Exploration and Production Plc (PTTEP), 40%; Total Exploration and Production Thailand (TEPT), 30%; British Gas Thailand Ltd., 20%; and Statoil Thailand Ltd., 10%. The field was operated by TEPT from the beginning until mid-1998, when the operatorship was transferred to PTTEP. Since 1998, Statoil Thailand Ltd. has farmed out its interest to the rest of joint venture partners. In 1995, the shallow gas anomaly was discovered in the Tonsak south area of Bongkot field. (Fig. 2) Drilling through the shallow gas was proven technically feasible and safe after a pilot hole, Tonsak SG, was drilled in 1996. The shallow gas anomaly characteristics were verified with logging while drilling (LWD) information. This well was abandoned safely. In 1998, a decision was made to set a platform over shallow gas anomaly. The motivation was a projected cost saving of approximately U.S. $20 million, in part because draining of the gas could then be accomplished with a single wellhead platform instead of three small wellhead platforms outside the shallow gas anomaly. (Fig. 3) Background The detailed work started in early 2001. The preparation included risk analysis, mitigating measures, personnel training, exercises, procurement of special equipment, and additional safety equipment. In early 2002, cement jobs performed across the shallow gas sand in three wells with various drilling and cementing techniques failed to isolate the gas-bearing sand. Because of the concern of gas breakout to surface, which would jeopardize the platform stability, one pilot hole was drilled to the upper layer sands and a pressure monitoring system was installed to monitor the pressure development of these sands. Then, two wells were drilled and completed to final depth. These two wells were subsequently perforated and produced. Sustained annulus casing pressures from the shallow gas zone were monitored and controlled.
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