Estimates of worldwide oilfield water production are as high as 300 to 400 million barrels of water per day (bwpd), while oil production is only 75 million barrels per day (bopd)1. Put in different terms: for every 1 bopd produced, our industry produces approximately 4 to 6 bwpd, and for many depleted areas of the world this oil-to-water ratio can be much higher, reaching up to 1:100. Excessive water production from oil and gas wells can cause serious reductions in well productivity and significantly increases operating expenses. In an attempt to reduce the oil industry's dilemma related to water production, there has recently been an increased interest in water control treatments using relative permeability modifiers (RPM). A new and unique RPM polymer is yielding significant economic benefits by increasing hydrocarbon production from treated wells. Generally, RPMs are designed to control water production from high permeability streaks or due to coning issues. The polymer adheres to formation rock exposing its hydrophilic (water-loving) side to the pore throats. The RPM restricts water movement through the pore throat by reducing the effective size of the throat in the presence of water and by increasing drag on formation water flowing through the reservoir matrix. Because it deforms in the presence of hydrocarbons, the RPM typically does not adversely effect oil or gas flow. The newly developed RPM (along with careful selection of well candidates, correct treatment design, and proper placement) is helping increase the success of RPM treatments. This paper will discuss the application and economic benefits from using the new low-risk RPM polymer. Multi-well RPM matrix treatments were performed on offshore Gulf of Mexico (GoM) frac-packed and gravel-packed wells. One particular RPM treated gas well showed a significant decrease in water production, a five fold increase in gas production and double the amount of oil. Payout for the entire treatment was just 7 days. Introduction Oil and gas well profitability is often compromised by excessive water production. Decreased well productivity and increased operating expenses are among the inherent problems associated with excessive water production. In addition, environmental concerns and local/federal regulatory agencies are making disposal of produced water increasingly difficult. The cost of handling produced water ranges from less than $0.10 to more than $4 per barrel of water produced, costing the industry billions of dollars per year. Mature field development is driving the need for effective water management technologies in our industry, especially as marginal fields become more common and environmental regulations become more stringent. Numerous methods and attempts have been made over the years to control water production; however the difficulty begins with understanding the source of the water (i.e., channels behind casing, casing leaks, coning, encroachment, water breakthrough, natural or induced fractures, or high perm streaks). If the water source can be easily identified, then mechanical intervention (such as bridge plugs and/or various cement system solutions) can often be successfully implemented. Other options include the use of various products such as polymer blocking, silicate and phenol-formaldehyde gels but each of these methods must be applied only after the water source is identified. Then, the problem zone needs to be isolated to prevent the unintentional placement of the blocking/damaging chemicals into the hydrocarbon producing sections of the zone. Herein lies the crux of the problem, locating the water source can be costly, time-consuming and, at times can even include guesswork in diagnosing the water source and/or water-producing pathway. If the water source diagnosis is incorrect and a subsequent treatment is misapplied to the hydrocarbon interval, the effects on production can be devastating.
The Gulf of Thailand is characterized by shallow-water depth wells with bottomhole static temperature ranging from 240 to more than 420°F. These wells are drilled to an average of 12,000 ft MD and 9,000 ft TVD with a fast paced-batch drilling strategy. Most cement jobs are done offline, and on the surface section can be as frequent as 6 jobs per day. With multiple rigs, operators can require more than 100 cementing operations per month and cement volumes as high as 18,000 bbl. This efficient operations environment creates a demand for a logistically and operationally simple cement system that can be applied in all well sections and across the full range of expected temperatures. An advanced, lightweight seawater-based cementing concept was tested for this application. This new cementing system uses a single blend with only 3 to 4 primary liquid additives (including a stable, high-temperature, multifunctional polymer) to adjust all primary cement jobs for the entire wellbore. A sophisticated lab testing program was conducted for the innovative cementing concept according to the required demands on cement slurry design given the harsh wellbore conditions in the Gulf of Thailand. Tests revealed that the developed cementing systems meet all well requirements despite low densities of 13.3 to 14.0 ppg with high water content. This advanced cementing system was introduced in 2011 and has gradually been used on all wells since then -to date more than 500 wells in the Gulf of Thailand. In addition to improving logistics, use of the system has enhanced cement bond quality in production tubing cementing jobs. This improvement also reduced pay at risk due to insufficient cement isolation. This is evident in the whole range of well temperatures.
The Gulf of Thailand (GoT) is characterized by shallow-water wells that are hot and deviated; with low fracture gradients and average bottomhole static temperatures of 425°F (some wells can approach 520°F). Drilling depths average 14,000 ft measured depth (10,000 ft vertical) and fast drilling practices are used for slimhole monobore completions, resulting in daily cementing jobs from each of the offshore rigs. This paper will present an advanced lightweight seawater-based cementing concept using a single cement blend with only 3 to 4 primary liquid additives (including a multifunctional polymer system) to adjust all primary cement jobs for the entire wellbore. A sophisticated lab testing program (such as analyzing slurry gas control) was conducted for the innovative cementing concept according to the required demands on cement slurry design and the given harsh wellbore conditions in the GoT. Valuable design-effect relationship elements found in this study (such as the impact of the multi-functional polymer on cement expansion) will be discussed for applications on other upcoming and challenging drilling projects in Asia. Tests revealed that the developed cementing systems meet all operator and well requirements despite their relative low densities of 14.0 ppg with high water content. The advanced lightweight cementing design has been successfully pumped in greater than 450 GoT offshore wells starting with just a few wells in 2011 to most wells in 2013, and its performance was compared to previous cementing systems. Lab test results, pre-job planning, cement job execution and cement bond logs are evaluated and discussed. The case histories conclude that the advanced lightweight cement design significantly improved the quality of zonal isolation in wellbores.
DescriptionThe development of coiled tubing as we know it today dates back to the early 1960s. It has become an integral component of many well service, workover applications and programs. While well services and workover applications still account for approximately 75% of Coiled Tubing (CT) use, technical advancements have increased the utilization of CT in both drilling and completion applications 1 .
Coiled tubing (CT) is one of the most common and effective methods employed to mill out composite bridge plugs (CBPs) that are used to isolate zones during completion. Typically, the zones are normally pressured or over pressured, i.e., each interval approximately the same pressure. Recently, in a New Zealand field, a plan was set to mill out CBPs that had been set between zones that were tight gas and conventional with as much as 3,780 psi pressure differential between them.One major challenge relates to the CT CBP milling. While milling the plug that isolates the over-pressured zones, the differential pressure can exert significant forces on the milling assembly, raising the potential for buckling/failure of the CT. To reduce this risk it was decided that a bridge plug with an equalizing path would be used to eliminate the large pressure differential and potential upward forces. Another challenge was the issue of cross flow between the zones after milling was completed, and the potential for well control issues due to some under-pressured zones that could not support a full fluid column, causing loss of hydrostatic pressure.For the under-pressured zones, nitrogen was used to equalize the pressure across the plugs prior to milling them. To minimize the risk of getting stuck and potential CT failure, the operation was closely monitored and optimized by using a CT real-time downhole communication system. The real-time downhole pressure captured by the system during plug milling provided the firm evidence that equalization had occurred. This paper reviews the selection of plugs/mills and the milling strategy for safely milling CBPs that have been set across zones with significant differential pressures. The benefits of using a CT real-time downhole communication system is discussed by illustrating the case study of successfully removing 25 CBPs with CT in the three wells within a field.
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