As exploration has moved into deeper, more hostile environments, drill-stem testing (DST) has had to address new challenges related to testing in these ever-changing, more demanding environments. These new scenarios have required continuous technology innovations to enable DSTs to meet the additional needs inherent to the deeper offshore environments. Testing technology has had to find solutions for these conditions, while maintaining cost optimization and operational safety, both of which present continuous concerns. One strategy has been to reduce the use of electrical cables in the well and minimize the application of pressure to the annulus. This paper presents the industry's first fully acoustic telemetry controlled and monitored real-time drill-stem testing (DST) operation performed in a deepwater environment. The fully acoustic controlled operations included:• Opening tester valve for flow • Closing tester valve for build up • Opening circulation ports • Actuating downhole samplers • Acquiring real-time pressure and temperature data.This job was performed in the pre-salt region of southeast Brazil from a semi-submersible rig at 7,053-ft water depth in a well that was17,600 feet deep. In this DST, a completely wireless acoustic system was used to control the downhole tools, and as such, had to actuate the tester valve, the circulation valve, and the bottomhole fluid sampler, while acquiring real-time bottomhole pressure and temperature data. This was the first time that this type of operation had been attempted in deep-water conditions. Acoustic telemetry systems usually can help optimize operational cost because of their capability to access quickly real-time data pertinent to the reservoir evaluation; because of this capability, immediate well-timed decisions or changes to operations can be made. The fully wireless system (acoustic wireless transmission across the subsea safety tree and its components) provided the operator with acoustic feed-through response, which enabled troubleshooting from the surface and capability to change the "next steps" for the DST quickly.This paper also discusses how the use of these tools elevated testing operations to a higher performance level and improved quality standards.

Deep-water exploration in Brazil has continued to increase in complexity, requiring new technology to not only meet the ever increasing demands of the challenging environments but also the increase in costs. These have been incurred from the continuous increase and upgrades in safety regulations and the costs associated with exploration into new environments. In this scenario, operators are welcoming any cost-effective methods to evaluate well profitability without sacrificing safety. In a newly discovered potential oil block, it is necessary to obtain downhole data such as pressure, temperature under specific conditions (flow and build-up periods) as well as obtain pressure-compensated fluid samples and produced volume across time. To obtain these data, it is necessary to perform Drill-Stem Tests (DSTs). Using the type of data that can be derived from DSTs, it is possible to estimate the volume of the reservoir, its layers inside the tested field, and other characteristics that are necessary for planning completion. If performed offshore, testing requires safety equipment placed inside the blowout preventer (BOP) stack to keep the well under control, prevent undesired flow, and protect the environment and personnel. Recent discoveries in Brazil indicate that there is a large hydrocarbon potential in the pre-salt area. That area extends in a track that includes 800 kilometers from the northeast to the southern regions, is 200 kilometers wide away from the coast, and has reservoirs that are 3,000 meters deep. The initial estimation of hydrocarbon production for the Brazilian pre-salt area was approximately 60 billion barrels, but other research has shown different results that are estimated to be from 120 to 200 billion barrels. The importance of this information has more than justified the need to perform DST operations to obtain reliable data. According to Petrobras, Brazilian production has increased steadily, and production has been 300 thousand barrels/day since 2008, when pre-salt production in Brazil commenced; the company wants to reach 1 million barrels/day by 2017. To achieve those numbers, it will be necessary to guarantee that the reservoir will respond as originally predicted. This will require acquisition of reliable data to estimate the current resources, which the DST provides. After the DST, if the operator determines that the production from the formation has not performed according to their expectation or their desired production rate, then the operator may choose to fracture the well. This process is performed by injecting large amounts of a specific, proppant-laden fluid into the reservoir at a high pressures and high pump rates, in order to attempt to increase the reservoir's expected production. With the traditionally used equipment, after completing the fracturing process, the equipment must be pulled out of the hole (POOH) and tripped in again to perform the actual drill-stem testing operation. Several trips were required, because the safety equipment available for the oil industry was not certified to work in extreme environments with solids being pumped at high rates and pressures. If the trips were to be consolidated, a specially-designed downhole equipment package would have to be developed. A major engineering/service company has now developed new subsea safety-tree equipment to be placed inside the BOP stack; with this new equipment, the fracturing operation and the drill-stem testing can be performed in the same trip, since the safety valve system has the capability to maintain integrity when functioning in heavy proppant, high pressure, and high pump-rate conditions.

Historically, a fracture treatment with proppant is performed with a dedicated workstring connected to downhole completion equipment (such as a permanent packer, a tubing seal receptacle (TSR), or a locator assembly). This paper discusses offshore field operations in Brazil to illustrate how surface and downhole equipment, including a temporary completion string, were capable of meeting these challenges for hydraulic fracturing using ceramic proppants, followed by an acid job before a drillstem test (DST), which saved at least 6 days of rig time.When performing a DST with a temporary completion string, there are risks associated with using this type of fracturing treatment these mechanical tools can lock up if they are operated with proppant still packed in the operating sections (such as the tester valve and circulation valve). It is recommended that during the job the tool operation should be minimized to the absolute minimum because proppant can be packed in other areas of the tools. Halliburton performed extensive testing before the operation to determine the erosional limits of the DST tools; as a result of this testing, the maximum flow rate of the fracturing process was limited to 23 bbl/min. In this treatment, debris-tolerant valves, rather than standard valves were used. The debris-tolerant valves were specifically designed and tested to manage more debris.The well-test surface equipment was made of a solid-tolerant design, including a choke manifold (high abrasion tolerance), a four-phase separator, which was used to separate the solids, and surge tanks that are suitable for managing well flow that contains solids. Additional atmospheric tanks were provided in the test plant as part of a contingency plan to store fluids in the event of a high concentration of solids or/and untreatable fluid, which cannot be discarded or burned; sensors for solids were installed downstream from the choke manifold.During the hydraulic fracturing operation, 2,760 bbl of fracturing fluid containing the 20/40 mesh size proppant was pumped at a rate of 23 bbl/min with a maximum concentration of 6 lbm/gal. During the fracturing job, a screenout occurred, and the contingency plan was followed, removing most of the proppant inside the string. The well-testing plant received 130 bbl of the fracturing fluid at the surface during the cleanup of the well. The DST tools were fully functionable after the fracture treatment, and the test was successfully performed.The main objectives of well testing included the characterization of the reservoir (primarily, all variables to calculate the productivity index and the reservoir fluid (specific gravity (SG) of oil and gas/oil ratio (GOR). A stimulation technique is commonly used to increase the PI, and in some cases, with exploratory wells, the stimulation and well testing are combined to gather information to determine the effectiveness of the technique and whether or not this method is sufficient to make the block lucrative. One of these stimulation techniques is hydraulic fracturing, whi...

Exercising environmental responsibility during decommissioning of old assets has become increasingly important during recent years. In addition to increasing awareness in the industry, regulators consistently update and review the regulatory requirements for well abandonment and asset decommissioning. Operators document liability costs related to decommissioning in their balance sheets. Advancements in project execution and technology adaptation have resulted in regularly scheduled reviews of these liabilities. However, an industry-wide initiative to improve decommissioning execution and efficiency has provided operators direct incentive to review these liabilities more consistently and thoroughly. This paper presents an integrated project methodology to help reduce liability costs by improving efficiency during the decommissioning phase. This integrated project approach typically begins with a detailed preparation/study phase to predict possible challenges, followed by a design phase for each stage of the project to identify potential costs savings. Well data and regulations are obtained and analyzed according to the specific geographical location and then categorized by the technologies and resources necessary for abandonment. During the technologies and resources phase, potential costs savings are included as part of the plug and abandonment (P&A) service solution. Wells identified as potential candidates for new technology applications are ranked and grouped according to the execution sequence. After this thorough categorization, time and costs estimates are produced for the candidate wells. This paper presents details of this integrated project methodology combined with recent key technologies to help improve efficiency during well abandonment operations in challenging scenarios. Case histories of the methodology application are also discussed.

Hazardous gases, such as H 2 S and CO 2 , present high risks for health, safety, and environment on and near offshore facilities. In recent years, it has become more important to evaluate the pollution and process safety for dispersion of the leaked and relieved hazardous gases during an offshore operation. The primary focus of this work is to estimate the dispersed gas concentration levels around the potential release sources on offshore facilities. Computational fluid-dynamics (CFD) simulations were performed to study H 2 S/ CO 2 dispersion behavior. In the simulations, the Realizable k-model for turbulence was used for the multicomponent gas flow, and the species-diffusion equation was solved for the gas-dispersion calculation. Parallel simulations were used to accelerate the computing time because system meshing generally has 1 to 2 million nodes. A series of scenarios was designed for the potential leak and relief locations, such as surface well testing (SWT) areas, relief lines (overboard), and flare boom, and with different wind directions, speeds, and gas-leak rates. The worst case scenarios were further studied. The results yielded 3D gas concentration distributions, including critical safety-concentration level profiles, pollution coverage area, and height.