TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractSince Cullender and Smith (1) , surface pressures have been used to calculate bottomhole pressures on shallow, dry gas wells. If the original Cullender and Smith equations are modified to account for produced liquids, the correlation may be extended to gas/condensate wells that are single-phase in the well bore. Single-phase liquid wells (water injectors and oil wells above the bubble point) can also yield accurate well test results from the surface. Testing from the surface reduces the cost and eliminates the risk of running tools into well bores. Surface testing also allows the testing of highpressure/high-temperature wells that cannot be tested with a downhole gauge because of harsh conditions. Thus, to reduce the cost and risk (or when no other option is available), many operators have chosen to run their pressure transient tests from the surface on single-phase wells.

With the advent and common usage of high resolution tree gauges, downhole permanent pressure/temperature gauges, and continuous flow measurement, many of the common petroleum engineering calculations and analysis tools for production systems can and have been automated. These include: a) Well Test Analysis, b) Well Productivity, c) Static and Flowing Material Balances and Energy Balances. In addition, the use of rigorous wellbore thermal and phase behavior models allows the two gauges (wellhead and downhole) to be used as a giant differential pressure meter – making it possible to calculate gas rates and water cuts independently of the flow measurements, as well as mid-completion bottomhole pressure (BHP). The purpose of this paper is to present the basic physics involved in these calculations/analyses, as well as to discuss the implications that these processes will have on instrumentation selection and on engineering work flows. The crux of the argument for these types of automated systems is that it is much easier for an engineer to check the results than to spend his/her entire day just looking for useful information in the database, then analyzing it (or getting someone else to analyze it). Furthermore, being able to see the “big picture” – seeing what skin, perm, productivity and apparent hydrocarbon reservoir volumes are now and how they have changed with time, allows engineers to make quicker, more accurate decisions. The use of automated analysis also reduces bias – the computer doesn't care what the answer is. This paper will also include several case studies for both oil and gas wells.

With the widespread use of downhole pressure gauges (DHPG’s) to measure and record downhole pressures in oil and gas wells, engineers have been able to eliminate/reduce the wellbore effects that can mask true reservoir response. However, not every well is equipped with a downhole gauge; even fewer have the downhole gauge at the mid-completion depth, leaving fluids below the gauge that are subject to frictional pressure drop and changing fluid density/head due to heating/cooling. The reservoir signal (delta pressure vs time) can be slightly masked or completely overwhelmed by the change in pressure head due to changing fluid density as the well bore fluids cool or heat-up. The resultant measured rate of pressure change will therefore, not be representative of the actual reservoir response. In addition, frictional pressure loss as fluids travel up the well bore can appear as pressure loss due to completion skin. This causes wells to have an artifically high skin. Using raw pressure data that has not been accurately corrected for changing fluid head/density and frictional losses below the gauge can lead to inaccurate pressure-transient analysis (PTA) results (Hasan 1998). This paper will discuss the physics of these processes and explain the reasons for these errors in the PTA results, along with the impact of these errors. Finally, a method for properly correcting the measured pressure to mid-completion pressure will be described. To demonstrate these effects, case studies conducted on two gas wells, a gas-condensate well and an oil well will be presented.

Operators are often presented with a dilemma when installing instrumentation in a subsea well. Do they install permanent downhole gauges? If so, is there a back-up plan in the eventuality that the downhole gauge fails. In the past, when a downhole gauge on a subsea well failed, the back-up plan has either been to "fly blind" or to rely on low-accuracy measurements from subsea tree gauges or pipeline gauges (which can also fail). While tree or pipeline gauges may be adequate to determine if the well is flowing, they are rarely of sufficient accuracy and resolution to optimize production from the well. The need for high resolution, accurate pressure data is greatest in high permeability wells and in unconsolidated sandstones, where the production of sand can be catastrophic. In 2001, a solution to this problem was developed. It allows an operator to temporarily install a highly accurate pressure recording system on the well in order to perform diagnostic tests on the well bore, completion and/or reservoir. This option is available to any subsea tree equipped with an Industry Standard "Hotstab" port. Typically, subsea trees are fitted with at least one female hotstab port conforming to ISO/CD 13628–8 enabling a remotely operated vehicle (ROV) to connect instrumentation specifically designed for this application. The ROV is then used to operate the isolation valves to allow well bore communication via the hotstab port. Once pressure communication with the well bore is established, diagnostic tests may begin. The purpose of this paper is to introduce a mobile high-precision, high-accuracy pressure recorder for pressure transient testing at subsea well heads. First, the instrument and subsea tree specifications will be discussed. Then, a detailed procedure for installing this instrument on the subsea tree will be presented. Next, the issue of wellhead to bottomhole pressure conversion will be addressed. Results from field tests with the system will be presented. This new tool makes it possible to test subsea wells in which downhole gauges were not installed or where they have ceased to operate. The tool has also proven useful for pressure integrity tests when commissioning sub sea pipelines. Introduction Accurate pressure versus flow rate data is as important to an engineer concerned with optimizing well production as an altimeter is to a pilot concerned with safety.Producing a reservoir at excessive rates risks collapse of the completion due to pressure drop exceeding the strength of the formation. Producing at reduced rates results in reduced cash flow. The industry has recognized the importance of this trade-off by investing in frequent well testing. In the case of subsea wells, it is much more difficult and expensive to conduct pressure transient tests than it is from dry trees. Therefore downhole gauges are permanently installed at a cost that can exceed a million dollars per installation. However, experience has shown that the majority of these downhole gauges installations will fail, many in less than a year. When that happens, the operator has no way of knowing if he is in danger of collapsing his completion or is producing at an unnecessarily reduced rate. The high-precision subsea pressure recorder (SSPR) allows an engineer to acquire the data necessary to safely optimize well production. Subsea Pressure Recorder The subsea pressure recorder (SSPR) is a self-powered device specifically designed for the acquisition of pressure transient data in the subsea environment. The device is housed in a subsea pressure vessel approx. 6 inches in diameter and 14 inches long. The system weighs approx. 40 pounds in air, 20 pounds in water, and is designed to operate in water depths up to 10,000 ft. Integral to the pressure vessel is the ISO/CD 13628–8 male Hotstab which is internally ported to the pressure transducer. The maximum allowable working pressure of the system is limited by the Industry Standard Hotstab to 10,000 psi.

The purpose of this paper is to provide a more relevant solution to the diffusivity equation than the conductive disc/zero potential flow (Exponential Integral) solution, especially for use in predictions of the time that is required for an interference effect to reach an observation well. After explaining the assumptions and theory behind the method, a direct integration of the radius of investigation will be presented, along with a physical explanation of what it is. While presenting multiple examples to support the theory, the results from Exponential Integral method for predicting interference arrival at an observation well will be compared. Finally, it will be demonstrated that the classic radius of investigation equation is more appropriate in interference/communication testing, and that rate, gauge resolution, and the total system pressure drop do not affect the arrival of the interference effect.