Both the Rawlins and Schellhardt and Houpeurt analysis techniques are presented in terms of pseudopressures. Flow-after-flow tests, sometimes called gas backpressure or four-point tests, are conducted by producing the well at a series of different stabilized flow rates and measuring the stabilized BHFP at the sandface. Each different flow rate is established in succession either with or without a very short intermediate shut-in period. Conventional flow-after-flow tests often are conducted with a sequence of increasing flow rates; however, if stabilized flow rates are attained, the rate sequence does not affect the test. Fig 1 illustrates a flow-after-flow test.

The isochronal test[1] is a series of single-point tests developed to estimate stabilized deliverability characteristics without actually flowing the well for the time required to achieve stabilized conditions at each different rate. Both the Rawlins and Schellhardt and Houpeurt analysis techniques are presented in terms of pseudopressures. The isochronal test is conducted by alternately producing the well then shutting it in and allowing it to build to the average reservoir pressure before the beginning of the next production period. Pressures are measured at several time increments during each flow period. The times at which the pressures are measured should be the same relative to the beginning of each flow period.

A single-point test for gas well deliverability is an attempt to overcome the limitation of long test times required for flow-after-flow tests. Both the Rawlins and Schellhardt and Houpeurt analysis techniques are presented in terms of pseudopressures. A single-point test is conducted by flowing the well at a single rate until the sandface pressure is stabilized. One limitation of this test is that it requires prior knowledge of the well's deliverability behavior, either from previous well tests or possibly from correlations with other wells producing in the same field under similar conditions. Ensure that the well has flowed long enough to be out of wellbore storage and in the boundary-dominated or stabilized flow regime.

Most of sour gas reservoirs in China are HPHT tight gas reservoirs which require long testing duration to reach steady state when conducting deliverability test while long testing time leads to huge operation risk because testing tools are used close to critical temperature and pressure condition. In order to resolve the contradiction among testing duration, operation risk and interpretation results' accuracy, a new deliverability test method is proposed by using pressure buildup transient data. The deliverability calculation model is built by integrating wellbore fluid flow and formation seepage considering fluid flow from formation to wellbore after well shut-in. The formation parameters are interpreted by one pressure buildup transient data, based on which, four daily production rates are designed to simulate the wellbore flow pressure until the well reaches steady state flow, and then the deliverability equation can be derived from the pressure & daily rate points under steady state flow. Filed case comparison is made between interpretation of actual test data and data from the new method. Results show that the new deliverability test method can get more accurate deliverability equation and AOF by only 1 time pressure buildup and greatly reduces the duration for testing, so it is very practicable because it can greatly decrease the operation risk and increase interpretation accuracy for HPHT sour gas reserviors. This new deliverability test method has wide application prospect in HPHT sour gas reservoirs and can be extended to other oil/gas reservoirs' application for quick AOF determination, rate allocation, and economic evaluation.

Abstract This study presents an inception-to-maturity data acquisition philosophy and deriving value from such surveillance. We show that wellhead pressures can be translated to bottomhole condition for many reservoir-engineering calculations during the flow period. While conversion of WHP to BHP is feasible during a flow test, measurements showed that shut-in tests do not lend themselves for such treatment because of rapid heat dissipation of a low-heat-capacity fluid, such as gas. Therefore, we relied upon flow-after-flow tests that were embedded in monthly variable-rate production measurements to obtain average-reservoir pressure and absolute open-flow potential. These average pressures enriched those that were obtained with downhole gauges from shut-in tests for the material-balance analysis. The resultant time-dependent inflow-performance relationship (IPR) and absolute-open-flow potential helped understand well performance. Indeed, evolution of declining IPR slope led to the identification of gradual wellbore blockage in one of the wells completed openhole. Downhole video recording confirmed mechanical issues in two openhole completions. Production logging showed preferential flow from the upper section of the thick carbonate interval in two wells. However, residual doubts remained about possible flow up the annulus in the openhole/slotted-liner completions. Analytic modeling confirmed that the notion of preferential flow up the annulus is untenable.

Abstract At first, this paper presents the bases for a new approach of well testing focused on to determine well-reservoir properties from Flow-After-Flow tests. This approach opens the unprecedented real opportunity to use tubinghead pressure data as a powerful tool of analysis. After that, the paper presents the evaluation of a field test to show the operational simplicity of the approach in evaluating a producing well either before or after a workover/stimulation job. Lastly, it is proposed to make a further use of this new well testing approach in the industry to develop statistically:The characteristic profile of "Initial-vs.-Final Skin Factor", for each kind of workover/stimulation job at each specific exploitation area; and The characteristic profile of "Skin Factor through the Time", for each specific exploitation area. These profiles will let respectively, a more precise screening of the future stimulation candidates, and the forecast of the future stimulation jobs required in a zone to keep optimized its productivity. Introduction Actually, it is not a frequent practice in the industry to run Well Testing after successful workover/stimulation jobs, due to a practical sense of conserving this recently obtained success -obtained after a significant investment- by limiting temporarily any other posterior intervention in the well like extended shut-ins or downhole interventions. The purpose of this paper is to present a new well testing approach that pursues to overcome this actual field reality and to impact positively upon the previous and posterior technical evaluation of the workover/stimulation jobs. The most remarkable feature of this new approach, as will be showed, is the opportunity that it opens to obtain information about the well-reservoir systems, through tubinghead pressure measurements. Initial Technical Considerations Productivity Tests are a new approach to obtain key information of the well-reservoir systems. They are based on the analysis of the conventional Deliverability Tests but with the final objective of determining properties like skin factor (s) average pressure () or relative permeability (kr). Specifically, this paper will treat the case of Flow-After-Flow tests in oil reservoirs. However, the principles to present ahead will be also applicable to gas reservoir following appropriated considerations for the case. Due to the novelty of this approach, a summary of its four theoretical bases is presented below. A more detailed discussion about them will be found in the complementary paper OTC 18855 "Wrong Paradigms in the Actual Well Testing Analysis---Oil Reservoir Case". (1°) Wrong Equations in the Current Literature. The equation actually used by both the oil and the gas industries to predict the flow rate (q) of a well under a certain pseudosteady bottomhole pressure (pwf) is incorrect. Wrong equation: The same apply for its version with the gas deviation factor (z) instead of the factor (B) in gas wells. For the specific case of the oil phase production, Correct equation: (1) Where (qBo)pwf= (qo)pwf (Bo)pwf and K is a generalized "well-reservoir configuration factor". For the case of a simple radial system, K = 2pakh/[ln(re/rw) -3/4 +s]. The error in the literature is originated by a wrong solving of the volumetric factor (B)pwf in the deduction of the equation, considering a pseudosteady-state flow system and the crucial relationship defined by Brownscombe and Collins1. Again, an explicit deduction of the correct equation is detailed in the appendix of the OTC paper mentioned before2.

Abstract This paper presents a case history study that demonstrates monitoring bottom-hole well deliverability performance for flowing oil-wells completed in layered reservoirs. The field of study is the recently developed Xijiang 24–3 Field, offshore China in the Pearl River Mouth Basin. Development of the bottom-hole backpressure curve for individual layer packages and total well are presented as a reservoir management tool. A combination of individual layer production well tests, production logging tool (PLT) measurements and permanent downhole bottom-hole pressure readings are utilized to develop the total well bottom-hole backpressure curve. Pre-gravel pack and post- gravel pack results are discussed and compared to daily production measurements. The bottom-hole backpressure curve is shown to be an effective reservoir management tool to monitor well and reservoir performance. Introduction The reservoir management plan for the Xijiang 24–3 Field clearly outlines that sound reservoir management practice relies on utilization of available resources to maximize profits from a reservoir by optimizing recovery while minimizing capital investments and operating expenses. Early data acquisition and evaluation of the reservoir system are inherit prerequisites to good reservoir management. This paper presents analysis results from individual layer pressure transient well tests, flow-after-flow multirate production tests and monthly separator tests. In addition to these more conventional data sources, daily bottom-hole pressures supplied via a permanent electronic gauge attached to the electrical submersible pump (ESP) in each well were used together to develop the stabilized bottom-hole backpressure curve. These measurements are a key component in the short and long-term production surveillance and reservoir monitoring program that supplement the overall reservoir-management plan for the Xijiang 24–3 Field. RESERVOIR CHARACTERISTICS Xijiang 24–3 Field is located approximately 120 km (80 miles) southeast of Hong Kong in the South China Sea in waters of the People's Republic of China. Xijiang 24–3 reservoir and associated hydrocarbon bearing pay zones are located in seven separate Miocene sand horizons found at depths that range from 1900 to 2400 meters (6200 to 7700 feet) under 100 meters (330 feet) of water. Most sand horizons are further subdivided into individual sand layers separated by shale. Sand units are referred to as Hanjiang 1, 2, 2A, 3, 3A, 4A, 4B, 4C and 4D with the Hanjiang 4D being the deepest. These sands contain crude oil with distinctly different crude oil properties. The lightest crude is contained in the bottom sands. Oil gravities ranges from 25 API in the upper zones to 39 API in the Hanjiang 4D. P. 593

Summary

Pressure data from gas wells are normally analyzed by use of pseudopressure,which is a transformation of measured pressure. When tests are associated withlarge pressure changes accompanied by a severe wellbore storage effect, such asin tight reservoirs, use is made of pseudopressure and pseudotime transforms.The purpose of the pseudovariables is to linearize "effectively" thegoverningdiffusivity equation so that proper test interpretation can bemade.

In this study, normalized pseudovariables or transforms are introduced. Useof these new pseudovariables produces results identical to those obtained withthe conventional pseudovariables. However, the proposed pseudovariables offersome distinct practical advantages. For example, units of pressure and time areretained, thus giving a physical "feel" for the pseudovariabledefinitions. Other features include use of liquid equations for solving the gasflow, problems—i.e.. constants of the working equations remain unchanged.

This study also proposes two methods for estimating the rate-dependent skin,together with permeability, mechanical skin, and well deliverability. The firstmethod involves logarithmic convolution of pressure with flow rate, bothmeasured downhole by use of a radial model. A trial-and-error approach is usedto obtain the rate-dependent skin on a convolution plot. The second methodrequires a transient flow-after-flow test of short duration: a standard graphictechnique allows the estimation of the desired reservoir parameters.

Once the reservoir parameters are estimated with either method, the absoluteopen-flow potential (AOFP) of a well can be established by assuming a reservoirradius because the AOFP is relatively insensitive to this assumption.