Well tests are typically used to evaluate formation damage before and after workovers. Buildup tests are the most commonly used transient because less flow rate measurement uncertainties leading in more reliable results, and they have a robust mathematical foundation. To take in account the flow rate history and its uncertainties several deconvolution algorithms were developed. These algorithms also are applicable to minimize the initial distortion in the reservoir's pressure response due to wellbore storage, with the expectation of improving the permeability and total skin estimated in shorter logging times.
This paper presents a comparative study of conventional well test methods, and direct and indirect deconvolution techniques in several field cases. This study includes buildup tests of real-time sandface rate measurements during the after-flow period. These field cases were analyzed using conventional well test methods and three deconvolution techniques; namely, straight line approximation, material balance deconvolution, and modified "ß" function.
We determined that the three deconvolution methods are preferable to conventional well test methods because they require much shorter logging times; however, their reliability depends on the real-time data acquisition quality.
The well tests analyzed show that we cannot rely solely on the new deconvolution techniques for well test interpretation in shorter times; however, these new methods improve the reliability in the main matching parameters, permeability and total skin, at no additional time and cost. As a result, the new methods are excellent additions to the techniques used for well test interpretation.
Marie Van Steene, SPE, and Mario Ardila, SPE, Schlumberger; Richard Nelson, SPE, and Amr Fekry, SPE, BP Egypt; and Adel Farghaly, SPE, RWE Dea Summary In hydrocarbon reservoirs, fluid types can often vary from dry gas to volatile oil in the same column. Because of varying and unknown invasion patterns and inexact clay-volume estimations, fluid-types differentiation on the basis of conventional logs is not always conclusive. A case study is presented by use of advanced nuclear-magnetic-resonance (NMR) techniques in conjunction with advanced downhole-fluid-analysis (DFA) measurements and focused sampling from wireline formation testers (WFTs) to accurately assess the hydrocarbon-type variations. The saturation-profiling data from an NMR diffusion-based tool provides fluid-typing information in a continuous depth log. This approach can be limited by invasion. On the other hand, formation testers allow taking in-situ measurements of the virgin fluids beyond the invaded zone, but at discrete depths only. Thus, the two measurements ideally complement each other. In this case study, NMR saturation profiling was acquired over a series of channelized reservoirs. There is a transition from a water zone to an oil zone, and then to a rich-gas reservoir, indicated by both the DFA and the NMR measurements. Above the rich gas, is a dry-gas interval that is conclusively in a separate compartment. Diffusion-based NMR identifies the fluid type in a series of thin reservoirs above this main section, in which no samples were taken. NMR and DFA both detect compositional gradients, invisible to conventional logs. The work presented in this paper demonstrates how the integration of measurements from various tools can lead to a better understanding of fluid types and distribution.
The subject of the case study is a recently discovered oil and gas accumulation characterized by laminated, shaly sandstones with high apparent water saturation. Conventional openhole log data was inconclusive in identifying hydrocarbon type and net hydrocarbon pay zones. Moreover, reservoir complexity, low mobility, and inadequate differentiation of oil versus gas pay made it unlikely that a conventional production testing program would be successful and cost effective. However, reservoir fluid identification and pressure measurements were critical for resolving key uncertainties and guiding decision making for future appraisal and development.
Cased-hole wireline formation testing was used to better determine reservoir fluid type and productivity in selected intervals so as to differentiate oil pay from gas pay and net pay limits. A total of 30 dual packer stations were conducted in cased hole. The test results were used to choose the intervals, methodology, and equipment for subsequent production tests, which successfully proved the existence of three separate oil reservoirs and demonstrated commercial production rates.
A vibrating rod downhole fluid density device with the unique perpendicular oscillation modes provides in-situ fluid density measurements that improve a wireline formation tester's pressure, mobility, downhole fluid analysis, and sampling applications.
The measurement applications for the real-time water-base mud (WBM) formation-water sampling include contamination monitoring, in-situ fluid density, fluids identification, pressure gradient and fluid contact, and vertical compartmentalization. Field examples validate the measurements with the sample laboratory analysis and other measurements.
Wireline formation testing is traditionally carried out in open-hole wells. Advances in formation tester technology have provided the industry with a new modular cased-hole formation tester (CHFT). In this new design a hole is drilled through the casing and cement, communication with the formation is then established enabling formation testing and sampling. The drilled hole is subsequently plugged.
This paper describes several case-studies from the North Sea where a full range of formation testing applications (that would traditionally be performed in open-hole) were made in casing using a cased-hole formation tester. In addition to pressure testing and sampling, three recent case studies demonstrate advanced applications.
The first example demonstrates zonal isolation behind casing and identifies communication between layers under injection. The reservoir consisted of two layers with significant permeability contrast. The CHFT was set at the bottom of the higher permeability zone and a hole was drilled thought the casing and annulus. The pressure was monitored while seawater was injected at increasing pressure steps into the lower permeability zone. By analyzing the pressure response the degree of zonal communication and the maximum injection-rate were obtained.
In the second example, the CHFT was used to determine whether production wells could be drilled safely, and to evaluate bypassed reservoir layers. A very deep and deviated injection well completed and perforated over a long interval was tested with a CHFT deployed by tractor. Formation testing results provided a formation pressure profile in un-developed zones and showed that the injected interval was over-pressured and above the maximum safe pressure for drilling operations.
The final case study described in this paper shows an application of the CHFT for shale integrity testing. A poor cementing operation potentially left a production well without zonal isolation. The overburden shales are weak and prone to collapse. If the quality of the seal provided by the collapsed shale is tested for integrity and can be qualified as a barrier providing zonal isolation, the operator could avoid the expense of drilling a side-track. Two effective-stress testing cycles were made with the CHFT, which confirmed the integrity of the shale barrier, and quantified the minimum horizontal stress.
Many sedimentary features of gas fields are multilayered, deltaic, thinly laminated shaly sandstones consisting of channel and bar sands with limited lateral and vertical extension. Relying only on conventional openhole log data and performing correlations among nearby wells proved to be inconclusive in identifying gas reservoirs owing to their thin beds, high shale content, and variable formation water resistivity. Missing gas-bearing formations translates into lost productivity, while perforating water zones can have detrimental effects on well performance. Moreover, the limited lateral extent of these relatively tight gas sands leads to extremely depleted reservoirs alternating with layers with virgin zone pressures. As a consequence, the depleted layers face a significant overbalance while drilling with an oil-base mud system.
Given these complexities, fluid identification and pressure measurements have a significant impact in resolving key uncertainties of such reservoirs. The main challenges faced during formation testing in the reservoirs studied have been a) laminated, low mobility and thin formations with varying water salinity, b) high depletion, resulting in extreme overbalance for some layers in new wells, c) possible formation damage while drilling, d) cable creep while station logging.
Several different approaches have been recently launched to increase the success ratio of wireline formation testers (WFT's) in getting reliable pressures and fluid analysis, including real-time monitoring of each survey by reservoir engineers. This paper describes the development path and results from the new techniques: i) extra-large diameter probe, ii) elliptical probe, iii) the openhole driller, iv) cable creep correction and v) extra-extra high displacement pump unit. We will present each project and its impact on the improvement of WFT tester success ratio in such challenging environments.
Godefroy, Sophie Nazik (Schlumberger) | Zuo, Julian Youxiang (Schlumberger) | Fujisawa, Go (Schlumberger) | O'Keefe, Michael David (Schlumberger) | Ardila, Mario (Schlumberger) | Canas, Jesus Alberto (Schlumberger) | De Santo, Ilaria (Schlumberger Italiana SPA) | Cig, Koksal (Schlumberger Oilfield Services)
Knowledge of formation fluid density is necessary for a variety of applications. It provides information on pressure gradient, zonal compartmentalization, transition zone characterization, thin beds analysis, and other reservoir qualities. It also contributes to estimates of the commercial value of the produced fluid and is a critical parameter used in modeling of the reservoir fluids through the equation of state (EOS) to obtain a better representation of fluid Pressure/Volume/Temperature (PVT) properties. Various techniques exist today for the measurement of formation fluid density. These measurements can be taken either at surface on captured fluid samples or downhole in real time using formation tester tools. The different techniques include laboratory PVT analysis of a fluid sample brought to surface, pressure gradients, downhole optical
spectroscopy, and, recently developed, density measurements with the in-situ densimeter, which determines density by measuring the resonance characteristics of a vibrating object immersed in the fluid.
Although PVT analyses have excellent accuracy, downhole measurements have an advantage over surface measurements as they provide in-situ measurements under reservoir conditions without depending on the quality of the fluid from the sample bottle and sample transfer. They also allow better reservoir characterization without the need for an extensive sampling program. Pressure gradient surveys have been successfully used for decades to provide density
measurements of the formation fluids. Although the measurement depends on the accuracy of both pressure measurement and depth, it provides density unaffected by flowline condition of formation testers and mud filtrate contamination. Downhole flowline sensors, such as spectroscopic sensors and vibrating rods, have the advantage of providing density measurements of the fluid itself rather than relying on other parameters such as depth, but they are sensitive to flowline conditions. Whereas the estimation of density from the spectroscopic method relies on an empirical model that cannot be used in every condition, the vibrating rod in-situ density sensor gives a direct physical measurement and is thus the preferred method of measurement whenever available.