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Abstract In this work we present a new theoretical understanding of pressure data obtained at a water injection well. The theory provides new physical insight on how permeability heterogeneity, saturation gradients and mechanical skin factor combine to influence the pressure response at the well. Based on the theoretical equations, methods for analyzing injection/falloff pressure data in both homogeneous and radially heterogeneous reservoirs are presented. For homogeneous reservoirs, we present procedures for estimating the mechanical skin factor from injection or falloff pressure data. Our theory provides a procedure for analyzing the pressure response during the second injection period of a two-rate test. It is shown that the information that can be obtained from a two-rate test is similar to that obtained from a falloff test. Introduction Injection testing is pressure transient testing during injection of a fluid into a well. It is analogous to drawdown testing for both constant and variable rates. Shutting in an injection well results in a pressure falloff which is similar to pressure buildup in a production well. However, the distinction between injection/falloff and conventional drawdown/buildup testing is that the flow characteristics of the injected fluid are different from those of the original reservoir fluids so that multiphase reservoir flow has to be considered in order to understand these tests. A novel insight into the theory of multiphase flow pressure transient testing was presented by Thompson and Reynolds. Their theory describes the averaging process that occurs during multiphase flow drawdown and buildup and explains pressure transient behavior of both single and multiphase flow in radially heterogeneous reservoirs. Although the focus was on gas condensate reservoirs, their studies included injection/falloff testing. In summary, the theory stated that well test mobilities reflect weighted average mobilities in those regions of the reservoir where rate is changing with time and where mobility is changing with time, i.e., (1) where, C1 is a units conversion constant, (see Nomenclature), KR is a "rate kernel", defined as, and KM is a "mobility kernel" defined as. In the case of injection/falloff testing, they argued that if changing mobility were the dominant factor occurring during the injection phase, it could explain the common belief that it is impossible to see beyond the "flood front" during injection. However, further numerical experiments on injection testing indicated that there were some cases where permeability beyond the flood front could affect injection-well pressure data. In this work, we investigate this apparently anomalous behavior carefully, and show that for injection/falloff testing, multiphase flow pressure derivative data yield information both about the reservoir region close to the moving flood front and the unflooded zone ahead of the front. Approximate Analytical Injection Solution In this section, we derive an approximate analytical solution for water injection in a radially heterogeneous reservoir. We assume an infinite cylindrical reservoir with a fully penetrating injection well of radius rw at the center of the reservoir. Wellbore storage effects are neglected. Water is injected into the reservoir at a constant rate, qwBw RB/D. Except for connate water, the reservoir is initially assumed to be filled with oil of a small and constant compressibility. The reservoir is made up of N+1 concentric cylinders having radii of r1, r2, … rN, with corresponding permeability values of k1, k2,…,kN, kN+1 respectively. P. 67^
The PDF file of this paper is in Russian.
PKKR JSC operates a couple of dozens of fields with more than a thousand wells. Consequently, a massive wells' surveillance program is conducted which includes pressure transient testing (PTT) and analysis (PTA). It leads to different kinds of cases which, eventually, help us to understand challenging issues. Thus, in the paper we try to shed light on how these data are critical to make the right decision with the aim of getting economical benefits for the company.
Field operation performs PTT on 70-80 wells annually such as pressure buildup and deliverability on producers, pressure falloff on injectors and interference tests on observation wells. All the tests are interpreted by the engineers of the company refusing from service companies during oil price decline in 2015 and purchasing commercial software. Using the software interpreter builds Horner and log-log plots, IPR curve which give the quantitative and qualitative parameters of near the wellbore, undamaged zones and outer boundary conditions. This information coupled with geological and production data are analyzed to gather puzzles into one full picture.
As the result of PTA the company could make important decisions which brought to millions of dollars of savings and earnings. The paper demonstrates standard cases, e.g. a pressure buildup test on a well helped to decide to execute fracturing and multiple time increase in oil rate was obtained. Oppositely, on another well falloff test showed presence of fractures, hereby, planned stimulation measures were cancelled in spite of low injectivity. In addition, falloff tests give additional information on how waterflooding is effectively carried out. Another case which was under active discussion includes the issue of converting a well to water injection, so we conducted an interference test and it reveals no response on adjacent producers. Again the company avoided the wrong decision and waste of money. Moreover, interference tests played a vital role in an extraordinary case where it was unclear how the wells produced gas more than reserves. Unexpectedly, the reason was a communication between two lithologically different reservoirs via fractures. So, it dramatically changed the geological concept of the field. There are other situations when PTA results help to characterize geometry of the reservoirs, presence of faults, their transmissibility, fractures distribution which all are critical for static modeling and dynamic simulation.
PTA is a crucial part of geology and petroleum engineering. It essentially helps engineers and managers to make right decisions. Sometimes it leads to big savings or significant profit earnings due to conducting or avoiding the works. Also PTA can change the geological picture of the whole field if properly analyzed. Thus, it is a powerful tool in the hands of geologists, reservoir and production engineers.
Abstract Pressure transient tests have been used for many years for the determination of well and reservoir parameters. Initially analyses of the tests were limited to evaluation of well performance. With the introduction of computer and pressure derivative log-log plots, numerous signatures of well reservoir and boundary responses are diagnosed and their model parameters estimated. Of recent, controlled reservoir monitoring from either permanent downhole gauges or standard bottom-hole pressure tests especially in gas reservoirs show that gas-water contact movement can be detected from the late time pressure derivative responses hence, water breakthrough time could be predicted. For a historical pressure transient tests taken at different times, the superimposition of their different pressure derivatives on the same log-log plot enable detection of advancing water front. The estimated fluid contacts from subsequent tests can be used to calculate gas volumes/reserves and predict water breakthrough time for the gas wells. This process was applied in Galaxy North field. The Field is a major domestic gas supplier for power generation in Nigeria and it started production in Dec 1963 with oil wells, while the gas wells came on-stream in 1984. Four gas wells have been drilled to in the field date. Current production is at 10Mbopd and 50MMscf/d from oil/gas and gas reservoirs. Pressure transient test are routinely carried out in the field to understand reservoir dynamics and gas wells performances and to ensure proper production planning towards uninterrupted gas supply to domestic market. The pressure transient tests carried out in Galaxy North wells between 2004 and 2013 depicted responses characteristic of upward trend (pseudo no-flow boundary). The boundary was established to be due to the effect of advancing gas/water contact. The estimated gas/water contact was compared with open-hole saturation log of an infill well drilled in June 2012 and results were close. This was used tovalidate the results of the pressure transient analyses. This paper presents guidelines and best practices on the use of classical reservoir tools in monitoring the gas water contact and the information derived could be used in estimating gas reserves and predict the future performance of the gas wells to ensure effective gas delivery to customer.
Permeability and skin factor can be misestimated from well testing data taken after completing wells in layered reservoirs. Results presented in this paper are based on field data and numerical simulation work on two wells in an offshore Louisiana field.
Testing results taken after completing the first well in the field with a gravel pack, gave considerably lower than expected permeability results that could have jeopardized the future development of the field. Well performance analysis based on pre-gravel pack flow, as well as investigation of existing well log data, indicated the possibility of a layer of higher permeability within the tested interval. In consideration of this analysis, a decision was made to proceed with the drilling of a second well in the field and perform a pre-gravel pack test to obtain original reservoir data. Then, the completion design for the second well and the treatment strategy for the first well would be based on the proposed pre-gravel pack test results of the second well.
The pre-completion impulse testing of the second well, drilled to the same reservoir, gave a higher calculated permeability than the first well, confirming our expectation. A new completion design was proposed and implemented on the second well. Post-completion transient testing indicated that the second well completion maintained communication with the higher permeability layer allowing the evaluation of the well completion skin. The new reservoir permeability then used in reservoir simulation resulted in a more reliable field production performance prediction and evaluation. Well log data, well test data, completion design, and reservoir simulation results are presented in this paper.
Poorly consolidated sandstone intervals are usually gravel packed to control sand movement into the wellbore when the well is on production. As it is known to negatively impact formation productivity at the wellbore damage should be minimized during both drilling and completion operations. This damage can usually be estimated from well test interpretation and is referred to as a skin value. However, in a multi-permeability layered reservoir, the amount of formation damage in each layer will be proportional to it's permeability. During well testing, this may result in significantly lowering the contribution of the highly damaged zone, and hence cause a misestimation of the effective permeability and skin. A basic description of transient flow models in homogenous, and layered reservoirs is presented in the next paragraphs. Description of transient flow regimes in different reservoir models has been presented by several authors. The system of equations governing transient flow of fluid in homogeneous porous medium is;
The semilog analysis solution to this problem using the Boltzmann transform approach is;