This paper presents the development of a new analysis tech-nique that can be used to determine the gas-in-place for abnormally pressured gas reservoirs. This new approach requires only production data ( p and Gp) ??? and does not require a prior knowledge of formation and fluid compressibility data. Using a pressure-dependent compressibility function based on the generalized gas material balance equation, this approach can be used to model both the rock collapse and shale water influx theories presented in the literature. In this work we introduce two new plotting functions:ce(pi- p) versus (p/z)/( pi/zi) and(p/z)/( pi/zi) versus Gp /G where these plotting functions are developed using the generalized gas material balance equation for a gas reservoir under the influence of a pressure-dependent formation compressibility function (Fetkovich, et al.1) in conjunction with the two straight-line trends observed on the p/z versus Gp plot for abnormally pressured gas reservoirs. Using these new plotting functions we develop a dynamic type curve matching technique that simultaneously determines the gas-in-place (G). In addition to gas-in-place, this new technique can be used to calculate pore volume compressibility as a function of reser-voir pressure. We provide the verification of our new analysis technique using the results of numerical simulations and we demonstrate the application of this methodology using several field examples. Introduction An ???abnormally pressured??? gas reservoir (sometimes called an ???overpressured??? or ???geopressured??? gas reservoir) is defined as a reservoir with pressures greater than a normal pressure gradient (i.e., >0.5 psi/ft). Bernard 2 observed that the effects of ???abnormal pressure??? behavior on reservoir engineering calculations could be ignored for cases where the pressure gradient is less than 0.65 psi/ft. A typical p/z versus Gp plot for an abnormally pressured gas reservoir will exhibit two straight lines – the first straight line corresponds to the ???apparent??? gas reservoir behavior (i.e. the abnormal pressure behavior) and the second straight line corresponds to the ???normal pressure??? behavior (Fig. 1).
This paper presents a conceptual study to evaluate the effectiveness of injection tests for the collection of dynamic reservoir data during project appraisals. A 2-D xy numerical model was built using representative field data to simulate the process and pressure response during injection and falloff tests for various boundary conditions. Various injection cases were studied: water injection into oil and gas condensate reservoirs, nitrogen injection into oil reservoirs, and nitrogen injection into dry gas, lean retrograde gas condensate, and heavy retrograde gas condensate reservoirs. For the case of nitrogen injection, we used a compositional option to model the phase interactions during the tests. Simulated pressure responses were analyzed using single-phase analytical solutions provided by a commercial well testing software package. We found that a composite reservoir model provided by well testing software package can be used to analyze the injection and falloff tests data. Permeability and distance to the boundary can be estimated for most of mobility ratios. Permeability found during the injection test is the effective permeability to the injected fluid. For the falloff test, it is possible to obtain the effective permeability of reservoir fluid. Type of boundaries can be detected and the distance from the well to the boundaries can be estimated by using effective system compressibility. The ability of boundary detection and mobility calculations are heavily dependent upon the optimal injected volume, and therefore, rely on proper well test design. For test design, the optimum injection volume is very important since it affects the time required to have radial flow in the uninvaded zone (‘reservoir zone’) which is necessary for the interpretation of reservoir boundary. Mobility ratio affects the length of transition zone and also the interpretation of reservoir boundary. Therefore, test design using a reservoir simulator is critical for determining the injection volume and the phase interactions if any, and understanding the pressure response. In addition to the above results, we utilize the material balance approach to calculate the compartment volume thus enhance the interpretation of injection and falloff tests. The results of this study provide a new and comprehensive overview of the practical application of the injection and falloff tests for the collection of dynamic reservoir data during project appraisal - with zero flaring. 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 that is similar to pressure buildup in a production well. Although an injection/falloff test is similar to a conventional drawdown/buildup test, the distinction between the two is necessary when the properties of the injected and formation fluids are different. Typically, injection/falloff tests are used for reservoir management of water flooding and enhance oil recovery projects, which usually happen later in the life of a field following primary depletion. Now, we are considering the use of injection/falloff tests during initial development planning of a field where these tests would be performed on appraisal wells drilled prior to the decision to develop the field.
As oil and gas developments mature, reservoir depletion reduces field output and fewer opportunities exist to drill new wells. Drilling new wells as the sole means of increasing field production often becomes less profitable, and it presents greater operational risks. Economic risks are also greater as the chance of completing good wells is getting less and the higher capital investment required. In many fields, operators, either intentionally or unintentionally, bypass pay zones during initial development by focusing only on the best zones. Accessing bypassed thinly laminated formations and low-permeability zones is economically attractive but poses several challenges. Several techniques were used to achieve sustainable commercial production from the bypassed zones in East Kalimantan. Hydraulic fracturing and underbalanced perforations were tried, with inconsistent results. Drilling new horizontal wells was not economical. Coiled-tubing (CT) drilling was the solution that provided a cost-effective alternative to the use of a conventional drilling rig. The advantages were a smaller location footprint, shorter trip times, ability to drill underbalanced, competitive rates of penetration, and through-tubing reentry. Because only a few CT drilling campaigns have achieved both operational and production successes, a campaign was proposed that used conventional well design and drilling programs. Previous lessons learned worldwide were used to reduce the drilling risk and enhance the chance of success. This was especially important in drilling a deviated hole through the coal zone of the subject well. This paper will describe three wells from the design phase through post-job evaluation. Lessons learned and improvement plans are also incorporated in this paper. Introduction Cost-effective development of a low-permeability gas reservoir in East Kalimantan's Badak and Semberah fields (Fig. 1, 2) has proven to be difficult. Conventional production techniques have not been able to produce the reserves at commercial rates because of the small and highly compartmentalized reserves. The current production optimization techniques, hydraulic fracturing and extreme underbalanced perforating, showed inconsistent results. A horizontal well was an ideal solution for field development, but because of the size of the reservoirs, drilling new horizontal wells conventionally was not economically attractive. Reentry drilling using existing wellbores was determined to be the best option to develop these fields, and coiled tubing (CT) drilling reentry applications were introduced. CT drilling techniques have evolved in regards to drilling practices and CT workstring limitations. Previous CT drilling experiences in the area were not very successful mechanically, mainly because of the candidate selection process. A joint feasibility study was performed to select well candidates that have a high potential for incremental production with minimum drilling risk. This objective was achieved with the combination of an extensive reservoir engineering study and reviewing lessons learned from other CT drilling operations [1,2]. A CT drilling reentry campaign was proposed with the key objective of maximizing gas deliverability and reserve recovery in a safer, cost-effective, and timely manner from low-permeability reservoirs and low-productivity wells. Deliverables of this CT drilling campaign were to achieve mechanical success, determine realistic costs, resolve drilling risk and evaluate low permeability reservoir productivity. Feasibility Study A well in the Semberah field that represents the average reservoir characteristics in the area of operation was chosen as the study case. The candidate selection process started by studying potential incremental production from a horizontal well against that of a vertical well, including considering the tubing size and its potential for production restriction. The openhole wellbore size was simulated to evaluate the effect of friction and length on potential production. The length of the openhole segment was reviewed not just from the most likely case to the limitation of CT drilling reach, but also with geological knowledge, limited well control, additional drilling time, cost, and associated drilling risk.
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