Taufan Marhaendrajana

A Novel Approach for the Evaluation of Oil and Gas Well Performances in Multiwell Reservoir Systems

The current methods for estimating Oilor Gas-In-Place and Reservoir Flow Capacity using dynamic data (pressure and/or rate) assume a single well in a closed system (or single well with constant pressure or prescribed influx at the outer boundary). In many cases a well produces in association with other wells in the same reservoir – and unless all wells are produced at the same constant rate or the same constant bottomhole flowing pressure, non-uniform drainage systems will form during boundary-dominated flow conditions. The approach presented in this paper accounts for the entire production history of the well and the reservoir and eliminates the influence of well interference effects. This approach provides much better estimates of the in-place fluids in a multiwell system, and the methodology also provides a consistent and straightforward analysis of production data where well interference effects are observed. This paper also presents the computation of flow capacity and skin factor using the multiwell approach. Introduction Analysis of well production data has some advantages over pressure transient analysis in which it is not required to shut-in the well. The data are also available over a long time span, which include transient and boundary dominated flow data. Hence, the complete information may be obtained about the reservoir (permeability, drainage radius, fluid-in-place, and reservoir type) and about the well (skin factor, effective fracture half-length, fracture conductivity, and effective horizontal well length). This type of analysis can be done by decline type curve method. The common practice is to use a single well model with fixed reference boundary (no-flow, constant pressure or prescribe influx). It implies that the well drainage area is constant over time. This may be true if the reservoir is produced only by a single well. Except for a very small field, this unlikely occur in practice. The change of individual well drainage area in a multiwell reservoir is due to addition of new well during development, infill well, changing well completion, closing/reopening, stimulation, and changing production schedule. The effect of some of these factors on well drainage area is illustrated in Figs. 1 and 2. These figures are generated using a numerical reservoir simulator. Fig. 1a shows pressure distribution when only single well, namely Well A, produces from the reservoir. When a new well, namely Well B, is introduced the drainage are of Well-A changes and in this case decreases due to competing with Well-B. Another scenario is shown by Fig. 2. At the beginning, two wells (Well-A and Well-B) produce oil with the same rate from the reservoir, and after some period of times each well establishes its own drainage area (Fig. 2a). When production rate of Well-B is increase while maintaining the production rate of Well-A, the drainage area of Well-B enlarges and the drainage area of Well-A shrinks. Those are two basic mechanisms that are responsible for changing well drainage area from which the explanation of the other factors can be derived. The effects of closing/reopening and infill well are similar to adding new well (Fig. 1). While the effects of changing well completion, stimulation, changing production schedules are similar to the effect of changing well production rate (Fig. 2). These phenomena of changing well drainage area cannot be captured properly if a single well model is used to analyze the production data. Hence, the objective of this paper is to develop a multiwell model so that the change of well drainage area in multiwell reservoirs can be properly addressed. Decline Curve Analysis In A Multiwell Reservoir System Marhaendrajana et al. presented general solution for the well performance in a bounded multiwell reservoir system: pD([xwD,k +ε],[ywD,k +ε],tDA)= qD,i(τ) d pD,cr(tDA –τ ) dτ k,i dτ 0 tDA Σ i = 1 nwell + qDk(tDA) sk............ (1) The physical model used to develop Eq. 1 is shown in Fig. 3. This model assumes a closed rectangular reservoir with a con-stant thickness, which is fully penetrated by multiple vertical wells (the well locations are arbitrary). The reservoir is assumed to be homogeneous, and we also assume the single-phase flow of a slightly compressible liquid. The SPE 93222 A Novel Approach for the Evaluation of Oil and Gas Well Performances in Multiwell Reservoir Systems T. Marhaendrajana, Inst. Teknologi Bandung

Experimental Studies of the Effect of Ionic Strength on Epoxy-Based Polymer for Water Shut-off Operation

This paper provides the experimental studies on parameters affecting the performance of epoxy based polymer used to be injected to unproductive layers in a water shut-off application. In this paper, we observe a parameter that can affect the performance of epoxy-based polymer which is ionic strength. By focusing the research on epoxy-based polymer, this study tackles the environmental problem and operation cost in water shut-off operation by proposing more environmental friendly and much cheaper polymer. The epoxy-based polymer can replace the use of the conventional Cr(III)-Carboxylate/Acrylamide-Polymer (CC/AP) which is more expensive and creates environmental problems. The epoxy-based polymer is tested at various ionic strength to determine the effect of ionic strength on density, rheological properties, gelation time and hard gel compressive strength after the polymer has gelled and hardened. The density of the polymer is determined analytically. The mass of the polymer is determined by weighing the gel, and the volume of the polymer was measured using the Archimedes method that measures the volume of irregularly shaped object to measure the gel volume. The density of the polymer is then calculated as the mass of the gel divided by the volume of the gel. To determine the rheological properties, the epoxy based polymer tested on a rotational viscometer at various time. Then, we observe the gelation time of epoxy-based polymers with semi-quantitative method by comparing the gel strength development with gel strength code US Patent No. 4688639. After it has gelled and hardened, the polymer is tested on hydraulic press equipment to determine the compressive strength of the polymer.

Reservoir Characterization of Lahat Outcrop for the Application of Chemical Flooding in Air Benakat Sandstone Reservoir, Center of Sumatera

The Enhanced Oil Recovery (EOR) method is a widely used for increasing oil recovery, one of which is by injecting ionic surfactants in sandstone reservoirs. The Sandstone Reservoir in Benakat Air Formation is composed of grains with dominant quartz, and cement with dominant calcite and silica. Brown clay (montmorillonite) fill in the rock matrix. The mineral montmorillonite is highly reactive to water, so that the sodium in montmorillonite will be hydrated with surfactant solution and result in swelling which can result in shrinking of the pore size of the rock and decrease the permeability so that the surfactant injection results are not optimum. Clay minerals and calcite have a positive surface charge at the fluid pH conditions in the reservoir so that it will affect the degree of adsorption and or precipitation of the anionic surfactant. Such adsorption and precipitation may affect the incremental oil recovery by injection of surfactant solution in the Sandstone reservoir, Air Benakat formation, either positively or negatively. Reservoir characterization has been done by examining the mineral content of sandstones reservoir on thin section. Two types of outcrops were analyzed in this study which consist of two thin section (L1 and L2). The mineral content of L1 outcrop consists of quartz, Potassium feldspar, plagioclase, gluconite and fossils, where matrix is composed of quartz, potassium feldspar and clay with dominant calcite cement. The L2 outcrop consists of grains filled with quartz, glauconite, plagioclase, biotite and fossil, where matrix is dominated by quartz and then clay, with calcite cement. The objectives of this study are to characterize the minerals contents in the sandstone core of Lahat outcrop for consideration of surfactant injection in Air Benakat Sandstone reservoir.

Dependence of critical porosity on pore geometry and pore structure and its use in estimating porosity and permeability

It is well recognized that the wave velocity is not only influenced by its constituent materials but also by the details of the rock bulk. This situation may bring about data points of P-wave velocity Vp measured on a large number of rock samples against either porosity or permeability of the frequently scattered although certain trends may exist. This paper presents the results of a study by employing rock samples on which ϕ, k, and Vp are measured in attempt to characterize critical porosity ϕc and its relation to other rock properties. The approach used in this study is the use of Kozeny equation. The equation is believed to account for all parameters influencing absolute permeability of porous media. A mathematical manipulation done on the equation has resulted in a power law equation that relates pore geometry √(k/ϕ) to pore structure k/ϕ3. Three different sets of sandstone amounting totally to as many as 716 samples were provided in this study. The properties measured are ϕ, k, and Vp, and grain size. For each sandstone data set, at least there are nine groups of the rock samples obtained. When Vp is plotted against ϕ, it is found that each group of each sandstone data set has both its own ϕc and an excellent relation of ϕ, Vp, and ϕc. Furthermore, combining all the basic equation for Vp, Kozeny equation, and the empirical relation for porosity results in a model equation to predict permeability. In conclusion, for the sandstones employed, ϕc is a specific property of a group of rocks having a similar pore geometry.

Study to improve an amphoteric sulfonate alkyl ester surfactant by mixing with nonionic surfactant to reduce brine–waxy oil interfacial tension and to increase oil recovery in sandstone reservoir: T-KS field, Indonesia

Crude oil with a high wax content and high pour point can be very challenging when enhanced oil recovery by surfactant flooding is to be applied. High wax content in crude oil will lead to high intermolecular interaction because of the increasing cohesion forces. It causes interfacial (IFT) tension between oil and brine to be high. Hence, oil recovery is relatively low. This paper presents formulation of an amphoteric sulfonate alkyl ester (SAE) surfactant with a nonionic surfactant (ester group) to reduce oil–brine IFT in waxy oil of T-KS field, in Indonesia. The ion–dipole forces may occur between SAE surfactant and nonionic cosurfactant molecules. The forces cause sulfonate chain to be attracted to oil phase. The formulated surfactant produces low interfacial tension between brine and waxy oil of T-KS oil field. Its ability to displace remaining oil in the pore space was also tested using coreflood tests. These tests demonstrate considerably good incremental recovery.

Study of Non-Newtonian fluid flow in porous media at core scale using analytical approach

Abstract Characterizing in situ polymer rheology in porous media is critical before further implementation of polymer injection in oilfield. Polymer as non-Newtonian fluid has unique behavior whose viscosity changes over various shear rate. This behavior creates unsuitable conditions which can lead to ineffective sweep efficiency improvement. The challenging issue in characterizing the in situ polymer rheology is how to construct the in situ Power Law model since the in situ viscosity cannot be measured directly. In this study, we use an analytical model to construct the in situ Power Law model. The model combines material balance equation, modified Darcy equation for non-Newtonian fluid flow, and equation of state. The model is solved for early (transient) time and late (steady-state) time. Coreflooding results in Berea Sandstone with 2000 and 500 ppm HPAM polymer injection are used for model’s simulations. Rheometer measurements are also used for comparison. The overall simulation results show there is no difference in flow behavior index between rheometer and porous media. The same fluid definitely gives the same flow behavior index through different measurement methods. However, there is significant difference in flow consistency index. It is caused by the effect of porous media’s tortuosity. The quantity of the skin parameter also depicts the thinning and thickening phenomena.