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.

A wellhead choke controls the surface pressure and production rate from a well. Chokes usually are selected so that fluctuations in the line pressure downstream of the choke have no effect on the production rate. This requires that flow through the choke be at critical flow conditions. Under critical flow conditions, the flow rate is a function of the upstream or tubing pressure only. For this condition to occur, the downstream pressure must be approximately 0.55 or less of the tubing pressure.

Oil reservoirs that do not initially contain free gas but develop free gas on pressure depletion are classified as solution gas drives. The solution gas drive mechanism applies once the pressure falls below the bubblepoint. Both black- and volatile-oil reservoirs are amenable to solution gas drive. Other producing mechanisms may, and often do, augment the solution gas drive. Solution gas drive reservoir performance is used as a benchmark to compare other producing mechanisms.

Summary Unconventional resources are of great importance in the global energy supply. However, the ultralow permeability, which is an indicator of the producibility, makes the unconventional production challenging. Therefore, the permeability is one of the critical petrophysical properties for formation evaluation. There are many existing approaches to determine permeability in the laboratory using core analysis. The methods can be divided into two categories: steady‐state and unsteady‐state approaches. The steady‐state approach is a direct measurement using Darcy's law. This approach has disadvantages because of the accuracy in the measurement of low flow rate and the long run time. The unsteady‐state approach includes pulse decay, oscillating pressure, and Gas Research Institute methods. These approaches are complicated in terms of setups and interpretations. Both steady‐state and unsteady‐state approaches typically have a constraint on the maximum differential pressure. We propose a novel unsteady‐state method to determine the permeability by transient‐pressure history matching. This approach involves simulation and experiments. On the experiment side, the ultralow‐permeability core undergoes 1D CO2‐flooding experiments, during which the transient pressure is monitored for history matching. On the simulation side, the transient‐pressure history is simulated using the finite‐volume method incorporating real‐gas pseudopressure and table lookup to deal with the nonlinearity in fluid properties and singularity during phase transition. The free parameter permeability in the simulation is adjusted for history matching to determine the rock permeability. Our new unsteady‐state approach is developed for fast and convenient permeability estimation for unconventional formation cores. This approach is a valuable addition to existing permeability measurement methods.

Summary This study continues the work of presenting a novel approach for making petrophysical assessments of tight core samples. This method, the full-immersion pressure-pulse decay (Hannon 2019), involves applying a rapid increase in pressure in a chamber surrounding the entire outer surface area of a cylindrical sample, shutting the system in, and monitoring the pressure decay in the chamber as it reaches a new equilibrium. A precursor article covered the numerical simulator designed to model flow through the sample, demonstrating its performance and accuracy in addition to providing a first-order comparison between the speed and shape of the pressure-decay responses of the full-immersion method with those of other similar transient methods. This study covers the parameter-estimation procedure and experimental verification through a proof-of-concept laboratory investigation. The investigations provided here demonstrate that under appropriate, achievable experimental conditions, the pressure data can be analyzed in such a way that returns an estimate of the porosity and apparent permeabilities both parallel and perpendicular to bedding from a single test performed on a single cylindrical sample. After determining these experimental conditions (the uniqueness window), this report outlines a data-inversion strategy to estimate the petrophysical properties (porosity, horizontal permeability, and vertical permeability) from each test. This strategy is put to the test through comparisons with measurements performed by a commercial core laboratory. A common set of samples recovered from an outcrop of a tight-gas sandstone formation were investigated using the full-immersion method, and their results are compared with those from conventional steady-state measurement procedures performed by the commercial laboratory. Comparisons between petrophysical characterizations of these samples, which had permeabilities between 25 nd and 2.3 μd, demonstrated close agreement in most cases. However, whereas steady-state measurements performed at the professional laboratory required 4 to 5 hours of testing time per measurement of a single permeability, similar assessments using the full-immersion technique, requiring approximately 5 to 10 minutes to complete, returned estimates of the horizontal and vertical permeability simultaneously. Additional analyses are provided to determine principal reasons of discrepancies in instances where agreement was not as strong. Based on lessons learned from these experiences, the report closes with suggestions on areas of improvement in the experimental approach. Once complete, these developments should propel this technology to fill a critical need to determine petrophysical properties (porosity and permeability) of tight rocks in a time-efficient manner and in a way that does not compromise their accuracy.

Miscible gas injection is a proven enhanced oil recovery method for medium-light oils. Miscibility is typically assessed with the slimtube experiment, which aims at identifying the minimum pressure (MMP) above which the displacement process is multi-contact miscible and leads to low microscopic residual oil saturation. During implementation of a miscible gas injection scheme, there will often be areas close to producing wells where the reservoir pressure is below the MMP and the question then arises whether the process can still be considered miscible. Another complicating factor occurs in reservoirs with significant lateral fluid property variation, where it is not intuitively clear how the MMP varies aerially.

We employ compositional reservoir simulation to investigate the impact of flowing bottom-hole pressures below MMP on the development and propagation of a miscible front. Starting with 1D simulations, we track a number of important properties such as the effluent gas composition over time, the component K-values at distinct positions along the displacement front, as well as the pressure at the front over time.

Due to the high gas mobility, the pressure drop per unit distance is greatly reduced in the areas flooded by gas. This means that the reservoir pressure at the gas-oil front is higher than the pressure at the same position before arrival of the front. Therefore, a miscible displacement can be maintained even when not only the flowing bottom-hole pressure but also the average reservoir pressure is below MMP. A key requirement is, of course, that the gas is injected at a pressure above MMP. We evaluate various parameters in terms of their ability to distinguish between miscible and immiscible displacement and find that the phase density difference versus pressure provides a unique advantage for estimating the MMP and we believe it can be used not only in 1D slimtube simulations but also in other thermodynamics-based algorithms. We also find that the vapor mole fraction, inferred from GOR measurements, is a better metric than GOR itself and that molar ratios applied to the effluent gas are very useful for tracking miscibility.

Halfaya oilfield in Iraq, discovered in 1976, contains multiple vertically stacked reservoirs. Currently main oil reservoirs are under primary development. The remaining deepest high GOR, HP/HT carbonate reservoir with original pressure gradient of 0.867 psi/ft has been drilled, tested, but undeveloped. An innovative production strategy has been put forward highlighting that high GOR crude can be injected into the upper oil reservoirs with partially pressure depletion, as energy-conservation measure, in view of its high wellhead pressure and good productivity during drill stem tests, therefore to achieve production enhancement and synergy among reservoirs.

In-house studies indicate high GOR crude can be miscible with all oils from eight zones. Field results show that injection processes can bring dead wells back production, yielding the prolific output. Also, water cut can be reduced immediately and field water cut rising trend can be mitigated.

The innovative injection processes are illustrated as follows:

New development wells should be deployed at updip positions to penetrate the all the hydrocarbon reservoirs with the thick pay.

The production enhancement strategy and processes in this paper could be of strong reference value to similar stacked reservoirs.

As the economic importance of natural gas continues to grow because of its relatively clean output, the exploitation of natural gas wells is of increasing importance in the energy industry. Monitoring of these gas wells is key and the Static Bottom Hole Pressure is an integral parameter when we talk about reservoir/well evaluation. The Static Bottom Hole Pressure is most often acquired through downhole gauge measurements. However, this method is disadvantaged by associated risk and cost of execution.

This paper presents a new method for calculating Static Bottom Hole Pressure. This new model considers the changes in the critical properties in the well in a fine grid segmentation of the well and uses the different values of specific gravity in a numerical simulation that involves a modification to the Cullender and Smith’s Equation that accounts for the variation in gas gravity profile values, fine grid segmentation, and well geometry.

Based on the results obtained, this model was seen to provide a more accurate estimate than the existing methods. The model was tested on 30 wells using the generated software and its results were benchmarked against other exiting models and compared with gauge measurements to validate the error reduction. Error estimation on the model showed that this method gives an average accuracy of 99% with an average absolute error of 0.304%. The results of this work showed that this method was effective in estimating Static Bottom Hole Pressure.

Abstract Black oil tables used in reservoir simulation and/or RTA/PTA history matching exercises are generated based on a fixed surface process (number of separator stages, psep, Tsep). However, even though the number of separator stages remain fixed, the separator pressure and temperature vary over time. This variation of separator conditions over time leads to an inconsistency between the rates used in history matching (assumes constant separator conditions) and the actual measured rates (changing separator conditions in the field). This paper provides a method to adjust all measured rates to a fixed surface process to ensure consistency between the black oil tables and rates used in history matching, and it also investigates for what fluid systems this normalization procedure is important. First, daily wellstream compositions are predicted based on a common equation of state (EOS) model, welltest and production data (separator oil and gas compositions, GOR, stock tank liquid API). Thereafter, these wellstreams are run through a fixed surface process, with the same separator pressure and temperature used to generate the black oil tables utilized in the reservoir modeling. Several practical observations are made. CGR normalization is in general not important for black- and volatile oil systems. However, it may be very important for near-critical fluids and gas condensate systems.The obvious application of the proposed normalization scheme is to calculate a set of consistent oil and gas rates for every well that can be used for history-matching purposes. Additionally, as black oil PVT properties are a function of the separator process, it is recommended to define a common surface process for an entire field or basin to ensure consistent apple-to-apple comparison between wells. Technical contributions include a qualitative framework of when CGR normalization is important and when it is not. The paper also proposes a simple solution to a widely known, but under-addressed and overlooked problem, not earlier presented in the open literature.

Phase diagrams are graphical representations of the liquid, vapor, and solid phases that co-exist at various ranges of temperature and pressure within a reservoir. Ternary phase diagrams represent the phase behavior of mixtures containing three components in a triangular diagram. Phase behavior of mixtures containing three components is represented conveniently on a triangular diagram such as those shown in Figure 1. Such diagrams are based on the property of equilateral triangles that the sum of the perpendicular distances from any point to each side of the diagram is a constant equal to the length of any of the sides. Several other useful properties of triangular diagrams are a consequence of this fact.