No abstract

Unstable well flow is detrimental to the technical and economic performances of an integrated production system. To mitigate this problem, it is imperative to understand the stability limits and predict the onset of unstable production of an oil well. Taking advantage of the phenomenon of slug flow and the onset of unstable equilibrium from inflow performance and vertical lift curves of a producing well, this paper presents a new method for evaluating the stability of an oil production well on the one hand and estimating its stable production limits in terms of wellhead flowing pressure and flow rate on the other hand. A novelty of this work is the introduction and quantitative characterization of three distinct stability phases in the performance of a production well. These phases are uniquely identified as stable, transition and unstable flows. Practical examples and field cases demonstrate the robustness of the new method. When compared against results from a commercial wellbore simulator for the same set of problems, the new method yields an average absolute deviation of 5.3%. Additional validation tests against a common, but more computationally demanding method of stability analysis yield satisfactory results. Several parametric tests conducted with the proposed model and method provide additional insights into some of the major factors that control well stability, highlighting scope for production optimization in practice. Overall, this work should find applications in the design and management of production wells.

Encountering a reservoir in either a gas-down-to (GDT) or an oil-up-to (OUT) situation poses a challenge to development planning and reservoir management. The resulting uncertainties in the distribution, in-place and recoverable volumes of oil and gas may jeopardize expeditious execution of the field development project. To confirm the presence or absence of either oil or gas and establish a possible gas-oil-contact (GOC), in some cases the drilling of an appraisal wells(s) may be required. This paper describes a method that does not depend on dedicated appraisal wells to reduce GOC uncertainties and proves to be a valuable method to de-risk planned reservoir developments. Where credible pressure-volume-temperature (PVT) data are available from the subject reservoir, compositional-grading simulations (CGS) can be employed to evaluate the presence (or otherwise) of a GOC within a vertically continuous reservoir column. From a thermodynamic standpoint, the GOC is that depth at which the reservoir fluid transits from being gas-like to oil-like, and vice-versa. Considering some saturated and undersaturated oil reservoirs in the Niger Delta as case studies, this paper demonstrates the applicability of a combination of PVT and CGS to de-risk the presence of GOC without resorting to either a new well or a pilot hole. In the cases where well logs have established GOC, blind tests show excellent agreement between CGS results and well logs. Similarly, CGS accurately suggests the absence of gas-like fluids within the proven undersaturated oil reservoirs examined. Finally, the results of this study will document that CGS is reliable and cost-effective for reducing GOC uncertainties and de-risking field development projects. Consequently, this method is recommended whenever credible PVT data are available.

Sandstone formations that have potential to produce sand during the life of the well account for a significant fraction of global recoverable volumes of oil and gas resources. The economics, environmental and safety implications of sand problems are critical enough to justify good knowledge of the potential for sand failure and production. Reliable evaluation of potential sand production is required to identify the needs for and the specification of sand-exclusion equipment during the project execution phase. To address these challenges, this paper presents a simple workflow that is premised on the petro-elasticity of the formation. Specifically, the proposed workflow uses cross plots of compressional sonic logs and density logs on reservoir-by-reservoir and well-by-well basis. From a petro-elastic standpoint, compressional sonic logs contain information on travel time required for sound waves to travel through the subject formation. The fundamental relationship between formation compaction (strength) and porosity has been explored to establish the trend of compaction, hence vulnerability of a sandstone formation to failure. In illustrating the applicability of the proposed concepts and workflow, some field examples from the Niger Delta are presented. Using wells with known history of sand failure and production, the workflow has been applied retroactively. The methodology presented is very useful for establishment of a quick screening sand control requirement. From a qualitative standpoint, it is found that the performances of the proposed workflow are in reasonable agreement with the history of sand failure and production in the example wells.

From a precipitation standpoint, wax is one of the most vulnerable hydrocarbon contents of crude oil and gas condensate. As a result, wax appearance temperature (WAT) is an important consideration for the management of flow-assurance challenges in the oil and gas industry. Ideally, the determination of WAT requires laboratory analysis of representative fluid samples. In the alternative, rigorous thermodynamic models are employed. However, both the laboratory and rigorous thermodynamic methods are expensive and demanding, yet they do not always guarantee accurate results for the full range of expected operating conditions. Either as a complement or substitute to these rigorous methods, several empirical correlations are available for predicting WAT. Two of these correlations are the composition-based models recently published by Hosseinipour et al. (2019). This paper reviews and interrogates the predictive capability of the two semi-empirical WAT models developed by Hosseinipour et al. (2019). In addition, based on some experimental datasets, a new correlation is proposed, which describes WAT as a simple function of solution gas-oil ratio (GOR). Using some WAT data obtained from different crude-oil samples in the Niger Delta, robustness of the Hosseinipour et al. (2019) and the new GOR-based correlations is examined. Compared to the experimental cases used in this study, the two Hosseinipour et al. (2019) correlations returned average absolute deviation (AAD) values of 13.0 and 3.0%. Conversely, the proposed GOR-based correlation yields an AAD of 1.0%. For the samples considered in this study, in addition to its relative simplicity, the new GOR-based semi-empirical model exhibits superior performance to both correlations from Hosseinipour et al. (2019). These results notwithstanding, potential improvement areas are highlighted for the three WAT models considered. Accordingly, an augmented form of one of the original Hosseinipour et al. (2019) models is proposed and validated.