Rate dependent skin is a key factor influencing the deliverability of gas producing wells because of the phenomena of high velocity flow behavior around a limited, near wellbore cross-sectional area. Forchheimer (1901) [1] proposed an additional factor in Darcy’s original equation to account for the pressure drop due to high velocity flux in the porous media, known as "Inertial Resistance Factor (β)", which is now a determinant parameter in the flow modeling of gas wells. Several authors have developed different correlations that account for the inertial forces acting under these producing conditions. Multi-rate and Pressure Transient Analysis (PTA) evaluation was performed on nine (9) gas well tests in the Dolphin Field. The Non-Darcy Flow Coefficient (NDFC) obtained was compared with predicted NDFC’s using 18 Beta (β) correlations, where each correlation has its own assumptions and determinant parameters. Existing correlations do not match the actual NDFC in the field, as a consequence, a new Inertial Resistance Factor Correlation (IRFC) is proposed for assessing the unknown NDFC in the ECMA fields with a minimum percentage error of 17%. The following study will detail the results of a probabilistic approach which uses correlations to provide a better estimate of NDFC in the Dolphin field, with the final objective of reducing uncertainty in forecasting production on recompletions and new wells in East Coast Marine Area fields.

One of the most important rock properties in Reservoir Engineering is very often absolute permeability. Unconsolidated sands offer some of the highest permeabilities due to their typically low consolidation degree, leaving more space between the porous media for conductivity. This low degree of consolidation, however, also brings high sand production potential while producing the reservoir; therefore sand control is required. This paper discusses how well failure histories were used, along with downhole analytical methods, to determine maximum FLUX limitations recommended to be used to minimize completion failures and sand production while producing at the highest safe rate.Chevron has a 50% working interest in an NOJV area with BG, in three different offshore dry gas fields located in Trinidad and Tobago. Dolphin field is the main producing field, having been on production since 1996 from four main groups of sands, all of which are unconsolidated (D, Upper E, Lower E and G sands). Due to the sands highly unconsolidated nature and targeting high gas production rates, all completions in the field utilize openhole gravel packs for sand control.During the field production history, several sand completion failures were encountered, as evidenced by formation sand production at the surface and reduced rates; and in some cases, complete cessation of flow (due to sand fill). After completing various analyses on possible failure root causes, it was found that the highest probable reason for sand completion failure was high FLUX across the completions. After drawing this conclusion, it was imperative for the Reservoir Management and Production Teams to understand FLUX associated with the failures, determine the maximum recommended FLUX to avoid future failures and finally, to apply a FLUX limit on current and future forecasts, from a prudent reservoir management perspective, in order to develop more realistic and reliable production forecasts.This case study shows how the failure history data was used and integrated with a downhole velocity analytical approach in order to determine the maximum FLUX limit to prevent current and new completion failures and sand production.

This study assessed the impact of static and dynamic variables in EUR and NPV in the development plan of a North Sea offshore field with 81 m of water, light oil crude of 40.5 API and 510 SCF/STB of GOR comprised of sandstones from a shallow marine environment in anticline structure separated to the northeast and southwest by a pair of normal faults. The analysis is conducted through the application of different experimental design techniques and the preparation of a comparison between them. Uncertainty analysis has been prepared to characterize the appropriate range for nine variables that affect the oil recovery and net present value of the field development. A Folded Plackett-Burman design was prepared to screen the initial nine variables; the linear regression results show that the oil water contact, permeability anisotropy and net to gross are the significant variables. Also, the residual analysis demonstrated that the proxy equation should be improved to have better predictability in the non-sampled space. In consequence, a D-Optimal and a Central Composite experimental design were prepared for the three significant variables. The regression results show better coefficient correlation and lower least square errors in the D-Optimal design using a full quadratic model and confirmed the oil water contact as the most significant variable of the field. Finally, Monte Carlo Simulation was performed in the proxy model from the D-Optimal design, which resulted in an expected value ultimate recovery of 357 MMSTB. The paper presents an exciting workflow to analyze different experimental design techniques, compare them and use the most suitable to prepare the development plan of a field.

Dolphin field is a mature gas field located in the East Coast Marine Area, offshore Trinidad. One of the methods to estimate gas initially in place (GIIP) of the field is material balance; however, this approach presents some particular challenges which include: sands are not well consolidated and exhibit very high rock compressibilities, communicating reservoir compartmentalization and wells are produced at very high rates. These three factors don't allow for a straight-forward understanding of the aquifer size, normally assessed with a deterministic Cole Plot analysis. As a result of these complexities, analysis demands a more in-depth understanding of the uncertainties of the reservoirs and their implications on fluid in place estimation to avoid bias and anchoring. This paper presents a case study of the workflow used in determining probabilistic material balance models for one sand in the Dolphin Field. Initially, an uncertainty analysis was conducted to determine the appropriate ranges of petrophysical data and aquifer properties that were used as input information for the material balance models. Experimental Design was then successfully applied to generate probabilistic material balance models: Placket-Burman design of experiment was used to identify the key uncertainties in a linear model. Monte Carlo simulation was used with the resultant response surface equation to determine probabilistic volumes of the field. This project successfully achieved a probabilistic GIIP range for a single method testing sand of the field, ultimately yielding a better understanding of the significant uncertainties and their implications. The resulting probabilistic material balance models also enable the use of an integrated asset model to generate fit for purpose forecasts and a provides a more rigorous quality checking method on reservoir simulation results. This paper will discuss a simple workflow used in probabilistically determining GIIP for one producing horizon in Dolphin field. Given the high confidence results encountered on the single sand, this approach will be applied to all Dolphin sand horizons to provide higher confidence GIIP estimates for the entire portfolio.

Compartmentalization is defined as the geological segmentation of once continuous reservoirs into isolated compartments. It is a complex subsurface uncertainty that is the product of the combination of stratigraphic architecture, structural architecture, fault permeability and diagenesis. This paper will discuss a process that was developed to integrate geophysical, geological and reservoir data to study compartmentalization in a mature field located in Trinidad. A set of seismic, well log, petrophysical, and well test data was integrated to construct a 3D structural model to study two compartmentalized/baffled reservoirs in Dolphin Field, Trinidad. This integration of various data was used to develop a practical and efficient methodology of studying compartmentalized reservoirs. Material Balance analysis has proven that there is poor connectivity between select wells within the same reservoir of Dolphin field due to the existence of likely barriers or baffles that affect pressure communication and flow, dividing the reservoirs into various compartments. Compartments were defined for two unconsolidated Pleistocene Reservoirs within the field’s E and G sands. In order to determine the geometry and extension of these partitions in E and G sands, re-interpretation of the seismic 3D PSDM data was done, applying seismic attributes to enhance the visualization of the data. Additionally, all suites of well logs were analyzed to define the geologic markers of interest and assess evidence of compartmentalization. Well correlations were revised to assess lateral changes that could represent a reservoir fluid confinement. Furthermore, reservoir data was evaluated in order to determine areal and vertical connectivity, and analyze the formation fluids to estimate the Gas-Water Contact on the wells. A new structural model was generated from the 3D seismic interpretation, which resulted in defining different compartments along the top of the structures. Faults framing these areas were characterized by calculating Shale Gouge Ratio (SGR) and Shale Smear Factor (SSF) for defining possible sealing faults. The values obtained for SGR and SSF fell within the range of a ‘good seal’ for each fault (> 40%), therefore they were deemed likely flow barrier/baffles. Juxtaposition (evaluated on the Allan diagrams) was analyzed along every fault to determine the lateral continuity of the seal. Integration of different data provided a significant benefit to the study of possible compartmentalization/baffling of select reservoirs in Dolphin field. Seismic attributes application enhanced structural modeling and provided evidence of compartmentalization in both sands. SGR, SSF results and Allan Diagrams determined the sealing properties of the confining faults. Formation Tester logs (e.g. MDT) assessed the existence of different Gas-Water Contacts on several wells. Integration of similar data and following this processes workflow could prove to be a viable means of identifying compartmentalization in other analog fields throughout the region.