Pictured left to right: BP CEO Bob Dudley, NOC Chairman Mustafa Sanalla, and Eni CEO Claudio Descalzi signed a letter of intent in London on 8 October that will enable Eni to buy into BP’s Libyan production-sharing agreement. Eni, BP, and Libya’s National Oil Corporation (NOC) inked an agreement on 8 October that should enable Eni to buy a 42.5% stake and become operator of three of BP’s Libyan oil exploration contract areas, where the companies plan to resume exploration work next year. BP’s 54,000-sq-km exploration- and production-sharing agreement (EPSA) consists of two onshore contract areas, A and B, in the Ghadames Basin and one offshore area, C, in the Sirt Basin. BP currently holds an 85% interest in the EPSA, with the Libyan Investment Authority holding the remaining 15%. Eni and NOC jointly have other operations and infrastructure near the onshore areas.
Seales, Maxian B. (Pennsylvania State University ) | Marcelle-De Silva, Jill (University of the West Indies) | Ertekin, Turgay (Pennsylvania State University) | Wang, John Yilin (Pennsylvania State University)
It is anticipated that increasing pressure for cleaner burning fuels and lower carbon dioxide (CO2) emissions will cause a shift in global energy demand from oil to natural gas. In the near future, natural gas is expected to replace crude oil as the fuel of choice for energy production and transportation. In Trinidad and Tobago, natural-gas production has already surpassed crude-oil production. Natural gas accounts for 80% of the country’s energy export, but the reserves-to-production ratio is only 7 years (year 2022). Consequently, the Ministry of Energy has taken steps to supplement the natural-gas resource base by supporting initiatives that can potentially bolster the nation’s proven gas reserves. Such initiatives include invitations to tender on deepwater blocks offshore Trinidad and Tobago’s gas-rich east coast.
Even though initiatives are under way to boost conventional natural-gas reserves, effort was not placed on identifying and/or characterizing unconventional gas resources such as natural-gas hydrates. Furthermore, the potential hazards of submarine gas hydrates on deepwater exploration and production (E&P) activities on Trinidad and Tobago’s east coast were not assessed. The results presented in this manuscript provide oil-and-gas operators with a means of proactively managing the risk associated with natural-gas hydrates. More importantly, this study acts as a necessary precursor to future studies in characterizing and, later, harnessing the energy potential of Trinidad and Tobago’s natural-gas-hydrate deposits.
Okon, Anietie N. (Department of Chemical & Petroleum Engineering, University of Uyo, Nigeria) | Udoh, Francis D. (Department of Chemical & Petroleum Engineering, University of Uyo, Nigeria, Department of Chemical & Petroleum Engineering, Afe Babalola University, Nigeria) | Appah, Dulu (Department of Gas Engineering, University of Port Harcourt, Nigeria)
Several correlations have been developed to predict wellhead pressure–production rate relationship in the Niger Delta region. Regrettably, most of these correlations were developed from field data that are not from the Niger Delta region and with limited field test data ranges, so their predictions are lower than expected field values when applied to the Niger Delta. Additionally, some developed wellhead pressure–production rate correlations based on Niger Delta field data are made using in-house equations by the operating companies in the Niger Delta region. To ameliorate this anomaly, sixty four (64) field test data: choke size (S), production rate (q), gas-liquid ratio (GLR), flowing wellhead pressure (Pwh), flowing temperature (FTHP) and basic sediment and water (BS&W) were collected from oil producing wells in the Niger Delta region to develop wellhead pressure–production rate correlations based on Gilbert correlation and modified Gilbert equations. The developed correlations using Niger Delta field test data were compared with several authors' correlations. The results obtained indicate that the developed correlations resulted in better predictions than earlier correlations. In addition, the statistical analysis of the developed correlations used to ascertain the extent of their predicted values differ from the field test data and resulted in average error, absolute error and standard deviation of -0.1477, 0.4430 and 0.9582 for Gilbert formula and -0.2515, 0.4737 and 1.0997 for modified Gilbert formula, respectively. Furthermore, the developed correlations are comparable with an average correlation coefficient of 0.9869. Therefore, the developed correlations can be used as a quick tool to estimate the wellhead pressure–production rate relationship in Niger Delta oil fields.
Andersen, Niels (National Space Institute – DTU Space & Polar DTU) | Bekker, Pieter (University of Dundee and Steptoe & Johnson LLP) | Bishopp, David (Galp Energia) | Nassif, Toufic (Sonde Resources Corporation) | Nordentoft-Lauridsen, Sune (National Space Institute & Polar DTU) | van de Poll, Robert (Fugro N.V.)
This paper provides an overview of the history of global maritime boundary issues, mechanisms to resolve boundary disputes, and the economic potential that can be unlocked by coastal States through the exploitation of hydrocarbons trapped in areas currently unavailable for exploration and production operations.
Vast hydrocarbon reserves are tied up in areas, either underlying waters greater than 200 nm offshore or disputed by coastal States. In the former case technology in the form of deepwater drilling has made testing the potential feasible, whilst in the latter case many of the 311 or so areas in dispute are able to be tested and developed using conventional techniques.
Anything that appears to show a sovereign entity ceding control of land or sea to another country inevitably takes on a high profile in the countries concerned, which in the worst case can lead to armed conflict. It is a credit to those States that subscribe to the principles of the United Nations Charter and the United Nations Convention on the Law of the Sea ("UNCLOS") that they have reached agreement on how the economic potential trapped in disputed areas may be divided or shared.
High-profile, high-stakes disputes relating to offshore oil and gas deposits underscore the importance of the modern law of the sea, and international law generally, to the peaceful settlement of boundary disputes affecting the energy industry. Yet boundary disputes form an overlooked area of investment risk management in the energy sector.
This paper will introduce the technical and legal principles behind the solutions reached by States and will highlight some of the areas with the greatest hydrocarbon potential that have yet to be exploited as well as the areas of risk that require mitigation before investors will advance risk capital.
Core data from various North American basins with the support of limited amounts of data from other basins around the world have shown in the past that process speed or delivery speed (the ratio of permeability to porosity) provides a continuum between conventional, tight-, and shale-gas reservoirs (Aguilera 2010a). This work shows that the previous observation can be extended to tight-oil and shale-oil reservoirs. The link between the various hydrocarbon fluids is provided by the word "petroleum" in the "total petroleum system (TPS)," which encompasses liquid and gas hydrocarbons found in conventional, tight, and shale reservoirs. Results of the present study lead to distinctive flow units for each type of reservoir that can be linked empirically to gas and oil rates and, under favorable conditions, to production decline. To make the work tractable, the bulk of the data used in this paper has been extracted from published geologic and petroleum-engineering literature. The paper introduces an unrestricted/transient/interlinear transition flow period in a triple-porosity model for evaluating the rate performance of multistage hydraulically-fractured (MSHF) tight oil reservoirs. Under ideal conditions, this flow period is recognized by a straight line with a slope of –1.0 on log-log coordinates. However, the slope can change (e.g., to –0.75), depending on reservoir characteristics, as shown with production data from the Cardium and Shaunavon formations in Canada. This interlinear flow period has not been reported previously in the literature because the standard assumption for MSHF reservoirs has been that of a pseudosteady-state transition between the linear flow periods. It is concluded that there is a significant practical potential in the use of process speed as part of the flow-unit characterization of unconventional petroleum reservoirs. There is also potential for the evaluation of production-decline rates by the use of the triple porosity model presented in this study.
A statistical model with a strong correlation has been developed to determine average fracture density (FD) on the basis of production variability of 271 individual wells producing exclusively from the Nikanassin and equivalent formations in a large area of more than 15 000 km2 in the western Canada sedimentary basin (WCSB) in Alberta and British Columbia. Fractional production-variability plots (FPVPs) published by Nelson (2001) have been used successfully in the past in many naturally fractured reservoirs around the world. Up to now, the generation of such graphs has been based on empirical observations from field-production data. The variability of the graphs is interpreted qualitatively as a measure of reservoir heterogeneities. This paper presents a sequential methodology to reproduce empirical fractional variability plots of the Nikanassin tight gas formation using real data, an empirical variability-distribution model (VDM), and dual-porosity numerical simulation. Different simulation approaches and multiple sensitivities were generated from the simplest to the most-detailed cases to understand what causes the curvature of the FPVP in Nikanassin wells. The base simulation case is a homogeneous dual-porosity model, where porosity and permeability are set constant for matrix and fractures. A second case accounts for a heterogeneous dual-porosity model generated through statistical distributions of porosity and permeability. Finally, discrete-fracture-network (DFN) methodology is used to generate multiple fracture models from which stochastic fracture properties are generated for the simulation model. It is concluded that curvature of the variability plot is affected mainly by the occurrence of natural-fracture density. This finding permits estimating FD approximately parallel to the northwest/southeast-trending thrust belt of the Canadian Rocky Mountains in both the west and the east side of the deformation wedge. An unexpected result is that for a significant change in fracture permeability and porosity with constant FD, the fractional production-variability curve is not affected significantly in the case of gas reservoirs. Although the method is applied specifically to the Nikanassin tight gas formation, the theory is developed in detail in such a way that the methodology can be applied in other tight gas reservoirs around the world. Findings from this work are in good agreement with the geological description of the Nikanassin formation and with a production analysis performed in six Nikanassin study areas based on the cumulative number of wells vs. yearly cumulative gas production.
Flow-rate prediction of oil production wells is of prime importance to effectively confront high-water-cut and separator problems. (Semi-) empirical multiphase-flow correlations are proved quite useful for this purpose. This work presents new generalized multiphase flow choke correlation, derived on the basis of actual production data from horizontal and vertical wells from an oil field in Iran. The newly established correlation predicts liquid flow rates as a function of flowing wellhead pressure, gas/liquid ratio, surface wellhead choke size, and the newly incorporated parameters: basic sediment and water (BS&W) and temperature. To evaluate the influence of these two new parameters, a parameter-sensitivity analysis was performed and the results are shown. This proposed correlation exhibited an average error of roughly 2.89%, which is superior to those previous correlations in the literature that did not use these two newly incorporated parameters (BS&W and temperature). These new parameters can be added to the previous correlations when the water cut and temperature become important in the production history of the wells.
The phenomenon of multiphase flow (liquid and gas) happens in the wellhead of the majority of the producing wells. As the regulation of the flow rate becomes important during the production period in the producing wells, chokes are used for isolating the underground reservoir from pressure variations in the surface equipment, and also they are used for preventing or reducing the water production. Larger amounts of produced water from oil recovery result in increasing of operating costs and are a major environmental concern for oil production (Jin and Wojtanowicz 2010).
Although numerous multiphase-flow correlations are included in the literature (Al-Attar 2010), almost all of them are limited to a special operational condition in which the correlations are driven. As a result, the strength of those correlations for predicting the actual flow rate is restricted.
Gilbert (1954) developed the most popular multiphase flow surface choke correlation, but this correlation is valid for the critical flow condition when the upstream pressure of the choke is 70% or more higher than the downstream pressure (Ghareeb and Shedid 2007).
Flow through the wellhead chokes is mainly divided into two critical and subcritical conditions. Within this manuscript, the critical-flow condition refers to the state at which the flow rate reaches a maximum amount independent of the downstream and upstream pressure difference of the choke. Empirical correlations are mainly used for critical-flow condition.
Amari, Mustafa (Schlumberger) | Misherghi, Nasser Ali (Schlumberger) | Algdamsi, Hossein Ali (Schlumberger) | Sharaf, Hosam Eldin Mohamed (Schlumberger) | Abid, Mohamed (Schlumberger) | Porturas, Francisco (Schlumberger) | Zeglam, Adel (Mellitah Oil & Gas B.V Libya) | Jalool, Hassan (Mellitah Oil & Gas B.V Libya)
With the advances made in drilling long horizontal wells over the past decades it has become economically attractive to produce oil from thin oil rims. However, the production from these types of reservoirs presents several challenges. Gas coning is one of the most important ones. Horizontal well drilling traditionally helps to improve the oil recovery and avoid problems of premature gas/water breakthrough. In Bouri field, offshore Libya, the main concern of the operator was to establish an advanced method of controlling gas and water encroachment in a fractured carbonate reservoir characterized by high vertical permeability. This paper describes the first Inflow Control Device (ICD) installation for Mellitah Oil & Gas, and the first such application in Libya Offshore field. It was an integral part of a well completion aimed at evenly distributing inflow in a horizontal well, and at limiting the negative effects after occurrence of expected gas breakthrough. Due to small clearances involved, the ICD deployment presented a significant operational challenge. Despite the higher initial completion costs associated with ICDs, they can provide a cost-effective way to reduce long-term operating costs and increase yield. Production targets are achieved with longer, but fewer wells, maintenance and overhead. From a reservoir management point of view, ICDs can improve the productivity index (PI) by maximizing reservoir contact, minimizing gas coning by operating at lower drawdown, and increasing overall efficiency .Swelling-packers were used to compartmentalize the horizontal and build sections, allowing better drawdown control and eliminating cross-flow issues. The completion required re-thinking of the established acid-wash treatment procedures, ultimately improving the overall well clean-up. Integrated analysis methods using steady-state wellbore hydraulic and 3D dynamic simulators were performed to generate flow profiles and calculate ICD pressure drop along the horizontal section. The models were updated using results from logging-while-drilling (LWD) and with real-time modifications to the initial design.
To verify the inflow profile along the length of the ICD completion, production logging (PLT) was conducted. The inflow profiles compared favorably with those predicted by the models.