Geostatistical-based models provide a considerable improvement for predictive reliability of dynamic models and the following reservoir management decisions. This study focuses on geostatistical modeling the Paleocene Zelten Carbonate reservoir in the Meghil field. The field was discovered in 1959 and production operations began in 1961. Nineteen wells have been drilled to date. The structural framework consists of three slightly asymmetrical anticlinal structures trending NW-SE with steeper dip on the SW flanks. Each of the structures are separated by major normal faults. Seismic interpretation suggests that carbonate build-ups are most likely present on the three separate structures. Edge detection was used to clarify the structural geometries and the presence of additional minor faults. Pillar gridding technique was used to develop the structural framework including four major faults that are partially sealed based on analysis of the available DST and production test data. Stratigraphic analysis indicates a local presentation of dolomitic limestone in the northern portion of the main and the western structures caused considerable litho-facies variation that impacted the distribution of the petrophysical properties. Basic and advanced formation evaluation the net reservoir thickness of about 15 feet with an average porosity of 17% and average water saturation of 35%. Geostatistical-based applications that combine the spatial statistics (e.g. the semivariogram) and the available well and core data were used to populate the reservoir model with porosity, permeability, facies (lithology), net/gross, and water saturation. A conceptual facies model was also used to constrain the reservoir property distributions. Sequential Gaussian Simulation (SGS) was used to populate the model with porosity and water saturation and Sequential Indicator Simulation (SIS) was used to populate the facies model with permeability. The modeling parameters (e.g. semivariogram, correlation coefficients) were significantly constrained by the limited number of wells. Based on the limited number of wells available the semivariogram analysis resulted in a spherical semivariogram model with major axis range of 1435 meters for porosity and 1800 meters for water saturation. Minor axis ranges were about 50% of the major axis ranges. Given the limited well data, a significant effort was made to document the potential impact of the semivariogram parameters on the original hydrocarbon in place (OHIP) estimates and the lateral stratigraphic continuity of reservoir properties. The deterministic approach resulted in place volume estimates of 60 MMBBL and the stochastic approach provided an estimate of 45 MMBBL.
This seminar will teach participants how to identify, evaluate, and quantify risk and uncertainty in everyday oil and gas economic situations. It reviews the development of pragmatic tools, methods, and understandings for professionals that are applicable to companies of all sizes. The seminar also briefly reviews statistics, the relationship between risk and return, and hedging and future markets. Strategic thinking and planning are key elements in an organisation’s journey to maximise value to shareholders, customers, and employees. Through this workshop, attendees will go through the different processes involved in strategic planning including the elements of organisational SWOT, business scenario and options development, elaboration of strategic options and communication to stakeholders.
Green fields today mostly can be regarded as marginal fields and successfully developed. It covers the complete assessment of the oil and gas recovery potential from reservoir structure and formation evaluation, oil and gas reserve mapping, their uncertainties and risks management, feasible reservoir fluid depletion approaches, and to the construction of integrated production systems for cost effective development of the green fields. Depth conversion of time interpretations is a basic skill set for interpreters. There is no single methodology that is optimal for all cases. Next, appropriate depth methods will be presented. Depth imaging should be considered an integral component of interpretation. If the results derived from depth imaging are intended to mitigate risk, the interpreter must actively guide the process.
Decisions in E&P ventures are affected by Bias, Blindness, and Illusions (BBI) which permeate our analyses, interpretations and decisions. This one-day course examines the influence of these cognitive pitfalls and presents techniques that can be used to mitigate their impact. Bias refers to errors in thinking whereby interpretations and judgments are drawn in an illogical fashion. Blindness is the condition where we fail to see an unexpected event in plain sight. Illusions refer to misleading beliefs based on a false impression of reality.
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.
El-Galil, Yehia S. Abd (Amal Petroleum Company) | El-Moniem, Mohamed A. Abd (Amal Petroleum Company) | El-Sherif, Mamdouh (Amal Petroleum Company) | Khalifa, Tarek (Amal Petroleum Company) | El-Fattah Fayad, Abd (Amal Petroleum Company) | Ramadan, Nasr (Cheiron Amal Petroleum Corporation)
Production Optimization is often attributed to new technologies, sophisticated algorithms and application of market leading expertise. In Amal, after years of production, our learning is production optimization is more about doing simple things well and getting better at it every day through practice and planning.
In this paper, we will present an example for the capability of using limited resources in offshore fields to maximize oil production for wells suffering from high water production.
The challenge was in one of oil wells, which has been ceased to flow due to high water cut and consequently we deferred around 400 BOPD. To illustrate this point, we will focus on how we can retain the oil production from this well while the ongoing gas lift project is not ready yet. We thought about the integrity between the wells in the same platform by using one of gas wells from gas reservoir as injector to lift the ceased to flow oil well and how we could obtain the gas quantities to be injected into the oil well however the rest will be produced normally from the gas well.
We will share how a loaded well with high water cut was revived through this idea of gas lifting with a higher pressure well, many runs were performed using commercial software of wells modeling and reservoir simulation. We determined the proper rate and WHFP from the gas well to be injected in the oil well to recover that oil and we could improve the well productivity.
As a result, the well has produced over the last ten months and we could maximize the oil production with our limited resources and without any huge gas lift project. Again, this idea helped maintain safe and continuous production from ceased to flow well and we recovered around 110,000 barrels of oil until now and the well still produce.
Most of the crude oil is already recovered and discovering new oilfields tend to be challenging and difficult. Implementing an EOR method is essential to enhance the production life of mature oil fields and to make them economically more attractive. Especially, for heavy oil reservoirs chemical flooding is besides thermal methods promising. Only a limited number of alkali flood projects alone are reported worldwide. Phase screening represents the first step of experiments and gives information about the ability of various alkali solutions to generate in-situ surfactants at different concentration ranges.
In this study, carbonate-based alkalis were screened on their effect on in-situ soap generation. Two oil reservoirs both located in the Matzen oil field (Austria) were observed, where an alkali flood project will be realized in the near future. In lab scale, were phase experiments with various concentrations of carbonate-based alkalis (sodium and potassium carbonate) screened at the water-oil-ratio 5:5. Formulations with synthetic and real softened brine were compared, using dead oil and viscosity-matched oil with cyclohexane. Samples were observed over time (100 days) to figure out their equilibrium at reservoir temperature. Afterwards large-scale samples were prepared and viscosity measurements performed.
Potassium carbonate (K2CO3) is not well investigated in the literature as an alkali agent yet. It showed very promising results in all performed trials and generated remarkably more amounts of in-situ surfactants compared to Na2CO3, which is the most frequently used alkali performer. Additionally, in most concentrations the micro emulsion viscosities were lower. Thus, potassium carbonate might be an interesting candidate in future alkali applications.
This paper reports on the start-up of Phase 1 of a Solar Steam Generation facility (SSG) and its export to the existing steam headers of the Amal oil field, located in the south of Oman. Significant considerations within the SSG are reviewed and the impacts on the client's systems identified and discussed.
Operational performance indicators on SSG and Client facilities are studied, primarily based on process operating data and equipment stability records, to ensure that the supply of variable steam from solar generation does not create any detrimental effects on the existing facilities. Of particular interest is to assess the success of a variable rate steam injection mode and the impact this has on Client facilities: system pressures, conventional steam generator operation, and wellhead steam injection rates.
Previous simulation work has demonstrated that this mode of operation is essentially equivalent to fixed steaming rates provided the same daily equivalent of steam is injected in both cases. However, this has never been demonstrated in the field for extended periods.
Operational data showed that, as anticipated, the Client's systems were able to accomodate the cyclic swings in header pressure and the induced variable flows through their fixed, manual chokes. Data showed that the Client's conventional steam generators (HRSGs) continued to operate as normal without noted issue.
The changing pressure in the Client's steam header propagated back to the solar steam generation facility which was able to easily manage its operations automatically, causing no disruptions to its operations. No safety-related incidents arose, and all processes were well-managed on-site.
This study demonstrates for the first time the performance of large-scale solar steam generation facilities operating alongside conventional steam generation and distribution systems with the two disparate systems seamlessly integrated. It also demonstrates that variable rate steaming has practical application within this field. This highly dynamic process has been sympathetically and successfully added to an existing large, steady-state operation without introducing significant issues to either system.
As waterflooding has become one of the most favorable approach for secondary recovery globally, understanding flood front behavior and reservoir sweep becomes even more pertinent to maximize recovery. To monitor the effectiveness of a waterflood program, chemical tracers are often deployed for enhancing surveillance techniques. This paper presents a classic example of value creation from the existing tracer database with the demonstrated workflow of the Residence Time Distribution (RTD) method in tracer interpretation applied in a mature waterflood field. The analytical study conducted was in a complex oil rim field located in East Malaysia.
As a five-year sampling programme was initiated for this field, a substantial amount of sample and corresponding tracer response data allowed the field to be a strong candidate for tracer RTD data analysis. Injection was carried out via smart wells into 28 zones and samples were taken on routine basis from monitored producers. Breakthrough of unique tracers coupled with low detection levels from the vendor laboratory were utilized as a foundation for constant waterflood optimization. Flow geometries and reservoir continuity between each injector-producer pairing were measured in detail through analysis of chemical tracer response curves.
Apart from immediate injector-producer communication upon first tracer breakthrough, a detailed study on water flood performance based on the RTD method allowed the pore volume swept, mass recovered from each section and quantification of heterogeneity to be determined. Flow geometry and reservoir continuity between each injector-producer pairing were also measured allowing identification of thief zones, out of zone injections, vertical communication between layers, and behind casing flow. As a result, the information gathered allowed the optimization of each injection zone based on the outcome of the tracer response at the respective producers. This information has proven beneficial to the reservoir surveillance team allowing insightful decisions to be made upon subsequent opportunities for production and water flood optimization.
Numerous studies on unconventional shale well production data have shown that downhole pressure fluctuations can exceed 300 psig during a slugging period. Such pressure fluctuation will result in very high drawdown and could lead to near-wellbore formation damage when the rock failure criterion was met. An engineering workflow was developed to investigate the impact of multiphase slugging events on cemented casing plug and perforation (CCPP)and open hole sliding sleeves (OHSS) completions. Based on transient pressure analysis and geomechanical evaluation, safety operational envelope was generated to minimize the risk of formation damage due to slugging behavior.
In this study, a dynamic multiphase flow simulator was used to predict the pressure amplitude and frequency during the slugging events in both a CCPP and OHSS completion configuration. The results from the simulation were then incorporated into a geomechanical model to analyze and identify potential hydraulic fracture closure and formation damage concerns, which can compromise well performance.
The results from this study show that OHSS completion is more vulnerable to damage during the downhole slugging period than a CCPP completion. However, severe formation and fracture damage could occur during downhole slugging for CCPP well if the well is operated outside the safety operational envelope. Results from the two case studies led to the conclusion that it is crucial to consider the effect of downhole slugging on near-wellbore fracture and formation integrity to avoid permanent and irreversible damage.