Africa (Sub-Sahara) Eni discovered up to 250 million bbl of light oil in the Ndungu exploration prospect in Block 15/06 offshore Angola. A well in 1076 m of water reached TD of 4050 m and proved a single oil column of approximately 65 m with 45 m of net pay of 35 API oil. Well results indicate production capacity in excess of 10,000 B/D. Eni operates Block 15/06 with 36.8421% Joint venture partners are Sonangol P&P (36.8421%) and SSI Fifteen (26.3158%). Eni discovered gas and condensate on the Akoma prospect in CTP-Block 4 offshore Ghana. The Akoma-1X exploration well was drilled in 350 m of water approximately 50 km offshore and 12 km northwest of the FPSO John Agyekum Kufuor.
Horizontal wells have been drilled extensively in recent years where several challenges have been faced such as increased cost, short well life, limited accessibility, uneven stimulation, less productivity and water production. Although similar issues encountered in all reservoirs, tight reservoirs impose extra difficulty given their complexity and inherited limited productivity. In order to optimize flow profile and extend the life of horizontal wells, several techniques were implemented including Production Segmentation Completion Technique (PSCT) and Inflow Control Devices (ICDs).
Initially, a single well simulation study was conducted to determine and evaluate the effectiveness of using a dual completion string and ICDs in a horizontal well with open hole across a carbonate reservoir which generally suffering from rapid increase of water-cut due to high drawdown around heel. A review of literature and internal well cases were conducted to highlight the heel to toe effect and early water breakthrough issues.
As a result a novel multi-zones completion technique was proposed and implemented, this design comprises running a lower completion (LC) as isolation string and an upper dual completion, the hole heel will produce from the open hole (OH)-LC annulus through the short string (SS) and the toe will produce through LC through the long string (LS) stung-into LC. This design provided a method to choose the most appropriate horizontal section and demonstrated the value of having dual completions in terms of oil gain and water management as well as improved accessibility. This approach is then compared with the option of utilizing ICDs as a sophisticated method to control flow and manage production from different compartments of the openhole.
Field results supported the success of segmented completion project providing future opportunity to optimize the production configuration of horizontal wells. Thus, reducing number of wells and increasing production. Execution of this project increased production by about 1.3x versus single completion well, accessing deeper horizontal areas, with an optimized cost in addition to saving time. On the other side, inflow control devices were used extensively in industry with a large chance of success when planned well. On the simulation model, ICDs were added and different sensitivities were tried to decide on the best configuration.
Implementation of such optimization tools in early stages may be crucial to mitigate potential well issues that are difficult to cure later in well life. This complex and high profile project was executed against a background of limited time frame and resources. Project team demonstrated ability to adapt and succeed when presented by a truly unique challenge. A comparison study was essential to decide on best approach. To date, PSTC technique is the first to be implemented in UAE and the Middle East.
Electric Submersible Pump (ESP) is a key artificial lift technology to the petroleum industry. Worldwide installations of ESPs are in the range of 130,000 units, contributing to about 60% of the total worldwide oil production. An ESP is made up of hundreds of components integrated together to perform the lifting function. Materials in these components belong to several categories including metals, ceramics, polymers, and others. A good understanding of these materials and vigilant selection for a specific application are critical to the reliability and run life of an ESP system. This paper presents an overview of two classes of materials used in ESP systems: metallic and ceramic materials. A subsequent paper is planned to cover all other categories of materials. The intent is to provide a reference for ESP field application engineers who are responsible for ESP design, component selection, equipment longevity and production optimization.
The information compiled in this paper is a result of extensive literature review. It covers materials used in the motor, protector, pump, and cable (Sensor, packer, Y-tool, diverter valve, surface components of variable speed drives and transformer not included). For each class of materials, it identifies relevant material properties and discusses suitable application conditions.
Roostaei, M. (University of Alberta) | Nouri, A. (University of Alberta) | Fattahpour, V. (University of Alberta) | Mahmoudi, M. (University of Alberta) | Izadi, M. (Louisiana State University) | Ghalambor, A. (Oil Center Research International) | Fermaniuk, B. (RGL Reservoir Management)
Standalone screen (SAS) design conventionally relies on particle size distribution (PSD) of the reservoir sands. The sand control systems generally use D-values, which are certain points on the PSD curve. The D-values are usually determined by a linear interpretation between adjacent measured points on the PSD curve. However, the linear interpretation could result in a significant error in the D-value estimation, particularly when measured PSD points are limited and the uniformity coefficient is high. Using the mathematical representation of the PSD is an efficient method to mitigate these errors. The aim of this paper is to assess the performance of different mathematical models to find the most suitable equation that can describe a given PSD.
The study collected a large databank of PSDs from published SPE papers and historical drilling reports. These data indicate significant variations in the PSD for different reservoirs and geographical areas. The literature review identified more than 30 mathematical equations that have been developed and used to represent the PSD curves. Different statistical comparators, namely, adjusted R-squared, Akaike's Information Criterion (AIC), Geometric Mean Error Ratio, and Adjusted Root Mean Square Error were used to evaluate the match between the measured PSD data with the calculated PSD from the formulae. The curve fit performance of the equations for the overall data set as well as PSD measurement techniques were studied. A particular attention was paid towards investigating the effect of fines content on the match quality for the calculated versus measured curves.
It was found that certain equations are better suited for the PSD database used in this investigation. In particular, Modified Logestic Growth, Fredlund, Sigmoid and Weibull models show the best performance for a larger number of cases (highest adjusted R-squared, lowest Sum of Squared of Errors predictions (SSE), and very low AIC). Some of the models show superior performance for limited number of PSDs. Additionally, the performance of PSD parameterized models is affected by soil texture: For higher fines content, the performance of equations tends to deteriorate. Moreover, it appears the PSD measurement techenique can influence the performance of the equations. Since the majority of the PSD resources used here did not mention their method of measurement, the effect of measurement technique could only be tested for a limited data, which indicates the measurement technique may impact the match quality.
Fitting of parameterized models to measured PSD curves, although well known in sedimentology and soil sciences, is a relatively unexplored area in petroleum applications. Mathematical representation of the PSD curve improves the accuracy of D-values determination, hence, the sand control design. This mathematical representation could result in a more scientific classification of the PSDs for sand control design and sand control testing purposes.
Meza, Oscar Grijalva (Joachim Oppelt Institute of Petroleum Engineering, Clausthal University of Technology) | Yaqoob, Tanveer (Joachim Oppelt Institute of Petroleum Engineering, Clausthal University of Technology) | Bello, Opeyemi (Joachim Oppelt Institute of Petroleum Engineering, Clausthal University of Technology) | Boulakhrif, Faissal (Joachim Oppelt Institute of Petroleum Engineering, Clausthal University of Technology) | Holzmann, Javier (Joachim Oppelt Institute of Petroleum Engineering, Clausthal University of Technology)
While drilling with casing stands instead of the classic drill pipe (CwD), the reduced standoff between wellbore wall and the rotating, sliding and bending tubular plays a critical role by "crushing and hammering" the formation cuttings into the formation. This plastering effect has demonstrated to be not only beneficial to hinder the losses of drilling mud into the formation but also to improve wellbore stability and later productivity in terms of lower skin values.
Field trials have established that monitoring of cutting sizes accumulated on the shakers and their correlation to the formation pore sizes (through offset match or well tests) can be an effective approach to improvise on the mud particle size for effective particle bridging and formation sealing. To enhance the mitigation of CwD-induced losses and formation damage, however, the horizon of investigation has to be broadened to include the size of radial clearance, rotating speed (RPM) and pump hydraulics. Assuming the cutting and mud smearing to be the result of point contact forces altering the near-wellbore stresses (confining stresses), the above parameters cause a repeated but unsynchronized invasion of particles in the initial micro fractures created due to bit interaction. Depending on the RPM, radial clearance and the resulting induced lateral drillstring movement, the magnitude of the contact force / hoop stresses increases within the original fracture-gradient limits. This improves formation sealability and results in an altered (enhanced) pore- and fracture gradient in the near-wellbore region.
The paper discusses the effect of Geo-mechanical and mechanical aspects of Plastering during Casing Drilling in Weak or depleted wellbores. The experimental analyses incorporates the combined effect of the point contact-forces through base drilling parameters, alongside highlighting the approach for field mud particle-size improvisation. Altogether, a broader panorama concerning the contribution of Casing Drilling to Well Integrity has been presented, setting the path to further experimental work.
Radhakrishnan, Venkataramanan (Bits & Drilling Tools Schlumberger) | Gonzalo, Hevia Garcia (Teratanatorn, Navalarp Coastal Energy) | Borge, Diego Barrero (Teratanatorn, Navalarp Coastal Energy) | Pickup, Duncan Ian (Bits & Drilling Tools) | Anggraini, Fauzia Dwi (D&M) | Kongoun, Chortip (D&M)
Directional Casing While Drilling (DCwD) with Steerable Motor or a Rotary Steerable System is an emerging technology with proven results in Casing While Drilling applications. DCWD has been successfully applied in wells in Asia, North Sea and Middle East using rotary steerable systems & PDMs, proving up its operational reliability. The technology has been implemented in Asia Pacific region as well overcoming several challenges. The project was successfully implemented in 2 back to back wells in Gulf of Thailand & being the first of its kind. Since the DCWD is first of its kind in Gulf of Thailand and to the operator, a proper planning and detailing the procedures along with risk assessment is the key to the success of the project. The procedure, in addition to directional capabilities requires that the well meet the demands of anti-collision concerns within the torque and hydraulic operating parameters of the formation.
Haghighi, M (The University of Adelaide) | O'Reilly, DI (Chevron Australia Pty Ltd, The University of Adelaide) | Hunt, AJ (Chevron Australia Pty Ltd) | Sze, ES (Chevron Australia Pty Ltd) | Hopcroft, BS (Chevron Australia Pty Ltd) | Goff, BH (Chevron Australia Pty Ltd)
This paper demonstrates how good technical evaluations and focused operational application can enhance the value of a mature asset. The Windalia reservoir underlies Barrow Island (BWI), situated 56 km from the coast of Western Australia, and has produced oil since 1965. Waterflooding commenced shortly after initial production, in 1967, and remains the main drive mechanism in the field today. Throughout the life of this onshore field, water injection and oil production have varied according to asset strategy and economic conditions. In this case study, we share how recent improvements made in the areas of Reservoir Surveillance and Operations activities have increased water injection efficiency and total oil recovery.
Through the use of new methods and workflows, the BWI Sub-Surface team was able to target specific areas of the field to distribute water to in order to increase injection and maximise oil production. For example, new workflows were built with the real-time PI monitoring system to analyse Pressure Fall Off (PFO) tests from each of the 147 waterflood patterns in detail. Capacitance-Resistance-Modeling was also leveraged to guide individual well target injection-rates. Operationally, several projects were also initiated to increase water injection into the right areas of the field.
The new Reservoir Management approach has significantly increased the volume of water being injected into the areas of need, supporting improved levels of oil production. For the first time in almost 10 years, the stream-day water injection rate has exceeded 90,000 bwipd. The results from PFO transient interpretation and pattern balancing proved effective in directing water to low-pressure, high-GOR areas of the field. They also provided valuable information about formation perm-thickness and skin. The phenomenon of water-cycling was also largely avoided, owing to close monitoring of production well tests and water injector transient surveys.
The present work addresses reservoir and operational aspects of Australia's largest active waterflood. The lessons shared are highly applicable to a low oil price environment, as they show how fit-for-purpose and low-cost acquisition of reservoir data can lead to improved field performance.
Muñoz, German (Saudi Aramco) | Dhafeeri, Bader (Saudi Aramco) | Saggaf, Hatem (Saudi Aramco) | Shaaban, Hossam (Schlumberger Oilfield Services) | Herrera, Delimar C. (Schlumberger Oilfield Services) | Osman, Ahmed (Schlumberger Oilfield Services) | Otaremwa, Locus (Schlumberger Oilfield Services)
To access the reservoir in a large Saudi Arabian development field, the operator is required to drill an intermediate 5,000 ft to 6,000 ft directional hole section with dogleg severity (DLS) varying from 2.5°/100 ft to 3°/100 ft. The commonly drilled 12¼-in. borehole crosses several interbedded formations comprised of limestone, shale and sands, and it is associated to a variety of hole problems, which present repeatedly in the offset wells. The main objective for the operator was to mitigate the problematic by defining alternative and suited drilling technologies. Among them, Saudi Aramco found that the recent developments in the directional casing while drilling (DCwD) technology may well provide an effective method for diminishing the associated nonproductive time (NPT).
The drilling engineering team conducted an extensive evaluation of the problems across this section, including wellbore stability, water flow, and loss of circulation; tight hole/stuck pipe incidents, severe bit/stabilizer wear while drilling abrasive sands. After a promising technical and engineering evaluation, followed by a detailed risk assessment aiming to determine the potential of the application, the selected well was planned and executed using the DCwD service.
This paper outlines the process carried out during all stages through the final deployment of the first 9?-in. DCwD application in Saudi Arabia, and how it successfully aided in achieving the goals by reducing the impact of some of the problems experienced while drilling the same section in previous wells in the field. Likewise, the information provided will serve as a starting point for the design and construction of subsequent wells leading to further improvement in drilling performance. Best practices and lessons learned from this implementation are expected to become a model and the know-how transferred to other areas where comparable drilling events occur.
The technological benefits have been recognized by the operator and this application reestablished DCwD as a viable technology to address a number of challenges common in many of the Saudi Arabian oil and gas fields.
Directional Casing while Drilling (DCwD) in Ecuador has been technically evaluated as a well construction technique to reduce or mitigate operational problems associate with: 1) constructing wells that could not be drilled efficiently using conventional techniques in partial and total lost circulation scenarios, through swelling shale or with hole instability issues, tight hole or stuck-pipe applications; 2) or to reduce total operational costs by eliminating casing runs, short/wiper trips and increase ROP.
At last count there have been over 200 worldwide directional casing drilling runs both onshore and offshore. These runs have been successfully executed in some of the most challenging drilling theaters making DCwD a viable and cost reducing alternative which helps operators solve the previously mentioned problems. To support the introduction of DCwD in Ecuador, rigorous engineering analysis has been performed which involves both the economic and technical aspects to help determine what kind of casing drilling system and BHA configuration is most suitable to ensure a successful run.
Modeling sofwares have been used to evaluate drilling dynamics and hydraulic requirements enabling engineers to select a drillstring that is capable of performing the specified job and obtain the required performance improvement with DCwD. The digital analysis helps to accurately predict if the application is suitable and determine which parameters could be applied to efficiently and safely execute the DCwD application.
There are some factors or parameters that can be taken as benchmarks when analyzing both static and dynamic simulation results. Torque determines if the rig has the capacity to drive the system. Fatigue and buckling analysis provide inferences into casing pipe selection and connection type. Realistic friction factors used during the simulations will avoid obtaining erroneous results which could lead to serious drawbacks. Scenarios like magnetic interference, presence of conglomerates or boulders could limit the tools' used for a specific application. The recommended BHAs will be supported by the specific regional analysis in addition to successes in other similar worldwide applications.
Once the engineering analysis has been completed, economics are then considered. The directional casing drilling service cost versus the amount of saving obtained by applying this technology has to be thoroughly evaluated. Savings will be couched as either time and/or money. Both have to be evaluated in the short and long term to determine which applications would benefit from DCwD and which environments should be avoided. The authors will explain how this analysis is performed to obtain an adequate feasibility study to meet the client's objectives. They will also discuss the key performance objectives that must be considered during each step of the analysis.
The drilling strategy of North Kuwait has embraced in the last few years to get more reservoir contact to maximize oil recovery. Presently, the wells are drilled with high deviation angle to intersect multiple pay zones and drain the existing prospects. However, water coning and edge water breakthrough are challenging to achieve production longevity. Inflow Control Devices (ICD) is a proved tool in oil industry, which can delay the water encroachment by creating uniform drawdown across wellbore section. The production performance of ICD wells indicated stability of water cut for longer period as designed.
Answer products is the key to monitor downhole production profile to ensure the functionality of ICD units. Some reservoirs are suffering from pressure depletion and artificial lift (ESP) was installed to deepest point to increase pump efficiency. This type of completions is limiting accessibility to collect downhole data for further action.
Besides, after period if the water shutoff is required, the well intervention inside ICD completion is challenging due to bore size limitation and materials availability.
Proactive action was taken to utilize the advanced technology of ICD Completion, which allows faster execution of Rigless shutoff and reduce Rigs demands.