Africa (Sub-Sahara) Kosmos Energy has made a significant deepwater gas discovery off Senegal. The Guembeul-1 well in the northern part of the St. Louis Offshore Profond license in 8,858 ft of water encountered 331 net ft of gas pay in two excellent-quality reservoirs, the company reported. The results demonstrate reservoir continuity and static pressure communication with the Tortue-1 well, which suggests a single gas accumulation. The mean gross resource estimate for the Greater Tortue complex has risen to 17 Tcf from 14 Tcf as a result of the Guembeul discovery, the company said. Kosmos, the operator, has a 60% interest in the well. Timis (30%) and Petrosen (10%) hold the remaining interest. In Salah Gas has started production from its Southern fields in Algeria.
Africa (Sub-Sahara) Petroceltic International said that the first of up to 24 new development wells planned in Algeria's Ain Tsila gas and condensate field was successful. The AT-10 well, situated about 2 miles from the AT-1 field discovery well, reached a total depth of 6,578 ft. Wireline logs indicated that the expected initial offtake rate would be comparable to the AT-1 and AT-8 wells, both of which test-flowed at more than 30 MMcf/D. Petroceltic is the operator with a 38.25% interest in the production-sharing contract that covers the Ain Tsila output. The remaining interests are held by Sonatrach (43.375%) and Enel (18.375%). Sonangol reported that it has found reserves in the Kwanza Basin of Angola that could total 2.2 billion BOE, including reserves in a block jointly owned with BP. Block 24, operated by BP, holds an estimated 280 million bbl of condensate and 8 Tcf of gas, totaling 1.7 billion BOE, Sonangol said in a statement seen by Reuters.
Africa (Sub-Sahara) Sound Energy identified significant gas shows at the first Tendrara well onshore Morocco. Drilled to a 2665-m measured vertical depth, the well hit a total gross pay interval of 89 m of gas. The full set of well logs are being processed before the startup of rigless mechanical reservoir stimulation operations, which will be followed by a well test. The company is the operator of the well with a 55% working interest.
Digital transformation is a process of applying all digital technologies and tools on current workflows to be able to deliver high quality information at the right time. The digital transformation of drilling will provide an unprecedented stream of high-quality information that has never been accomplished in the industry, through the utilization of automated real-time drilling downhole tools, data analytics and predictive analysis. Thus, it creates value, improves efficiency, further reduces costs and boosts performance significantly.
Despite the advantages of digital transformation, the oil and gas industry (especially drilling contractors) has been slow to seize the opportunity. There are many challenges that need to be overcome to realize its full potential for the drilling contractors. A coherent road map to build a successful digital transformation strategy will be addressed in this paper. (that is not only focused on assets, but also focused on how to create new revenue streams.)
A setup of a real-time digitalization tool based on automated rig activities detection technology is established in a national drilling contractor in Algeria and a measurement and monitoring process was started. Data aggregation is the first step towards implementing a digital transformation process.
However, the main task was standardizing and aggregating cross-vendor data streams. Breaking the data silos was required to move data smoothly from rig site to our digital records for a fast setup
Another issue is quality of data. Constant quality control checks of the received data ensured that the maximum value can be accomplished, which will consequently support in improving the awareness and decision process for the contractor based on this detailed information and following systematic procedures.
Also, company culture is extremely important to fostering the successful execution of a digital strategy. An approach of sharing relevant information between all members of the drilling crews on daily basis and using what is so-called "Hawthorne Effect", defines a continuous improvement process.
The digitalisation of drilling process has the ability to sustain a constant flow of information with the potential to transform operations and create additional profits from existing capacity. Clearing the bottlenecks in the data integration and analysis stages was vital for a successful digital transformation process.
This process enables real time reporting of drilling performance. This empowers the contractor to track the improvement and efficiency over time and find a performance gap to establish a feedback link to correct the deviations. The second benefit of applying such process is to by doing increase the utilization of the existing equipment and evaluating the best performance that crews can achieve with such equipment.
The eventual goal is establishing and improving the global process and workflow of monitoring the operating units for the multi-level operating team structure, by the means of high speed, digital data technologies over considerable slower human factors. In this paper, we will demonstrate all the tools and framework that have been utilized to achieve this goal.
Drilling waste generated during the drilling of wells using oil-based muds (OBMs) can often contain a high level of oily waste liquid as a result of surface mud losses, fluid displacements, rig wash down activities, and rig tank cleaning. This type of waste commonly known as "drilling slops" represents a significant volume of the overall waste generated while drilling a well and contributes to the overall environmental impact, cost of waste haul, and final disposal. In addition, the use of emulsifiers and other chemicals in OBMs leads to these liquids becoming difficult and expensive to treat efficiently with conventional separation and treatment systems.
This paper sets out a new method for treatment and recycling of this type of waste for land drilling operations that achieved a 73% reduction in waste volumes generated compared to other wells drilled in the same area. The results in the paper will also demonstrate that the oil and water recovered by this system was within the recommended quality parameters for recycling in the drilling operation. This system significantly reduces the need to transport wastes for offsite treatment and disposal while reducing the overall environmental impact of the drilling operation.
After analyzing the source of wastes generated during drilling at a land location in Algeria, a methodology was devised to segregate drilling wastes and avoid the co-mingling of different waste types before sending the drilling slops to the system for treatment. Lab tests were carried out to determine the optimum flocculants and dosing rates required to separate and recover the oil and water from the solids. This new method for treating and recycling these waste is an integrated chemical flocculation and dewatering system using a container fabricated from a specially engineered textile that provides confinement and drying of drill solids inside the container while allowing the liquids to permeate through the engineered textile for recycling and reuse on the rig. This system reduces the amount of liquid wastes hauled off site for treatment leaving dried solids that are easily handled and disposed of with conventional treatment methods.
The use of this technology can have an important and cost effective contribution to reducing the environmental impact of land drilling operations using OBMs in Algeria and beyond.
Hassi Messaoud (HMD) is a mature oil field with approximately 1100 production wells. About half of the wells are natural flow and the other half are continuously gas lifted (CGL) with concentric (CCE) strings. CCE gas lift is different from conventional gas lift as the lift gas is injected in the well through the CCE string while production is from the annulus between the CCE string and the tubing. The typical production tubing size is 4 ½". The sizes of the CCE strings include 1.315", 1.66", and 1.9". The 1.66" CCE is most commonly used in gas lift wells. The typical gas lift injection line on the surface is 2" from the gas network to the wellhead. A choke is used on the gas lift line to control the lift gas injected into each well. As the injection gas pressure is high from the source of available lift gas, large pressure drops across the lift gas injection chokes exist in some wells. Due to the Joule-Thompson effects, a big temperature drop is associated with the large pressure drop across the lift gas injection choke. This temperature drop can result in hydrate formation in the lift gas line downstream of the gas lift choke. Hydrate formation in the gas injection lines, especially in winter has seriously disrupted production due to plugging of lift gas lines.
Salt deposition is a big challenge in Hassi Messaoud field operation. The reservoir interstitial water contains high salt concentration in excess of 300 g/l. During well production, salt deposits in the wellbore and across the production choke. Periodically, water is required to be injected into the well to dissolve the salt and restore well productivity. A CCE string allows water to be injected into the wellbore either concurrently with injection lift gas or separately by itself for a specific period of time.
High volumes of lift gas are injected in many wells due to the lack of effective control in the lift gas injection rates. The excessive gas from lift gas injection and production in the system can lead to the need to flare occasionally when the facility gas capacity limit is exceeded.
In order to reduce the usage of the high volume of lift gas, Intermittent Gas Lift (IGL) was selected in a pilot project to evaluate its applicability in the Hassi Messaoud field.
Three CGL wells were selected for this pilot project. The selected wells are characterized by high GOR, low PI and without continuous concurrent water injection (with lift gas) to dissolve salt deposited down-hole.
IGL operation parameters were designed by using modified empirical correlations to those presented in the API Recommended Practice for Intermittent Gas Lift. The modifications were suited for the operating conditions in Hassi Messaoud Field. Static and dynamic well and network models were created to simulate the field test results and guide new designs and future applications.
This paper presents the pilot test programs and the results from this project in mitigating both the excessive lift gas injection problem and injection line blockage due to hydrate by converting certain CGL wells to IGL. It also highlights the application conditions for the future. Finally, the plan for the expanded application of IGL in Hassi Messaoud is discussed.
An experience of electrical-submersible-pump (ESP) -issues troubleshooting to overcome the high-corrosion media of GSA wells is presented. Additionally, actions taken to extend the run life of pumps are explained. GSA is the company in Algeria that adopted the ESP system including all services; therefore, there was no chance to share experience with other entities in the country. Thus, it became necessary to try all available approaches during a period of 10 years to mitigate ESP failures and, eventually, production downtime.
To overcome the high salinity of >320 g/L, several actions were introduced by either of two ways--ESP equipment or well completion. Simple motors and protectors were changed to tandem to prevent water penetration inside the motor. Power cable was changed from galvanized to Monel armor for high resistance to corrosion. For well completion, single or double 1/2-in. water-dilution lines were adopted and were run along tubing and connected to tail pipe, which runs to perforations. Modification in completion metallurgy also took place, when carbon steel was replaced by Super 13Cr. Supplementary actions were taken at the surface; the pressure switch was connected with a variable-speed drive (VSD) to smoothly shut down the ESP for unforeseen surface-controlled subsurface-safety-valve (SCSSV) closures.
The adopted actions yielded considerable positive results. ESP failures that originated from the motor were reduced from four per year during 2012 to only one failure in 2016. However, salt-deposition blocs were almost prevented, and resulted in decrement in bullheading and coiled-tubing interventions by 85%, except for some wells when salt-bloc buildup was occasionally quicker and more important than water-dilution rate. Running a 1/2-in. injection line along with the tail pipe lowered ESP-shutdown frequency. Also, changing the power-cable type gave roughly good results. After running Monel armor, the number of related power-cable failures decreased, contributing to the reduction of whole failures, because related power-cable failure represented 70% of ESP failures in 2015. Considering Super 13Cr instead of carbon-steel tubing gave positive indications, and reduced sharply related tubing-integrity failure. The problem still exists, however, with very low frequency. For surface equipment, all unforeseen SCSSV closures actuated from the control panel are always accompanied by a gradual decrement of frequency and, consequently, smoother ESP shutdown.
Because our organization is the company that uses ESP with a proper sense in Algeria, this paper presents some best practices to be considered for other companies and ESP contractors that are based in the country or abroad that intend to install an ESP system in very high-salinity and corrosive fields and to adopt a lease model for downhole equipment.
Hebib, R. (University of Science and Technology Houari Boumediene) | Hebbadj, A. (DESSAU Groupe Inc) | Haouchine, T. (Algiers Metro Company) | Meziane, N. (Algiers Metro Company) | Alloul, B. (University of Science and Technology Houari Boumediene) | Belhai, D. (University of Science and Technology Houari Boumediene)
The aim of this work is to relate the experience that is a sheet of trial plot, performed prior to actual works. In addition, this work presents the (teachings of works), through the analysis and interpretation of results. These results confirmed some doubts reported before (the starting the trial plot). Indeed, this plot allowed an optimization of the grouting project adopting the traditional grouting method that has proven the most effective technique (compared to the methods in the original project): On the one hand, the analysis of the real evolution of injections and the evolution of penetrability showed weak grout absorptions. On the other hand, the geo-mechanical behaviour of the injected rock showed no instability or breakdown of the rock. 1 1 INTRODUCTION The ground improvement work, through grouting is increasingly performed in underground works. The adoption of this type of treatment comes down to its various applications, but also to its adaptation to all the situations that may be encountered before, during and even after the excavation works. The flexibility in the application of grouting work is still faced with difficulties to master the injection project, which depends on several factors, including those related to the type of ground, the injection parameters, and means of implementation.
The percussion performance drilling motor was proposed in combination with polycrystalline diamond cutter (PDC) drill bits to overcome the drilling challenges of the 12 ¼ in. vertical section in Ahnet field (South-West of Algeria), consisting of harsh lithology types habitually drilled using several bits run.
Introducing the percussion drilling motor is the next step for performance optimization in harsh drilling environments. Utilizing the advanced generation of performance elastomers in combination with new energy distribution system enhances the drill bit's rock failing mechanism by combining the torque and rotation speed with a high frequency axial oscillation. This lifts the entire BHA with each pulse while maintaining the drill bit always fully embedded into the formation, resulting in an increased penetration rate. This paper presents a case study that evidences the benefit of using such a tool to reduce the drilling cost.
The 12 ¼ in. section in the subject field is usually drilled using 6-10 drill bits with the associated excessive non-productive time (NPT) and increased drilling costs for the operator. Extreme dull characteristics are also exhibited by all drill bits after every run. The introduction of the percussion drilling motor in this section represents a step change in performance and drilling efficiency to reduce drilling time. In combination with optimized PDC drill bits, the percussion drilling motor completed the interval with just 2 bits compared to offsets using 10, 8, and 6 bits, respectively. In conclusion, this approach crucially contributed to save 7.72 drilling days to the client compared to the initial plan. Moreover, an increase of 119% was recorded in term of ROP compared to the best offset well and a very good hole quality with only 0.7% excess recorded on the caliper log.
The innovation of the percussion performance drilling motor is a completely new telescopic bearing mandrel design to keep the drill bit always in contact with the formation while gently oscillating the upper BHA reducing friction, improving weight transfer, and improving bit cutting structure efficiency enhancing its rock-failing properties.
Azari, Mehdi (Halliburton) | Hadibeik, Hamid (Halliburton) | Ramakrishna, Sandeep (Halliburton) | Bakiri, Kamal (Sonatrach) | Imouloudene, Abdellaziz (Sonatrach) | Ghalambor, Ali (Oil Center Research International)
This paper discusses the causes of performance failure of a well in the Hassi Messaoud field in Algeria that was fracture stimulated but did not achieve the expected production increase, and it discusses alternative methods to increase well production by integrating geology and petrophysics with production and well-test data.
The well was perforated in sand B and in the upper section of sand C. It was initially tested at 5.07 m3/h (765 B/D), but within three months, production declined to 1.99 m3/h (300 B/D). Early studies suggested that the rapid decline was probably caused by near-wellbore formation damage during drilling. A fracturing program was designed to help remove well damage and restore flow capacity; however, negligible production increase was observed following the hydraulic fracturing. Initially, damage on the fracture face and uncleaned fracturing fluid were the suspected causes of the ineffective fracture stimulation. A new pressure-buildup test was performed to assess the effectiveness of the fracture stimulation, and detailed analyses indicated that the small reservoir size might have been the cause of the rapid pressure decline.
The fracturing design was based on pressure data from the initial drillstem test (DST) at 388.9 kg/cm2 (5,531 psi). A post-fracture pressure-buildup test revealed that reservoir pressure had declined to 233.2 kg/cm2 (3,317 psi) after only producing 6901 m3 (43,406 bbl). The pressure-buildup analysis detected a fourth boundary that was not mapped during the original three-dimensional (3D) seismic survey. This fault reduced the well drainage area by a factor of four and was the cause of the rapid pressure decline during production. A recent seismic survey refined the geological map of the entire reservoir and confirmed the presence of this fault.
Petrophysical analysis of sand C showed higher-quality rock than sand B; however, the resistivity decreased with increasing sand C depth, suggesting the presence of water. Lithology analysis confirmed that the decrease in resistivity was resulted from higher clay content and clay-bound water. Offset wells also confirmed that the oil-water contact (OWC) was approximately 70 m (229.7 ft) below the bottom of this well. Well productivity could have been significantly higher if the entire sand B pay was initially completed. To compensate for low-formation pressure, a gas-lift optimization procedure was performed to lift the fluid to surface with an initial production of 2.14 m3/h (323 STB/D). After two years, the reservoir pressure in this bounded section declined to 169 kg/cm2 (2,404 psi).
This paper discusses an integrated approach to increase oil production from a well penetrating a geologically challenging environment. Integration of geology, petrophysics, seismic, production modeling, and gas lift with proper data acquisition helped prevent abandonment of this well, leaving behind potential reserves. This paper also discusses a case study in which a false-formation damage diagnosis could have led to reservoir mismanagement.