Nafikova, Svetlana (Schlumberger) | Bugrayev, Amanmmamet (Schlumberger) | Taoutaou, Salim (Schlumberger) | Baygeldiyev, Gaygysyz (Schlumberger) | Akhmetzianov, Ilshat (Schlumberger) | Gurbanov, Guvanch (Schlumberger) | Eliwa, Ihab (Dragon Oil)
A major operator on the Caspian Turkmen shelf has started to encounter sustained casing pressures (SCP) attributable to insufficient isolation across a hydrocarbon gas zone, due to downhole stresses and other contributing factors. Enhanced placement techniques of conventional cements failed to prevent SCP, confirming the requirement for an alternative cement system that can withstand anticipated stresses and resolve this challenge. An innovative and cost-effective solution was applied and successfully solved the SCP challenge due to its unique self-healing properties.
If cracks or microannuli occur and hydrocarbons reach the cement, the system has the capability to repair itself, restoring integrity of the cement sheath without external intervention. The cement system is placed conventionally in the annulus across or above the hydrocarbon-bearing formation. It then acts as a pressure seal, expanding to accommodate downhole changes and healing if any hydrocarbon reaches it. This technology has been used in four wells in the field with excellent results.
Two wells were used to demonstrate the capabilities of the self-healing cement as a lead cement slurry, which created a cap over the pay zones. The self-healing cement was designed with low Young's modulus for optimum flexibility. To minimize the risk of set cement integrity failure due to microannuli or microdebonding from chemical shrinkage after setting, linear expansion up to 1.2% was incorporated into the design. After cementing, the wells were intentionally exposed to a sequence of high-pressure tests, which induced annular pressures in the wells. However, because of the self-repair capability of this cement, isolation and integrity were effectively restored in the two wells within 1 to 2 weeks without external intervention. As a result, the self-healing cement technology has become the standard for the field for all future wells, and the operator plans to extend the self-healing cement technology to other fields with similar challenges.
This paper clearly demonstrates successful casing pressure remediation without intervention by engineering a flexible, self-healing cement system. The design strategy, execution, evaluation, and results for two wells are discussed in detail and will help to guide future engineering and operations around the world.
Al-Maqtari, Ameen N. (SAFER E&D Operations Company) | Saleh, Ahmed A. (SAFER E&D Operations Company) | Al-Haygana, Adel (SAFER E&D Operations Company) | Al-Adashi, Jaber (SAFER E&D Operations Company) | Alogily, Abdulkhalek (SAFER E&D Operations Company) | Warren, Cassandra (Schlumberger) | Mavridou, Evangelia (Schlumberger) | Schoellkopf, Noelle (Schlumberger) | Sheyh Husein, Sami (Schlumberger) | Ahmad, Ammar (Schlumberger) | Baig, Zeeshan (Schlumberger) | Teumahji, Nimuno Achu (Schlumberger) | Thiakalingam, Surenthar (Schlumberger) | Khan, Waqar (Schlumberger) | Masurek, Nicole (Schlumberger) | Andres Sanchez Torres, Carlos (Schlumberger)
A 3D petroleum systems model (PSM) of Block 18 in the Sab'atayn basin, onshore western Yemen, was constructed to evaluate the untapped oil and gas potential of the Upper Jurassic Madbi formation. 3D PSM techniques were used to analyze petroleum generation for conventional reservoirs and the petroleum saturations retained in the source rock for the unconventional system. Block 18 has several proven petroleum systems and producing oil and gas fields. The principal source rocks are within the Madbi Formation, which comprises two units, the Lam and the Meem members. Both contain transgressive organically rich "hot" shales with total organic carbon (TOC) of 8 to 10%; these are located stratigraphically at the base of each member. Additional organic-rich intervals within the Lam and Meem are less-effective source rocks, with lower TOC values.
The PSM consisted of 17 depositional events and 2 hiatuses. To accurately replicate geochemical and stratigraphic variations, the Lam and Meem members were further divided into sublayers. The model was calibrated to present-day porosity, permeability, and pressure data, and it incorporated vertical and lateral lithofacies and organic facies variations. Further calibrations used observed maturities (vitrinite reflectance and pyrolysis Tmax) and present-day temperatures and considered laterally variable heat flow from the Early Jurassic to the Late Miocene. Finally, petrophysical analyses from wells provided calculated hydrocarbon saturations, which were used to calibrate the saturation output from the model. The model satisfactorily reproduces the distribution of the main gas and oil fields and discoveries in the study area and is aligned with well test data.
Maturity results indicate that the upper Lam intervals currently sit within the main to early oil window but are immature at the edges of Block 18 (based on the Sweeney and Burnham Easy R0% kinetics). The lowest Lam unit enters the wet gas window in the center of the block. The underlying Meem member ranges from wet gas to early oil window maturity. Like the Lam, the Meem remains immature along the edges of Block 18. However, in the south of the block, the richest source rocks within the Meem are mainly in the oil window. The degree of transformation of the Meem and Lam varies throughout the members. The model predicts that, at present, the lowest part of the Meem, containing the greatest TOC, has 90% of its kerogen transformed into hydrocarbons.
The model confirms that the Madbi formation is a promising unconventional shale reservoir with a high quantity of hydrocarbons retained within it. Despite the higher quantity of hydrocarbons retained in the upper Meem, in terms of liquid and vapor hydrocarbons predicted in this model, the lower Lam is the most-prospective conventional tight sand reservoir, and the Meem has very small potential as tight sand reservoirs. This study provided a novel application of 3D PSM technology to assess new unconventional as well as conventional plays in this frontier area.
The complete paper describes a work flow in which wells and production networks in the Cheleken Block offshore Turkmenistan are automatically modeled daily with steady-state and transient tools and ultimately analyzed by the Cheleken Block Central Data Gathering System. The Caspian Sea region is once again becoming one of the globe’s important frontiers in oil and gas production. Azerbaijan, Kazakhstan, and Turkmenistan are in the midst of intensive efforts to underpin their developing economies by increased exploitation of massive reserves.
Methane monitoring using improved methods is detecting more gas in the atmosphere, increasing the need for better ways to eliminate releases. The complete paper describes a work flow in which wells and production networks in the Cheleken Block offshore Turkmenistan are automatically modeled daily with steady-state and transient tools and ultimately analyzed by the Cheleken Block Central Data Gathering System. One tech company is using a unique approach to building custom apps for the oil and gas business. The Southwest Partnership on Carbon Sequestration (SWP) is one of seven large-scale demonstration projects sponsored by the US Department of Energy. Newly developed ambient seismic imaging methods provide valuable information throughout the life cycle of an unconventional field.
The large independent put together a team of data scientists, software developers, and petrotechnical staff to create a forward-looking vision for how to use digital technology to solve problems. Baker Hughes is still a GE company, but it has partnered with a second company for artificial intelligence expertise, C3.ai. The deal is expected to speed the integration of AI into oilfield operations by the company which also markets GE’s device analytics platform, Predix. Marathon Oil says its shale fields are producing more oil and gas with less hands-on work from company personnel thanks to a growing arsenal of digital technologies and workflows. Malaysia’s Petronas, Shell Malaysia, and Thailand’s PTTEP are now in the midst of full-scale digital adoption.
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.
Replacing all analogue sensors in the oil field is very costly and normally only a fraction of them is done. Currently, there is no cost-effective method to efficiently, reliably and accurately capture analogue meter readings in a digital format. Operators are then left with only two options: either replace them with digital (high capex) or continue with manual gathering (high opex). This paper shows how computer vision and artificial intelligence was used for the first time to capture analogue field gauges data with dramatic reduction of cost and increase reliability.
This unique solution was implemented in the Cheleken Oil field, Caspian Sea, Turkmenistan. In the offshore platforms, only low-cost cameras were necessary, and gauges were identified using QR codes. During the field trial, operators were only required to take pictures of the gauges at a given interval of time and upload the photos to the application. After an innovative process of calibration, the acquired images were processed using artificial intelligence and deep learning computer vision.
Routine manually gathered data was compared with data collected using this solution with the following observations made: Date/time: Operators usually round time. The solution described records time on the captured pictures automatically. Value: Manually gathered data is subject to reading, typing and transcription errors. This solution has no error (provided a good calibration is done). Data Modification: Data gathered automatically with this solution has no human intervention. Therefore, is not subject to alteration, copying or duplication. Data collection with pictures was completed in 1/10th of the time that manual processes take. The business benefits from quicker operator rounds with improved accuracy in meter reading data, and time stamps. The administrative burden for operators of filling in extensive spreadsheets which are prone to error was reduced, this allowed them to collect more meter readings or be reassigned by management to more important scopes of work that bring greater value to the business. Once more it was proved that "a picture is worth a thousand words ".
Date/time: Operators usually round time. The solution described records time on the captured pictures automatically.
Value: Manually gathered data is subject to reading, typing and transcription errors. This solution has no error (provided a good calibration is done).
Data Modification: Data gathered automatically with this solution has no human intervention. Therefore, is not subject to alteration, copying or duplication.
Data collection with pictures was completed in 1/10th of the time that manual processes take.
The business benefits from quicker operator rounds with improved accuracy in meter reading data, and time stamps. The administrative burden for operators of filling in extensive spreadsheets which are prone to error was reduced, this allowed them to collect more meter readings or be reassigned by management to more important scopes of work that bring greater value to the business. Once more it was proved that "a picture is worth a thousand words ".
This solution offers an excellent opportunity for digitizing the marginal section of the field and provides a unique way to turn all analogue data into digital with a very low cost of implementation, on an infinitely scalable platform that is vendor agnostic and simple to manage.
Dragon Oil operates the Cheleken field in the Caspian Sea offshore Turkmenistan. The production system consists of multiple wellhead and manifold platforms, a complex network of infield carbon steel and flexible flowlines to handle production from HP and LP systems and a 30" 40 km TL to transport the produced fluids to the CPSF (Central Processing and Storage Facility) located onshore. In addition to the complexities of the flowlines network, the development has a number of unique features that pose challenges to the daily production operation activities such as: - Relatively low reservoir temperatures; - Waxy oil with high WAT (Wax Appearance Temperature) and Pour Point; - Complicated bathymetry of the 30" TL (Trunkline); - Complex reservoirs leading to uncertainty in rates; - Increasing water production; - Increasing sand ingress; - Necessity to commingle water from different sources in the flowlines; - Corrosion, erosion and emulsion occurrence; While management of any of the Flow Assurance issues is well understood on stand-alone basis; there is no definite guidelines to manage them simultaneously through understanding their impact on each other. Obtaining flawless understanding of the nature and extent of each of the impediments issues was a key element for Dragon Oil's team to innovate this approach to minimizing the overall negative impact on production operations. The approach has been developed based on balancing the hydrophobic, hydrophilic and molecular properties of the produced fluids in correlation with the physical criteria of each of the issues to minimize the impact on the others. This paper presents the key elements of a novel approach developed to control the impact of some issues and maintain the deliverability and integrity of the 30" TL. The approach consisted of the following activities: 1. Conducted thorough and rigorous fluids' analyses; 2 SPE-194768-MS