Unconventional oil and gas reservoirs are being explored significantly around the globe nowadays. The economical production of hydrocarbons from these unconventional oil and gas reservoirs like CBM requires very advanced and cost effective technologies. Hydraulic fracturing is such a technology which is being used in the oil and gas industry for many decades to create highly conductive channels in the formations having very low permeability values. Multistage hydraulic fracturing has been proved to be a great achievement in oil and gas industry to enhance the production from unconventional reservoirs. An effective hydraulic fracturing planning & execution is a key to achieve the expected results in terms of production from unconventional reservoirs such as tight gas, shale gas, coal bed methane or other very low permeability reservoirs.
Unconventional reservoirs such as Shale & CBM require large scale hydraulic fracturing operations, where multiple frac fleets, wire-line units, coiled tubing units; work-over rigs & ancillary services are mobilized. A scheduling software based project management approach was followed at CBM Raniganj for planning & modeling of operations. This paper aims to study how the operational resource deployed in Raniganj field for hydraulic fracturing was optimized in terms of time, cost & load for fracturing operations.
The approach of modeling & planning the hydraulic fracturing operations is based on project management & scheduling software. Assumptions were finalized based on experience. The loopholes, possible schedule slippages and other deterrents which could cause a lag in the hydro fracturing campaign aimed to pump over 1,600 frac jobs in CBM Raniganj field, over a period of 30 rig months, were identified clearly. The scope, time, budget & quality standards were clearly defined and a schedule was prepared with the help of the scheduling software to run the fleets in a clockwork manner. Activities like perforation, Acidizing, data fracturing, main fracturing, flowback, sand plug and finally sand cleanout were defined as series & simultaneous operation.
This paper will describe a methodology which has been developed as an alternative to four-dimensional (4D) Seismic. The main objective is to track heat conformance over time in the thermally developed "A" Field, Sultanate of Oman. The method has several significant advantages over 4D Seismic, including: Negligible cost and manpower requirements; Provision of close to real-time information and no processing time requirements; No Health, Safety or Environmental exposure, or disruption to ongoing operations.
Negligible cost and manpower requirements;
Provision of close to real-time information and no processing time requirements;
No Health, Safety or Environmental exposure, or disruption to ongoing operations.
The paper will also demonstrate the power of integrating wide-ranging data sources for effective well and reservoir management.
The increasingly close well spacing at "A" Field has made Seismic Acquisition progressively more challenging. Conversely, it has created an opportunity to utilize dynamic Tubing-Head Temperatures (THTs) for tracking areal thermal conformance over time. For each month in turn an automated workflow:- Grids the monthly THT averages; Integrates the production and injection data, represented as bubble plot overlays; Adds the top reservoir structure from the subsurface model, highlighting structural dip, and fault locations.
Grids the monthly THT averages;
Integrates the production and injection data, represented as bubble plot overlays;
Adds the top reservoir structure from the subsurface model, highlighting structural dip, and fault locations.
Morphing (movie) software then interpolates the monthly images to create a smoothly transitioning "Heat Movie".
The Heat Movie demonstrates the general effectiveness of the Development in terms of warming the reservoir over time. This in turn is reducing the oil viscosity and increasing production. However, it also highlights temperature anomalies that can be linked to geological features such as faults and high permeability layers. Identification of these anomalies may underpin decisions to optimise the thermal development.
In addition to the Movie, time-lapse images can be created for any chosen period. This is similar to 4D Seismic, but more powerful, since the period can be directly linked to significant field milestones, for example equal time periods before and after upgrading the steam generation process.
Proof of Concept was demonstrated in early 2018, and the technique has already been deemed sufficiently mature to utilize it for tracking and managing Thermal Conformance in place of 4D Seismic. This is resulting in annual cost savings of millions of dollars and man-years of staff time.
One potential advantage of 4D Seismic is highlighting vertical conformance. Although this is not possible using THTs alone, at "A" Field the plan is to mitigate this by integrating data from ongoing Distributed Temperature Sensing (DTS) and well temperature surveys.
Regarding applicability, the workflow can be adapted for other objectives, for example creating a movie of surface uplift and/or subsidence integrated with bubble plots of production and injection data, or water breakthrough for wells with downhole gauges, in water flood developments.
In addition to describing the methodology underpinning this innovative approach, this paper will also discuss the vision for further improving the workflow and expanding the functionality.
Thermal recovery is becoming a main stream enhanced recovery method for heavy oil with unique challenges. The extreme nature of thermal recovery requires flexible and creative approach to address the unique challenges. One of the accepted recovery thermal methods is Cyclic Steam Stimulation (CSS). The thermal cycle starts with injection phase followed by soaking, and finally, production phase. Conversion from injection phase to production phase is considered a significant operational risk in addition to typical risks associated with oil production operations. The additional risk during the conversion to production from an injection cycle is due to the significant energy placement in the reservoir during steaming. If not controlled, high energy hydrocarbon fluids flowing back to surface can lead to loss of containment and harm to life or the environment.
Beam Pumps have been used predominantly in conjunction with insert down-hole pump and sucker rods. During injection phase, the well is operated as an injector without pumps or rods, and when the time comes to convert to a producer, rods and insert pumps are reinstalled. This conversion step from injector to producer is highest risk in the CSS well operation cycle.
After the injection cycle is completed, a significant energy is placed into the reservoir, the well is shut in for soaking period which is 1-3 days. Free flow is required after the shut in period to depressurize the well. Depressurization period extends in some cases to many weeks and would require killing the well where it's common that a well would not die off just by depressurization alone resulting in significant wait time. The amount of flow back and energy stored in the well is directly proportional to steam injection pressure and duration.
In many cases where well still retain some energy and pressure is still high for intervention, due to free flowing not subsiding, killing the well is utilized. Well killing procedures pose another set of challenges such as; pump start up challenges due to viscosity reduction, cost for brine mix and wrong pressure estimation leading to prolong interventions.
The challenges in CSS opened an opportunity for innovation where thermal wells could be attended for conversion with minimum rods taken out or rods added back in under high temperature and pressure. The new concept is a combination of dual rod Blow Out Preventer (BOP) and stripper seals set in series. A trial in November 2017 was conducted with positive results where the advantages of this innovation were clearly demonstrated. This paper is a summary of the design approach and the successful trial proving the concept.
Shaqsi, Khadija Al (Petroleum Development Oman LLC) | Alwazeer, Abdullah (Petroleum Development Oman LLC) | Belghache, Abdesslam (Petroleum Development Oman LLC) | Mawali, Shaikha Al (Petroleum Development Oman LLC) | Sawafi, Marwan Al (Petroleum Development Oman LLC) | Aulaqi, Talal Al (Petroleum Development Oman LLC) | Bulushi, Badriya Al (Petroleum Development Oman LLC) | D'Amours, Kevin (Petroleum Development Oman LLC) | Yahyai, Ahmed Al (Petroleum Development Oman LLC) | Yazidi, Rashid Al (Petroleum Development Oman LLC) | Hilali, Ali Al (Petroleum Development Oman LLC) | Zaabi, Yousuf Al (Petroleum Development Oman LLC) | Hinai, Jaifar Al (Petroleum Development Oman LLC) | Mujaini, Rahima Al (Petroleum Development Oman LLC) | Gheithy, Ali Al (Petroleum Development Oman LLC) | Bettembourg, Solenn (Shell Kuwait LLC)
This paper describes how the deployment of multiple Lean projects by Petroleum Development Oman's Thermal Well and Reservoir Management (WRM) team has resulted in significant cost savings, in terms of efficiency and oil production.
WRM teams are an integrated group within production assets, comprising of petroleum, process engineers, operations staff and well services. Supported by data acquisition and interpretation, the teams are responsible for operating and optimizing the field.
Historically, Petroleum Development Oman's Thermal WRM team faced some challenges such as data access and activity processing including pattern reviews, Cyclic Steam Stimulation (CSS) planning, business planning and operational routine activities such as fluid levels. In addition, key surveillance activities suffered from delays and data interpretation inaccuracy. The above resulted in significant time inefficiencies and deferred oil production.
The continuous improvement initiatives started in 2015 with a particular focus on improving thermal WRM process. A deployment plan was created starting with identifying the need and clarifying the required steps to earn the Lean status as defined in PDO. Lean Management System (LMS) was defined followed by awareness sessions. These initiatives resulted in the identification of many opportunities for continuous improvement and Lean initiatives.
Multiple improvement areas were identified against a set of measured baseline conditions. The following projects were selected for Lean: Integration pattern reviews improvements. CSS optimization by monitoring key reservoir management indicators. Reduction well intervention cycle time in CSS. Exception based automation of reservoir surveillance tools. Visualization of CSS workflow and efficiency enhancement. Production forecast automation. Automation fluid level above pump for well optimization.
Integration pattern reviews improvements.
CSS optimization by monitoring key reservoir management indicators.
Reduction well intervention cycle time in CSS.
Exception based automation of reservoir surveillance tools.
Visualization of CSS workflow and efficiency enhancement.
Production forecast automation.
Automation fluid level above pump for well optimization.
Four of the above projects were successfully completed in 2016 and 2017, with the remaining were completed in 2018. Below are highlights of implementing Lean projects in PDO: Estimated 70% manpower time saving. Approximated 5% incremental oil gain. Anticipated 42% reduction in unscheduled deferment. Confirmed 80% waste reduction in overall forecasting, CSS workflow and steam flood monitoring process. Eliminated the need for manual fluid level shots, reduced HSE exposure due to travel.
Estimated 70% manpower time saving.
Approximated 5% incremental oil gain.
Anticipated 42% reduction in unscheduled deferment.
Confirmed 80% waste reduction in overall forecasting, CSS workflow and steam flood monitoring process.
Eliminated the need for manual fluid level shots, reduced HSE exposure due to travel.
Improved tracking of CSS activities reduced operational errors. A thermal economic dashboard was also introduced to rapidly identify sunk costs, minimize Unit Technical Cost and improve Cash Flow.
Dropping of oil price has significant influence in Oil & Gas industry in term of cost saving. A lot of efforts and initiatives were made in order to sustain with the current situation and to facilitate the Oil and Gas industry to lead the market. Existing of alternative energy is another challenge which threats the market. ILT initiative was introduced in the Drilling Function to Drill Wells in more efficiency and high performance considering the priority for safety and integrity. The main objective of ILT is to identify the area's of invisible lost time, track it and to Eliminate As Low As Possible (ALAP) and to Drill Well in Shortest Time compare it with Best Of Best Wells (BOB) During the period when the oil price was high, a lot of expansion in terms of rigs and manpower were there, where there are no focus in the performance of the wells which lead to big inflation in well duration resulted by Non Production Time and Invisible Lost Time. Invisible Lost Time is the hidden operation time which is lost due to many factors such as shortage of the key players, lack of experience, reluctant of people and shortage of proper equipment & tools. All these factors are affecting the main drive mechanism in the well which is, the ROP, Tripping Speed and Connection Time. A clear road map for the project was set for three phases. Pilot Phase, where focus was on the mentioned areas and identify the gaps and lesson learns.
Belhouchet, Mohamed (Weatherford Kuwait) | Al-Turkey, Shaikha (KOC) | Shah Bora, Mir Alam (KOC) | Al-Hindi, Khaled (KOC) | Al-Failakawi, Fatma (KOC) | Nair, Abhilash (KOC) | Elabsy, Islam Mohamed (Weatherford Kuwait) | Abdessalem, Abba (Weatherford Kuwait)
Before a well is drilled, the forces and stresses acting within a formation are in equilibrium. However, as the wellbore is drilled and a cylindrical volume of rock is removed, the stresses originally exerted on that volume must instead be transferred to the surrounding formation. The cylinder of rock is essentially replaced by a cylinder of drilling fluid, with its hydraulic pressure substituting for the mechanical support of the rock being removed. The hydrostatic pressure from the drilling fluid is uniform in all directions, and it cannot replicate any directional shear stresses that exist within the formation.
Formation stresses redistribute around the borehole wall, and if they exceed the rock strength, the borehole will start to deform. If the borehole wall itself begins to fail, the resulting problems could include stuck pipe, borehole wall breakout, swelling shales, and unintentional hydraulic fracturing.
The ability to predict and implement corrective action prior to any borehole problem occurring greatly reduces operational risk and ultimately increases operational efficiency. This is accomplished through the development of a geomechanical model which combines local geological and geomechanical field knowledge with comprehensive drilling and evaluation data from offset wells.
The geomechanical model provides the ability to predict and simulate wellbore stability of a planned well. Fields exhibiting considerable lateral heterogeneity and depositional variation can be challenging, but prediction and planning become more accurate as additional wells are drilled.
The well discussed in this paper was drilled with a bottomhole assembly (BHA) which included an azimuthal acoustic tool that enabled real-time wellbore stability analysis and equivalent circulating density (ECD) measurements to maintain an accurate mud-weight window. Real-time monitoring allowed predicted model responses to be confirmed, and/or the model to be updated.
The well was drilled to its final depth with no adverse borehole events, resulting in a quality borehole and a casing run with zero nonproductive time (NPT).
Al-Ghanem, Fahad (Kuwait Oil Company) | Al-Jabri, Saleh (Kuwait Oil Company) | Abdul Hameed, Mohamed Rizwan (Kuwait Oil Company) | Al-Saeed, Mohammed (Kuwait Oil Company) | Al-Otaibi, Mohammed (Kuwait Oil Company)
Kuwait Oil Company (KOC) owns and operates several Oil & Gas fields and Pipeline networks in Kuwait and is responsible for exploration, development, production and operation of Kuwait's Hydrocarbon assets. The oil fields in the western part of the state predominantly produces high sour gas and normally the compressed sour gas is transported to downstream refineries for treatment, wherein the Acid Gas Removal Plants extract the sulfur contents in the gas received by treating it with regenerative Amine based treating processes for removing acidic impurities such as H2S, CO2 and organic Sulphur compounds.
The country has been long battling with the limitations in downstream sector such as limited handling capacity, unplanned shutdowns, and delay in their expansion projects. This created huge bottlenecks for the upstream unit of KOC which consequently resulted in operational disturbances and gas flaring beyond the company's global flaring target of < 1%.
To overcome these challenges, a comprehensive study was carried out for sour gas handling in the State of Kuwait and installation of Gas Sweetening Facility (NGSF) within KOC was considered imperative. However, the process of project delivery was a great challenge due to emerging operational approaches and conflicts with expansion projects in refinery. Thus, breakthrough solutions were set out deploying appropriate core technologies. This paper discusses the challenges at length and the innovative solutions implemented which were intended to optimize the production and utilization of gas in support of energy requirements for the State.
The A East Haradh formation contains a 200-m-thick oil column of highly viscous oil, with viscosity ranging from 200 to 400,000 cp. Because of the high viscosity, first production was considered possible only by the use of thermal enhanced-oil-recovery techniques, starting with cyclic steam stimulation (CSS). This paper presents key learnings derived during this initial-operations phase of CSS in the A East Field, including key trial results on different well completions and artificial-lift systems. In light of the results of a new geochemical characterization study of the crude extracted from a core, cold production was deemed feasible in the crestal area of the field. Viscosities at the top of the Haradh were estimated at 200 cp, lower than previously thought, and progressing cavity pumps (PCPs) were installed in 32 wells to start a cold-production phase.