The Yibal Khuff/Sudair reservoirs were discovered in 1977. The field contains both Non-Associated Gas in the Sudair & Lower Khuff reservoirs and Associated Gas with oil rims in the Upper Khuff reservoirs. The Upper and Lower Khuff hydrocarbons contain 2–3% H2S and 4–6% CO2, whereas the Sudair gas contain 1–1.5% CO2 and less than 50 ppm H2S. The Field Development Plan (FDP), a multibillion dollar sour development project, was completed in 2011 proposing a total of 47 wells, 34 dedicated horizontal/vertical wells for oil rim production and 13 commingled vertical/deviated gas wells, and the construction of new sour surface facilities with a gas production capacity of 6 MMm3/day.
FDP execution started in 2016 while the details of field start-up, scheduled a few years later, were still being planned. As part of this planning, it was noticed that a number of pre-drilled wells required perforation and clean-up before facility startup. Due to the time necessary to prepare all the pre-drilled wells, pre-production wellbore cross-flow was expected to occur in wells located in the West block of the field. A dedicated subsurface team was assigned in 2017 to evaluate and mitigate the potential risks associated with this expected cross-flow through the wellbore resulting from the pressure difference between the Lower Khuff and Upper Khuff layers.
This paper covers the integrated approach that the team followed to address the expected cross-flow issue, including: Basis for pre-production cross- flow The quantification of the cross-flow using analytical and numerical simulation methods The assessment of the impact of cross-flow on process safety and the environment (i.e. drilling risks with potential blow out of sour gas) and social responsibility (i.e. production capacity and ultimate recovery losses resulting in lower benefits to the community) The identification and assessment of solutions to stop/reduce the cross-flow The implementation of a robust and feasible mitigation plan
Basis for pre-production cross- flow
The quantification of the cross-flow using analytical and numerical simulation methods
The assessment of the impact of cross-flow on process safety and the environment (i.e. drilling risks with potential blow out of sour gas) and social responsibility (i.e. production capacity and ultimate recovery losses resulting in lower benefits to the community)
The identification and assessment of solutions to stop/reduce the cross-flow
The implementation of a robust and feasible mitigation plan
The conducted study demonstrated that the impact of cross-flow at well level would be severe. The cross-flow rate could reach up to 25-137 Km3/day/well, while the field level cross-flow rate could reach up to 400 Km3/day. The oil rate capacity reduction in the West Block wells could reach 20-30% at start-up, resulting in a total only 1% oil ultimate recovery loss at field level since the West block contribution is small to total production and West block wells are constrained. The study also showed that the casing design is adequate and drilling risks are manageable even in case of cross-flow. Out of several solutions identified to stop/reduce cross-flow, phasing perforation was considered the most robust and feasible option.
This paper presents the novel approach of a collaborative study that resulted in improved safety and reduced environmental risks and potential ultimate recovery losses. It also presents the methodologies used to allow the Assessment and Mitigation of Pre-Production Cross-flow and evaluation of the best option to mitigate the cross-flow in order to minimize the impact of cross-flow at minimum cost, well interventions and impact on well deliverable.
Noirot, Jean-Christophe (Petroleum Development Oman) | Hamed, Walid (Petroleum Development Oman) | Ghulam, Junaid (Petroleum Development Oman) | Svec, Robert (Petroleum Development Oman) | Cobanoglu, Mustafa (Petroleum Development Oman)
Achieving consistent optimum field development choices in technically complex portfolios requires sound individual and corporate technical capabilities. Within the largest Exploration and Production Company in the Sultanate of Oman, some key gas and contaminated hydrocarbon Field Development Plans are produced by dedicated specialized study teams that are part of the company's so-called Field Development Centre. In order to tackle projects involving technically complex challenges such as tight reservoirs, rich gas condensates, contaminated hydrocarbons or high pressure developments, a number of organizational elements are put in place to ensure continuous growth of staff and corporate capabilities along with corporate knowledge dissemination.
First, each project team remains integrated throughout its project life time. The integration of subsurface and surface disciplines allows early identification of realistic and robust development options. It also facilitates knowledge sharing with activities such as field visits conducted jointly between subsurface and surface engineers. The benefits of this integration are demonstrated with examples from several gas condensate and sour oil study cases.
Second, experienced professionals provide project specific guidance and coaching to junior staff over several projects. This scheme allows maximizing the impact of the experienced staff while allowing hands-on learning from younger recruits.
Third, benefiting from a ring-fenced organization to conduct studies facilitates the retention of corporate knowledge and the replication of best practices. However, this does not imply that knowledge and capabilities remain centralized as several conduits are in place to ensure dissemination across the organization. Asset staffs with identified technical development gaps are assigned for the duration of a project to the study team where they actually develop their skills through direct project contribution. Specialized forums, physical and web-based, are also available to share information and solutions learnt from previous projects.
Finally, fundamental technical capabilities and knowledge bases are developed at corporate level in order to consistently address key challenges encountered in various assets (e.g. gas condensate modeling and optimization, tight units recovery improvement, fraccing optimization and associated production forecasting). A wide scope integrated multi-year project covering all company gas activities within several formations has been kicked-off for this purpose. This fundamental project involves various contributors from the company such as Subject Matter Experts and experienced asset staff, specialized external service providers and academia. More specifically, the project aims at developing a comprehensive corporate understanding of its gas reservoirs, and at developing consistent datasets and validated effective modeling workflows to be disseminated through standards, websites and trainings.
This paper provides an overview of the work practices and tools that have been put in place within a large company in order to ensure the steady development of staff and corporate technical capabilities while consistently addressing the development of its most complex oil and gas reservoirs.
B.Kozluca Field with an OOIP of 138 MMSTB has been producing for more than 16 years. Main producing formation is the carbonate Alt Sinan. Oil gravity is 12.6 °API with a very high viscosity of 500 cp at reservoir conditions. Production mechanism is rock and fluid expansion with a very weak bottom water drive. By the year 2001, the cumulative oil and water production are 3,836,551 stb and 539,059 stb respectively and daily oil production is 570 stb/day with 20 % WC.
In 2000, in order to increase the oil recovery, a re-evaluation and reservoir management study was started. This study was initialized by screening the applicable EOR methods. Since there is a CO2 reservoir at Camurlu Field, which is about 10 km from the B.Kozluca field, study was focused on the CO2 injection. Then, a full field simulation and reservoir characterization study was performed. Firstly, a numerical model was used to predict the oil production by current production scenario and then this model was used to make a sensitivity study to determine a certain CO2 injection pattern, number of the injection wells and the optimum injection rate. Although the initial predictions for different immiscible CO2 injection scenarios give very limited incremental oil due to the very adverse mobility ratio between oil and CO2, this application accelerates the oil production. Then, many different Water Alternating Gas (WAG) scenarios were studied and the results showed that WAG will be better than only CO2 injection. In order to find the optimum injection period many scenarios were studied and 60 days of CO2 injection followed by 30 days of water injection scenario was chosen as the best case. Meanwhile, a parallel study was initiated for the design of the surface facilities and well heads for injection wells of B.Kozluca field, a processing facility for CO2 and produced water at B.Kozluca field and CO2 production and treatment facilities at Camurlu field.
At the end of the integrated reservoir management study, by applying the WAG technique as an EOR method, it was predicted that more than 7 MMSTB incremental oil will be produced with $ 4.25 MM capital investment for surface facilities, additional perforations, pipe line construction and conversion of production wells to injection wells. With this investment, more than $ 20 MM profit will be gained. Pipeline construction between Camurlu and B.Kozluca field has been already started and Camurlu field surface facilities were evaluated and was found to be sufficient for CO2 production and treatment. Other surface facility constructions are being planned for the coming months.
B.Kozluca Field is located in South East of Turkey, close to Syrian border. The field was discovered in 1985 and was developed with a total of 29 wells. The reservoir has one productive layer, called A.Sinan formation.
Since B.Kozluca Field is a heavy oil field, high viscosity and low aquifer support are main constraints for production from B.Kozluca field.
The Water Alternating-Gas (WAG) was originally proposed as a method to improve the sweep efficiency of gas injection, mainly by using the water to control the mobility of the displacement and to stabilize the front1. In the recent years, the number of CO2 injection and WAG applications have increased. The main effect of the WAG application is to increase the horizontal and vertical efficiency.
The use of WAG strategies has become paramout in the operation and economic maintenance of CO2 floods.
It has been found to be an effective and inexpensive tool in the control of gas production throughout the life of the flood2.
The main factors affecting the WAG injection process are the reservoir heterogeneity (stratification and anisotropy), rock wettability, fluid properties, miscibility conditions, gas entrapment, injection technique and WAG parameters like cycling frequency, slug size, WAG ratio, injection rate3.