Alusta, Gamal Abdalla (Heriot-Watt University) | Mackay, Eric James (Heriot-Watt University) | Collins, Ian Ralph (BP Exploration) | Fennema, Julian (Heriot-Watt University) | Armih, Khari (Heriot-Watt University)
This study has focused on the development of a method to test the economic viability of Enhanced Oil Recovery (EOR) versus infill well drilling where the challenge is to compare polymer flooding scenarios with infill well drilling scenarios, not just based on incremental recovery, but on Net Present Value as well.
In a previous publication (Alusta et al., 2011, SPE143300) the method was developed to address polymer flooding, but it can be modified to suit any other EOR methods. The method has been applied to a synthetic scenario with constant economic parameters, which has demonstrated the impact that oil price can have on the decision making process.
The method was then applied and tested (Alusta et al., 2012, SPE150454) with varied operational and economic parameters to investigate the impact in delaying the start of polymer flooding to identify whether it is better to start polymer flooding earlier or later in the life of the project. Consideration was also given to the optimum polymer concentration, and the impact that factors such as oil price and polymer cost have on this decision. Due to the large number of combined reservoir engineering and economic scenarios, Monte Carlo Simulation and advanced analysis of large data sets and the resulting probability distributions had to be developed.
In this paper the methodology is applied to an offshore field where the choice has already been made to drill infill wells, but where we test the robustness of the method against a conventional decision making process for which there is historical data. We do this by performing calculations that compare the infill well scenario chosen with a range of polymer flooding scenarios that could have been selected instead, to identify whether or not the choice to drill infill wells was indeed the optimum choice from an economic perspective.
We conclude from all the reservoir simulations and subsequent economic calculations that the decision to drill infill wells was indeed the optimum choice from an economic perspective.
Wu, JinYong (Schlumberger) | Banerjee, Raj (Schlumberger) | Bolanos, Nelson (Schlumberger) | Alvi, Amanullah (Schlumberger) | Tilke, Peter Gerhard (Schlumberger - Doll Research) | Jilani, Syed Zeeshan (Schlumberger Oilfield UK Plc) | Bogush, Alexander (Schlumberger)
Assessing the waterflood, monitoring the fluids front, and enhancing sweep with the uncertainty of multiple geological realisations, data quality, and measurement presents an ongoing challenge. Defining sweet spots and optimal candidate well locations in a well-developed large field presents an additional challenge for reservoir management. A case study is presented that highlights the approach to this cycle of time-lapse monitoring, acquisition, analysis and planning in delivery of an optimal field development strategy using multi-constrained optimisation combined with fast semi-analytical and numerical simulators.
The multi-constrained optimiser is used in conjunction with different semi-analytical and simulation tools (streamlines, traditional simulators, and new high-powered simulation tools able to manage huge, multi-million-cell-field models) and rapidly predicts optimal well placement locations with inclusion of anti-collision in the presence of the reservoir uncertainties. The case study evaluates proposed field development strategies using the automated multivariable optimisation of well locations, trajectories, completion locations, and flow rates in the presence of existing wells and production history, geological parameters and reservoir engineering constraints, subsurface uncertainty, capex and opex costs, risk tolerance, and drilling sequence.
This optimisation is fast and allows for quick evaluation of multiple strategies to decipher an optimal development plan. Optimisers are a key technology facilitating simulation workflows, since there is no ‘one-approach-fits-all' when optimising oilfield development. Driven by different objective functions (net present value (NPV), return on investment (ROI), or production totals) the case study highlights the challenges, the best practices, and the advantages of an integrated approach in developing an optimal development plan for a brownfield.
A Joint Industry Project (JIP) was conducted in 2007 to determine the degreeof consensus of leading ice mechanics experts on the loads exerted bymulti-year ice on offshore platforms. Seven international experts on multi-yearice loads were asked to predict loads for three different ice loading scenariosinvolving multi-year ice floes: isolated floe, a multi-year floe in pack ice,and a multi-year hummock field in a sheet of first-year ice. The Experts wereasked to calculate the loads from these three ice conditions interacting with a150 m wide vertical caisson structure and a 45 degree conical-shapedstructure. There were significant differences in the methodologies usedand the assumptions made to estimate the loads. Load predictions variedconsiderably for each scenario with estimates differing by a factor of 4.6 forthe vertical caisson and 3.5 for the conical structure. In spite of the lowerratio of predicted loads for the conical structure, the Experts were moreconfident with loads on the vertical caisson. The key areas for furtherresearch were identified and these include improved knowledge of the icethickness and its variation for Old Ice, new and innovative techniques forobtaining ice loads, improved knowledge of pack ice driving forces, and betterunderstanding of the failure behavior of multi-year ice. This paper provides anoverview of the loading scenarios, details of the load predictions, andoutlines the areas identified for future research to help to provide morereliable load predictions.
Ice feature interaction with subsea infrastructure or the seabed is acomplex nonlinear event, for which many analytical and advanced computationaltools have been developed with demonstrated application. Although subsea fieldshave been developed in ice gouge environments, such as the Grand Banks,consideration of alternative methods for protecting subsea infrastructure is ofgreat importance. A more in-depth understanding of ice feature mechanicalbehavior and interaction with subsea infrastructure is required.
For various iceberg shapes and loading conditions, the finite element modelspresented in this paper examine the interaction of free-floating ice featureswith protective structures located above or partially above the mudline. Apreliminary assessment of an interaction scenario involving a gouging icebergkeel with a buried protection structure is also presented. The outcome of thisstudy enhances understanding of the primary factors to be considered for thedesign of protection structures in ice environments and highlights some of thetechnical issues associated with the development and calibration of advancedsimulation tools.
Arctic projects are characterized by a very short installation season withan unpredictable begin and end, as well as large lo-gistical distances. Inparticular pipelay and pipe burial are a concern as these are time consumingprocesses. The deployment of multiple units for completing the work within thenarrow time frame available involves significant mobilization andde-mobilization costs, as for many Arctic developments the nearest offshoreequipment deployment area during the rest of the year is far away.Additionally, the costs of standby whilst waiting for break-up of the ice arehigh for such a vessel spread.
The paper presents a novel concept of pipelay using large floatingexchangeable reels which concept is anticipated to be sig-nificantly fasterthan S-lay. Moreover, it needs only a small construction crew in the field andis competitive with S-lay on costs.
For the economic viability of such a fast pipelay concept, it is essentialthat an Arctic pipelay market of sufficient volume will develop, in order toallow depreciation over a number of projects.
The fast pipelay concept proposed can also be deployed outside the Arctic onprojects having a scope comparable with the example project described.
The subject Gas Field is located in the Sulaiman Fold Belt (SFB) in Pakistan. A realistic 3D static model was constructed for the challenging multiple reservoirs in the Field which included both clastics and carbonates. Four main reservoir horizons were modeled.
The steps involved in the Reservoir engineering analyses were: analyze PVT, well test, Static Pressure Data, and Core. The static pressure analysis helped define hydraulic compartmentalization in the field.
WHFP measurements were not available in the desired accuracy and density. A surface network model was used with plant inlet pressure as the primary constraint in order to obtain the required information. Satellite based elevation information was used to establish an accurate model with respect to pressure drop due to liquid hold up in pipelines.
The History Match in the field was performed on a Zone by Zone basis. In the absence of a 3D seismic cube, many of the faults in the field could not be interpreted, yet their presence was predicted by a closely matching Sand Box Model. This was an important clue which led to a useful approach regarding the location of simulation faults distributed in the entire field. An innovative approach was used in order to calibrate the size of sand lenses in one of the zones.
The final step was the forecasting and development of Optimal Scenario using Economic analysis. Many scenarios were tested, and the optimal scenario was identified. Maximum use was made of existing wellbores through re-completion, and new drilling was minimized. Furthermore, the impact of increasing the currently low Gas Price was tested. It was concluded that doubling of the gas price of the field would increase the NPV 3 times delay abandonment by 6 years.
The Gas Field is located in the Sulaiman Fold Belt (SFB). Eighteen (18) wells in all, those have been drilled in the Field. Currently 12 wells are producing Gas. The primary target horizons in Field are the Sui Main Limestone (SML) and Lower Ranikot (LRKT). However, the Dunghun Limestone and Pab Sandstone are also producing in some of the wells. The depositional sequence consists of clastic and carbonate succession. The stratigraphy of the reservoirs is strongly influenced by the structural evolution of the Sulaiman Fold Belt and initial rifting of the Indian Plate.
A narrative on injection of CO2 for enhanced oil recovery considering the advantages of the integrally geared compressor over the single shaft compressor, and using the Siemens hermetically sealed canned motor-compressor in the process of separating export gas and CO2 for reinjection.
When injecting CO2 for EOR we have investigated the most important market requirements to identify the best solution from the existing portfolio of turbo machinery, when comparing a standard single shaft inline compressor to an integrally geared compressor, and have concluded, based on economics, efficiency, and power consumption, that integrally geared turbo compressors incorporate the optimum design concept for economic CO2 compression.
When re-injecting the produced gas after oil and gas separation there is a mix of saturated CO2 and hydrocarbons and other contaminants possibly containing hydrates, mercury and H2S. Gases and components which are preferably contained in the process equipment without possible leakages to the atmosphere due to seal leakages or malfunction of the compressor units dry gas seals. With the above in mind we developed a sealless (no dry gas seals) compressor which could add strategic benefits and eliminate the need for continuous flaring and venting of the seal gas and barrier gas to the atmosphere. And in conjunction with a fully categorized material selection provide the best solution with high availability and reliability.
Combined with the increased robustness of the overall system with less instrumentation and auxiliary systems and thus less spurious trips and downtime it is obvious that the integrally geared turbo compressor, STC-GV, in combination with the hermetically sealed compressor, STC-ECO, has the potential to considerably contribute to minimizing the environmental foot print, higher reliability and lower OPEX in the Oil & Gas operations especially in the process of mixed flow dirty gas separation found in the CO2 reinjection application.
Optimize early oil production facilities for a H2S environment
Companies active in Exploration & Prodution (E&P) are entering blocks with the target to explore and find new Hydorcarbons (HCs).
Probably most of those E&P companies are chasing "early roduction??, once they have discovery promising a feasible commercial discovery. Moreover, this early productionshould be done in an optimized way. This paper outlines the approach that OMV has taken in order to "optimize the early oil production in an H2S environment?? for a block in Kurdistan, Region of Iraq.
Looking at the project environment, the first question we needed to
answer ourselves was: Optimized in which respect?
? Highest safety / HSSE standards?
High H2S (> 10% in the associated gas) content encountered in the DST!
? Shortest time for oil to produce, deliver and commercialize?
Earliest possible production with standard equipment from the shelf
? Maximize initial oil production?
Just produce to the limit with no proper knowledge (no appraisal done yet) of the reservoir and the reservoir drive.
The answer to the above questions was not an easy one, however, with HSSE being OMV's priority in all operations "SAFETY First!?? has been clear from the very beginning. Independent from all other technical and business issues, OMV started a "Pre development Study?? with the target to have a plan forward, if we would encounteroil in commercial quantities. Actually, that study was started prior (!) to the spud of the first Exploration well.
this created certain costs, but the study provided valuable input for the definition of our "optimized?? solution under the given project environment.
The following steps in the project definition and developmentwill be introduced in detail at the SPE conference:
1. Conduct Pre-Development Study:
Identify country specific basics
2. Opportunity Framing with definition of scenarios
"Do we look wide enough???
3. Define the "optimized - preferred scenario??
4. Minimum economic field size:
Prove the Scenario (OPEX+CAPEX) against the MEF
5. Prepare contracting / procurement strategy
6. Prepare and float the invitation to tender for the early production facilities
El Gazar, Ashraf Lotfy (Abu Dhabi Co. Onshore Oil Opn.) | Ayoub, Mohammed Ramadan (Abu Dhabi Co. Onshore Oil Opn.) | Dawoud, Ahmed Mohamed (Abu Dhabi Co. Onshore Oil Opn.) | Arslan, Izzet (Abu Dhabi Co. Onshore Oil Opn.) | Bin Sumaidaa, Saleh Awadh (Abu Dhabi Co. Onshore Oil Opn.) | Basioni, Mahmoud (Abu Dhabi Company for Onshore Oil Operations (ADCO)) | El Mahdi, Ahmed
This paper presents a case study of developing a significant volume of oil rim with a large gas cap reservoir in Abu Dhabi-UAE.
The reservoir is a low relief heterogeneous carbonate located in a complex environment represented by natural and artificial islands in the surface, shallow and medium water marine areas. The reservoir rock properties showed lateral and vertical heterogeneities as well as variation in reservoir fluid properties.
The static and dynamic data were utilized to construct representative geological and dynamic models for the reservoir. The field development objective focused on producing the oil rim while maintaining the gas cap as long as possible to save the reservoir energy and benefit from the gas cap pressure support.
Five years production dynamic data were available from two oil producers in addition to well testing and MDT data during the appraisal phase "13 wells??. These data were used to quality control the initialization and history match phases.
The development options included pressure support using water injection, lean gas injection, miscible gas injection and miscible WAG injection. The predicted reservoir performance of the oil rim indicated considerable gas cusping from the gas cap in all the development options.
It was a challenge to reduce the amount of gas production from the gas cap in all the development options. A new development option was introduced to perform miscible gas / WAG injection underneath the gas cap accompanied with optimization of the wells and completion intervals locations for producers and injectors to minimize the gas cusping from the gas cap. This resulted in significant enhancement of minimizing gas cusping with minor impact of the recovery factor.
The development of the oil rim was suggested to be in phases focusing on the lowest uncertainty segment of the reservoir. This paper provides the methodology followed to guide the development plan to fill in the uncertainty gap by a detailed data acquisition and monitoring programs to better understand the reservoir behavior.
Water flooding and gas injection are two widely used improved oil recovery techniques that can be applied individually or combined as water alternating gas (WAG) or simultaneous gas and water (SWAG) injection. To do reservoir development planning, for possible implementation of these oil recovery schemes, reliable reservoir performance prediction is needed. Most of the existing reservoir simulators are unable to adequately account for all the complex multi-phase and multi-physics processes involved in these oil recovery techniques. That is particularly the case under mixed-wet and low gas-oil IFT (near-miscible) conditions. Performing reliable laboratory experiments is the key to evaluating the performance of these oil recovery techniques under reservoir conditions.
We present the results of a comprehensive series of well-controlled coreflood experiments carried out under mixed-wet condition using a very low IFT gas-oil system. The experiments include oil recovery by water flood (WF), continues gas injection (CGI), two series of WAG, and two series of SWAG injection tests. The difference between the two WAG experiments is the order in which gas and water injections are carried out. The first WAG test started with water injection whereas the second WAG experiment started with gas injection. The difference between the two SWAG experiments is the gas/water (SWAG) ratio, which was 0.25 for the first one and 1.0 for the second SWAG test.
The results show that in both mixed-wet cores, WAG injection has a superior performance over WF, CGI and SWAG injection. Oil recovery by the WAG test which had started with water injection was higher than the WAG test started with gas injection. SWAG performed better compare to CGI. However, surprisingly, SWAG resulted in lower oil recovery compared to primary waterflood in these mixed-wet systems. It was observed that increasing the gas/water ratio in SWAG leads to faster gas breakthrough, higher produced gas/oil ratio and further reduction in the recovery performance of SWAG. Compared to the other injection strategies, a very high pressure drop across the core was observed during SWAG injection indicating injectivity problems with the application of the process in mixed-wet rocks. The results show that for mixed-wet rocks, amongst the studied injection strategies, SWAG is the worst and alternating injection of water and gas (WAG), starting with a water flood period, is the best injection strategy.