Transverse fractures created from horizontal wells are a common choice in tight and shale gas reservoirs. Previous work has shown that proppant pack permeability reduction due to non-Darcy flow in a transverse fracture from a horizontal well causes significant reduction in the fracture performance when the gas formation permeability exceeds 0.5 md. There are other configurations and architectures such as aligning the well trajectory with the fracture, either by drilling horizontal wells in the direction that results in longitudinal fractures or by just sticking with drilling vertical wells. However, when drilling and fracturing costs are considered, productivity is not the only optimization consideration.
The field example illustrates a case when the apparent choice to use transverse fractures from horizontal wells proved to be suboptimal from the productivity perspective, but fundamental considering economics. Parametric studies for permeability ranging from 0.01 to 5 md illustrate the importance of economics in addition to physical performance. For similar reservoir characteristics, the optimum fractured well architecture varies considerably, and therefore an extensive reservoir engineering approach may be necessary beyond the well completions and/or current prejudices and inadequate understanding.
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.
Gupta, Shilpi (Schlumberger) | Pandey, Arun (Schlumberger) | Ogra, Konark (Schlumberger) | Sinha, Ravi (Schlumberger) | Chandra, Yogesh (ONGC) | Singh, PP (ONGC) | Koushik, YD (ONGC) | Verma, Vibhor (Schlumberger) | Chaudhary, Sunil (Oil & Natural Gas Corp. Ltd.)
Production logging has been traditionally used for zonal quantification of layers for identification of most obvious workover for water shut off, acid wash or reperforation candidate identification. The basic sensors help in making some of the critical decisions for immediate gain in oil production or reduction in water cut. However, this technology can be used in a non standard format for various purposes including multilayer testing to obtain layer wise permeability and skin factor using pressure and flow rate transient data acquired with production logging tools. This is very crucial and complements the present wellbore flow phenomenon to better understand relative zonal performance of well at any stage of its production. In addition, production logging along with the pulsed neutron technique is very crucial to evaluate the complete wellbore phenomenon, understand some of the behind the production string fluid flow behaviors. Another major concern in low flow rate wells is recirculation, causing fall back of heavier water phase while lighter phase like oil and gas move upwards. This well bore phenomenon renders the quantification from production logging string, and this in extension also prevents any comprehensive workover decisions on the well because of the risk involved. Oil rate computation from hydrocarbon bubble rates becomes very critical in such scenarios to bring out the most optimal results and enhance confidence in workover decisions. Another key concern in any reservoir is to evaluate the productivity Index; this is even more critical once the field is on production. It is essential to determine the performance of various commingled layers and reform the Injector producer strategy for pressure support or immediate workover. Selective Inflow performance is a technique used to identify the Productivity index of various layers in a commingled situation. This paper elaborates on various non conventional uses of production logging from the western offshore India.
Brown field management has been a key focus in the western offshore region. Over the last decade cased hole production logging for evaluation of reservoir phenomenon has been the backbone of workover operation in western offshore India. Besides the usual operations production logging has been pivotal in determining various important parameters for field development. Various unconventional uses require understanding of the tool physics and limitation. Advanced generation of production logging tools not only provide additional information in terms of wellbore flow fractions, slippage velocities and complex flow regimes but their basic outputs can also be utilized in variety of applications for reservoir evaluation and wellbore flow monitoring. Following sections describe several case studies describing unconventional usage of production logging outcomes.
Unconventional Applications of Production Logging
Case Study 1: Selective Inflow Performance
Field wise production logging has always been an excellent source to evaluate the open hole results and suggest some immediate workover to optimise the production. Selective Inflow performance is new variation in the already existing technique used to identify the Productivity index of various layers in a commingled situation. This operation can provide us with the openhole flow potential of the well and thus help in mapping the flow profile in the reservoir. A multichoke production logging survey usually covering two to three choke sizes is performed and flow profiling for each survey is done.
Pressure maintenance support in mature fields where permeability heterogeneity is present requires proper distribution of injected water into the respective zones of interest. This process can be extremely challenging, if no method for allocating the proper amount of water into each zone is available. An operator in the South China Sea, who had initiated a water injection project using legacy single-string two-zone completion technologies, found himself in this predicament, since no selective control for pressure maintenance had been considered for the project.
During the past few years, the application of intelligent completion (IC) technology has increased rapidly. This acceptance has been due primarily to its proven capabilities for reservoir monitoring and corresponding optimization of well performance without well interventions. Historically, the majority of IC applications have been in production wells; however, an increasing number of operators have started adopting IC technology for their injector wells.
This paper presents a case study in which IC technology was successfully applied in an offshore field in the South China Sea to provide an efficient water-injection method for optimizing pressure support as well as sweep. The operator selected this technology, as it presented a solution for optimizing the water injection. In addition to eliminating problems experienced with the incapability of the legacy completion technology to monitor water allocation and pressure maintenance for each zone, the IC technology would allow selective well testing for each zone. By evaluating the reservoir properties and characteristics of each zone independently, an intelligent completion would provide another key benefit to the operator, since it would comply with the platform size restrictions for the pumping equipment.
The paper will discuss field objectives, the conceptual design, the design obstacles, and the operational challenges experienced during the job execution.
The success of recent applications in underbalanced drilling (UBD) and managed pressure drilling (MPD) has accelerated the development of technology in order to optimize drilling operations. The increased number of depleted reservoirs and the necessity for reducing formation damage has also increased the need to apply UBD/MPD to such candidate fields. Several methods used the latest mechanistic multiphase flow models in order to predict bottomhole circulation pressure when performing UBD/MPD operations. A new model is developed that utilizes the latest mechanistic multiphase flow models; the developed model calculates the bottomhole circulation pressure as a function of surface injection rates, choke pressure and time.
The developed model can be used in designing and optimizing UBD/MPD operations in terms of determining the correct injection rate and/or choke pressure. In addition, the developed model is used to utilize the reservoir energy to attain correct bottomhole conditions. The developed model in addition to utilizing the latest mechanistic models also reduce the error in calculating the bottom hole pressure by incorporating an algorithm in which the injection rates are calculated in-situ rather than assuming constant injection rates.
The model is validated against data from literature and against a commercial simulator. Results show that the developed algorithm has increased the accuracy in predicting bottomhole pressure by incorporating the changes in new gas and liquid injection rates.
Al Hamad, Abdullah (Halliburton) | Abdul-Razaq, Eman (KOC) | Al Bahrani, Hasan (KOC) | Surjaatmadja, Jim Basuki (Halliburton) | Bouland, Ali (Kuwait Oil Company) | Turkey, Naween (KOC) | Brand, Shannon (Halliburton) | Al-Saqabi, Mishari Bader (Kuwait Oil Company) | Al-Zankawi, Omran (Kuwait Oil Company) | Vishwanath, Chimmalgi (KOC) | Gazi, Naz H. (Kuwait Oil Company)
There are many ways to stimulate an unlined openhole horizontal well using acid. The simplest way is to just pump acid into the well (i.e., bullhead) without placement control. However, this can often be ineffective. Although still used, such approaches can create massive enlargements at the entry point or high injectivity area, thus causing ineffective treatments and re-entry issues. Wellbore collapse often follows. The use of coiled tubing (CT) as a "pin-point?? delivery method is therefore preferred. Using CT allows dispersal of the acid either uniformly or intermittently along the lateral, as desired. CT also allows acid washing to be performed, which is another common process that can improve stimulation without much additional expense to the operator. Using a jetting tool with many jets, acid can be sprayed onto the wellbore wall, and the active agitation caused by the acid-wash process increases the chemical reactivity of the acid at the desired locations.
Another beneficial approach of using CT is the hydrajet assisted acid fracturing (HJAAF) method. With focused jetting of acid at much higher pressures, the process initiates microfractures in the wellbore walls. When etched with acid, this approach effectively bypasses near-wellbore (NWB) damage much deeper than common washes, thus providing much better results. Further modification of the process by exerting high annular pressures offers the capability of delivering medium to large fractures.
This paper discusses two HJAAF processes uniquely combined into one process used in two large horizontal wells. Because of the large dimension of the inner diameter (ID) of the wells combined with the small production tubing the tool must pass through, the implementation had to be further improved by using a unique jetting mechanism, which positioned the jet nozzles closer to the target. Actual results of such stimulations are presented.
This paper describes key initiatives of the HSE management system that has been developed, and implementation at KOC West Kuwait (WK) fields which resulted in 26 Million Man-Hours worked without any lost time injury till 31st March 2012.
The multi-cultural composition of the workforce imposes specific difficulties in execution of HSE initiatives and application of the HSE Management System. Significant efforts have been made by HSE (WK) Team to address these areas using approaches such as communication & awareness on HSE Management System with all levels of Business partners and Company's employees.
The initiatives and achievement that HSE West Kuwait has adopted resulted in minimizing the industrial incidents and Motor Vehicles Accidents. This paper also focuses on the process of implementation of various initiatives taken by the HSE (WK) to achieve a substantial lowering of HSE risks, reduction of disabling injuries and frequency rates, and employee HSE behavior, enhanced Contractor's HSE performance and many more indirect positive results.
Significance of Subject Matter
All of the company's activities have the potential to affect the health, safety and environment of its stakeholders and nearby communities in a positive or negative way. KOC is committed to managing these effects and the risks associated with its activities and products. To fulfill the commitment, HSE (WK) initiated following activities for the implementation of a HSE Management System at the field.
1. Setting up of HSE (West Kuwait) Team and streamlining of responsibilities/ functions.
2. Clearance of Explosive Ordinance Disposal from West Kuwait key areas.
3. HSE Compliance at Site by Leadership HSE visits.
4. Communication with KOC Employees and Business Partners (Contractors).
5. Road Safety Measures.
6. Initiating and ensuring the presence of a Physician in WK Clinic.
7. Active Participation in International Conferences.
8. British Safety Council Award-International Safety Award for 2011for WK Fields.
9. Certification for the "Campaign of the Year?? award by SHP-IOSH.
10. Results and Conclusion.
Excessive water production from unwanted zones in oil producing wells is one of the major challenges faced by the oil industry. The applicability of organically crosslinked polymer (OCP) systems as sealants for water shutoff treatments in temperatures up to 350°F is well documented. However, their effectiveness at temperatures above 350°F has not been evaluated. This paper presents experimental data from using an OCP system for water shutoff treatments at 400°F.
At temperatures around 400°F, crosslinking is expected to happen faster and can lead to premature gelation of the recipe before the entire treatment is in place. Thus, controlling the gelation time at such temperatures is extremely crucial. Optimizing the amount of retarder is essential to provide adequate time for placement of the treatment fluid. This paper provides gelation time data at temperatures between 350 and 400°F with different amounts of retarder. With an optimum amount of retarder, the OCP showed a gelation time of 1 hr 20 min.
This paper also describes the experimental setup used to study and determine the long-term stability of the OCP system at 400°F. Sand packs measuring 1-ft long were used for the test to simulate formation conditions. Once the optimized OCP recipe was gelled inside the sand pack, measurements were taken by gradually applying incremental differential pressure (?P) to evaluate the sealant at temperature, as well as the threshold ?P the system could withstand. Even after one month at 400°F, the OCP recipe was able to sustain a ?P of 950 psi over the sand pack.
The data indicates the applicability of this system as an effective conformance product to shut off water-producing zones over an extended period of time at 400°F.
In recent times the topic of well barrier integrity has become increasingly salient. Within the well completion arena, there have traditionally been two main alternatives for barrier plugs used for packer setting or temporary well abandonment; these are the metallic flapper or ball type isolation plugs. This paper describes the evolution of an innovative glass type barrier plug from its first appearance in the oilfield in 2004, to the deployment of third generation prototype systems into wells in the North Sea today.
Traditional ball or flapper type plug systems need to operate in two states: open and closed. This functionality typically necessitates the use of dynamic seals, which also have to compensate for the pressure differential applied across the plug. Plugs built in this manner can be prone to malfunctions in the dynamic seals and have limitations as to the pressure differentials that can be applied to them when opening. Additionally as the balls or flappers themselves are traditionally manufactured using metallic alloys, in the event that a plug fails to open the only alternative is milling, which if successful, will still leave a restriction in the well limiting options for future well interventions.
Glass barrier plugs have to operate in two slightly different states, solid or shattered. When the plug is run in hole the glass is in a solid state with pressure integrity maintained using static elastomeric seals. Once well operations have progressed to the stage when the plug needs to be opened, a preinstalled trip saver can be activated which would shatter the glass and open well communication. Operating in this manner avoids the use of dynamic seals thereby increasing plug reliability. Other major advantages are that the differential pressure applied across the plug when opening has no effect on the plugs functionality and since the plug is made out of glass, in the event of a trip saver malfunction the plug can be opened using a shoot down tool, a spear, or milled within approximately 10 minutes using a wireline tractor (Welltec, 2011) leaving a full bore ID for future well interventions.
This paper describes how BP Norway and TCO used the lessons learned from two generations of Glass Barrier Plugs (GBPs) to develop a system with increased debris tolerance, improved redundancy and a larger inner diameter.
Dashti, Qasem M. (Kuwait Oil Company) | Al-anzi, Ealian H.D. (Kuwait Oil Company) | Al- Doheim, Aref (Kuwait Oil Company) | Kabir, Mir Md Rezaul (Kuwait Oil Company) | Acharya, Mihira Narayan (Kuwait Oil Company) | Al-Ajmi, Saad (Kuwait Oil Company)
Robustness of measurement while drilling (MWD) and logging while drilling (LWD) tools is laboratory-tested and rigorously field-tested for the expected operating and measurement specifications. Such tools have been used in the industry for decades with proven track record of stability. However, a typical tool string deployed as a part of bottom-hole assembly (BHA) has recently failed to withstand the unexpected BH conditions during drilling of the pilot hole using potassium formate mud (KFM), a heavy water based mud. The failure occurred within a deep-fractured calcareous kerogen section (CKS).
The tools had multiple surface communication failures; the first one was resolved as debris was found obstructing the rotor-starter part before drilling the CKS. The second failure occurred in the back-up tools, after drilling into the CKS and remained unexplained throughout drilling with the expectation of BH data recorded on memory. Inspection of the tool components, once the drilling was completed, revealed two major findings: First, some parts of the BHA, specifically the components of the CuBe tool had "vanished??. Secondly, the recovered tool parts had further damage due to corrosion and pitting. In addition, an unexpected color change in metal body parts was observed.
In the paper, the authors explain the unique mystery of tool eating "down-hole ghost??. Similar tools were previously used without an issue at comparable high pressure and temperature conditions and in geological sections alike in Kuwait in drilling with oil-based mud. The service provider's operational experience elsewhere has failed to explain the bizarre outcome, as they had not encountered similar incidents of vanishing tool parts and down-hole color change. The claim was that similar tools were successfully operated in water-based mud drilling including KFM. This claim was confirmed prior to the field execution with metallurgical compatibility tests carried out by the mud supplier.