The Gulf of Suez Petroleum Company (GUPCO) is a leading Egyptian petroleum company. GUPCO production is primarily dependent on gas lift with 90% of its producing wells utilizing this artificial lift method, consuming more than 450 MMSCF of gas per day. One of the main hindrances to maximizing GUPCO's production is insufficient gas supply which leads to shutting in many producers resulting in significant production deferrals.
GUPCO's Base Management Team (BMT) initiated an integrated system optimization project in 2013 which combined four different technical pieces of work. It was introduced for the first time in GUPCO to ensure gas is used efficiently in the Gulf of Suez (GoS) to maximize the value of GUPCO's old data, build trust in well and surface modelling and increase BMT capabilities. The main challenges of this project were data gathering and quality, engineering capabilities in the use of Prosper and GAP modelling and lack of integration between field and office technical personnel regarding the system optimization.
Working through these challenges created tangible value through enhanced understanding of the gas sy stem, identifying additional opportunities to save gas and increased oil production. This boosted the modelling capabilities of all team members. The BMT approach was divided into four different phases as follows: Gas balance study for better understanding of the gas systems in the different areas across the GoS. Prosper modelling for gas-lifted wells that resulted in 20 gas lift valve change opportunities that lead to increased production of 1000 BOPD. GAP modelling for the production system that resulted in a 7700 BOPD potential oil gain, 16.5 MMSCFD potential gas saving and debottlenecked pipelines. Creaming curves which became a very good tool to prioritize the GL wells with respect to gas availability, evaluating well work value, and quantifying the impact of surface facilities failures and/or repairs.
Gas balance study for better understanding of the gas systems in the different areas across the GoS.
Prosper modelling for gas-lifted wells that resulted in 20 gas lift valve change opportunities that lead to increased production of 1000 BOPD.
GAP modelling for the production system that resulted in a 7700 BOPD potential oil gain, 16.5 MMSCFD potential gas saving and debottlenecked pipelines.
Creaming curves which became a very good tool to prioritize the GL wells with respect to gas availability, evaluating well work value, and quantifying the impact of surface facilities failures and/or repairs.
Until the time of this paper, the project was in the execution phase and has resulted in saving 7 MMSCFD from optimizing gas lift injection in 8 wells. The forward plan of the project is as follows: Continue the execution phase and ensure good communication between all teams. Install recommended meters/scanners to enhance data measurement in order to ensure sy stem balance. Complete GL optimization execution in SC GoS & share the outcomes. Install MPFM on some offshore platforms which will help in evaluating the optimization. Utilize a Portable Test Package for further enhancement of system evaluation & optimization.
Continue the execution phase and ensure good communication between all teams.
Install recommended meters/scanners to enhance data measurement in order to ensure sy stem balance.
Complete GL optimization execution in SC GoS & share the outcomes.
Install MPFM on some offshore platforms which will help in evaluating the optimization.
Utilize a Portable Test Package for further enhancement of system evaluation & optimization.
The objective of this paper is to show the technical processes used to initiate an integrated gas lift optimization project in the GoS and how the opportunities created will add considerable benefits to the business.
Kortam, Mostafa (Petrobel) | Anwar, M. (Petrobel) | Mousa, Doaa (Petrobel) | Fouad, Ahmed (Petrobel) | Yosry, Mohamed (BP Egypt) | Mathur, Anil (Schlumberger) | Abbas, Nelly Mohamed (Schlumberger) | Sahli, Mohamed El (Schlumberger)
The Abu Rudies field in the Egyptian Sinai peninsula produces mainly from the South Gharib formation that is characterized as a complex, heterogeneous, thick and laminated, but permeable, slightly oil wet rock and depleted sandstones consisting of sands with an average permeability in the range of 150-550 mD and Young's Modulus in the order of 1.0 - 2.5 million psi. Conventional hydraulic fracturing and Frac & Pack techniques have been traditionally deployed to produce hydrocarbons and for sand control. The added complication is the reduction in the effective permeability to oil due to the rock being oil wet. Conventional fracturing techniques have had limited success especially in the highly permeable compartments of the field due to premature screenouts that were encountered extensively, residual polymer in the intergranular porous rock and the flowback of formation sand and proppant. This paper describes the application and production enhancement efforts for the first time with a novel channel-fracturing technique combined with rod-shaped proppant in selected production targets in the Abu Rudies field in Egypt. The channel fracturing technique introduces channels within the proppant pack that significantly increase conductivity and effective fracture half-length leading to increased productivity. Rod-shaped proppant when used as tail-in in fracturing treatments increases near-wellbore fracture conductivity and completely prevents proppant/formation sands flowback as demonstrated by zero flowback due to its particular geometry. This paper describes actual case studies of fracturing a high-permeability layered reservoir using the channel fracturing technique, the problems encountered due to high leak off, low closure pressures, reservoir heterogeneity and the complexity due to adjacent water bearing layers. Finally, we demonstrate the well performance with the channel fracturing technique compared with alternate techniques.
Marie Van Steene, SPE, and Mario Ardila, SPE, Schlumberger; Richard Nelson, SPE, and Amr Fekry, SPE, BP Egypt; and Adel Farghaly, SPE, RWE Dea Summary In hydrocarbon reservoirs, fluid types can often vary from dry gas to volatile oil in the same column. Because of varying and unknown invasion patterns and inexact clay-volume estimations, fluid-types differentiation on the basis of conventional logs is not always conclusive. A case study is presented by use of advanced nuclear-magnetic-resonance (NMR) techniques in conjunction with advanced downhole-fluid-analysis (DFA) measurements and focused sampling from wireline formation testers (WFTs) to accurately assess the hydrocarbon-type variations. The saturation-profiling data from an NMR diffusion-based tool provides fluid-typing information in a continuous depth log. This approach can be limited by invasion. On the other hand, formation testers allow taking in-situ measurements of the virgin fluids beyond the invaded zone, but at discrete depths only. Thus, the two measurements ideally complement each other. In this case study, NMR saturation profiling was acquired over a series of channelized reservoirs. There is a transition from a water zone to an oil zone, and then to a rich-gas reservoir, indicated by both the DFA and the NMR measurements. Above the rich gas, is a dry-gas interval that is conclusively in a separate compartment. Diffusion-based NMR identifies the fluid type in a series of thin reservoirs above this main section, in which no samples were taken. NMR and DFA both detect compositional gradients, invisible to conventional logs. The work presented in this paper demonstrates how the integration of measurements from various tools can lead to a better understanding of fluid types and distribution.
Well A, encountered multiple depleted reservoir layers (initial reservoir pressure >10840 psi) with up to 5,000 psi differential pressure across layers due to irregular depletion in thin bedded shale and sand layers. Well was drilled with over 16 ppg mud to limit under balance in any higher pressure layer and overbalance in depleted layers. After drilling 4 lopes of sand body and during the start of drilling the last sand lope, complete loss of circulation was encountered, followed by kick and differential sticking. The original well integrity assurance plan considered the deployment of borehole compensated sonic tool in order to acquire a discriminated cement bond log based on attenuation measurement. Also in the plan, a Cased Hole Dynamic Tester tool was to be run and the selection of pressure points to be based on the results of the cbl-vdl. So to assure the full integrity of the cement and be able to conduct the Cased Hole Dynamic Tester as required and proper decision to be evaluated regarding the Type of GP job, the use of the Ultrasonic Imaging Tool was evaluated to be run under tough and challenging conditions (high mud weight and thick wall thickness).
The Ultrasonic tool for cement to casing bond evaluation is typically limited by the attenuation of the ultrasonic echo caused by the wellbore mud weight and composition. With the cooperation between BP PhPc and Schlumberger, and making use of worldwide expertise, the decision was taken to include the Ultrasonic Tool in the cement evaluation suite despite the well conditions.
The analysis of the log managed to prove the zonal isolation requirements and be a source of development of best practices that can improve cement evaluation even with the presence of heavy SOBM.
Fundamentals for the Cased Hole Dynamic Tester (CHDT*) in order to acquire representative formation pressure measurements at interest depths:
1. Good zonal isolation obtained by an effective and homogenous cement sheath bonded to both casing and formation.
2. Casing quality for the seal between the CHDT* tool and casing ID.
The CHDT* tool seals against the casing and uses a flexible drill shaft to drill through casing and cement into the formation. When communication to the formation is established, multiple pretest measurements can be taken to ensure a repeatable formation pressure measurement. After performing the required pressure testing, the CHDT* tool can seal the hole with a 10k psi bi??directional corrosion resistant plug and test plug integrity.
Ultrasonic Imaging tool (USIT*) provides an overview of cement to casing bond quality as well as radius and thickness.
Cement integrity and casing quality is measured simultaneously with 360??degree azimuthal acoustic coverage by the USIT* tool. Precise acoustic measurements of the internal dimensions of the casing and of its thickness made with a rotating transducer provide a map??like presentation of casing condition including internal and external damage or deformation. Analysis of the reflected ultrasonic wave package provides information about the acoustic impedance of the material immediately behind the casing. A cement map presents a visual indicator of cement quality.
Sand control, particularly gravel packing, is a common practice in the Mediterranean Sea due to the presence of poorly consolidated sandstone reservoirs. Open Hole Gravel Packs (OHGP) in highly deviated wells present an additional challenge due to the risk of sand bridging during the alpha wave propagation. The risk of bridging is escalated further in low fracture gradient environments where the pumping rate is reduced to avoid inducing losses. A major operator in Egypt has performed the first highly deviated OHGP jobs in the Mediterranean using Alternate Path screens. A series of qualification work was performed by the service provider during the planning phase for the 2 wells. Planning work included fluid rheology tests, flow loop testing, modeling full scale tests to achieve desired accuracy with gravel transport equations, pretreatment numerical simulations and post-treatment comparison of simulated data to actual data. Moreover, a lightweight proppant (LWP) product was qualified and successfully pumped on the second well where the fracture gradient was particularly low due to reservoir depletion. This paper discusses the planning, execution and post-job review work that was performed for these wells to produce two successful sand control jobs. Recommendations and lessons learnt for the future wells are also included.
With the Industry and specifically the Mediterranean Basin moving towards more challenging wells requiring sand control in ever higher deviations and significantly depleted sands these highly deviated gravel packs with high overbalances are becoming increasingly important to unlock resources and maintain field plateau.
The paper will detail the simulated results based on flow loop testing and how they compare with the actual job data. Successful sand control integrity was achieved with amount of gravel pumped exceeding 100% of the theoretical volume and sand free production achieved on both wells. Individual well performance with estimated skin values will also be shared.
A successful use of MPD techniques from a semi??submersible rig in an HPHT drilling operation offshore Egypt is described. Included is a discussion of the MPD techniques and experience developed on jack??up HPHT drilling operations and how these were successfully transferred across to the floating rig operation. The presentation will discuss the rig modifications required to install the MPD equipment on the semi??submersible, including installation of the rotating head in the marine riser. It will also review the operations carried out utilizing MPD techniques, and give examples of how the equipment was used in the drilling of the last 3 hole sections. Some key areas considered essential to the success of this technology on a floating rig in a demanding HPHT environment and the benefits associated with the MPD operation are highlighted.
Taurt field, located in the Mediterranean Sea in 108-m water depth, is the first BP-operated subsea-to-shore gas development. Phase 1 of the project consists of two subsea wells producing directly from the subsea manifold to the onshore gas-processing plant with a 68-km, 20-in. pipeline. The field has been brought into production and was successfully ramped up to 230 MMscf/D despite facility constraints during initial startup. The main flow-assurance issues experienced during the initial startup are hydrate risks because of Joule-Thomson (J-T) cooling and liquid-production handling onshore, particularly because of potential completion-brine return.
The experience during initial startup highlights the importance of collecting good fluid samples during exploration and appraisal, and obtaining downhole and wellhead pressures and temperatures during flowback. Confirming the condensate yield helps prediction of liquid holdup in the pipeline that will affect the prediction of liquid production coming onshore during ramp up. More-accurate prediction of the wellhead temperature affects the requirement for hydrate inhibitor, which also affects the liquid holdup in the pipeline and liquid production coming onshore.
Transient simulations help in selecting the dewatering strategy to be either a pigged or a pigless operation by predicting the amount of remaining water and how it impacts the production ramp up. Simulations also help prediction of the liquid production for setting up temporary liquid-handling facilities to prevent the possibility of completion-brine return upsetting the processing plant.
Comparison with the actual liquid-production data suggests that simulations should have been performed with less-conservative condensate yield, although predicting the completion-brine return onshore is still difficult. After obtaining the latest fluid composition and the actual operating conditions, the hydrate-management strategy was revisited, and this resulted in cost savings and simpler operating procedures.
Howes, Thomas Bennett (BP Egypt) | Farouk, Mohamed (BP Egypt) | Darwish, Mohamed (Gulf of Suez Petroleum Company) | Koroletz, Wilhelm (Baker Hughes - Egypt) | Ismail, Ahmed M. (Baker Hughes - Egypt) | Moustafa, Amin (Baker Hughes - Egypt) | Heisig, Gerald (INTEQ)
To address risk and uncertainties in difficult sidetrack operations in the Gulf of Suez in Egypt, a new method was implemented to identify and control the direction of the wellbore during the whipstock exit, and close to the liner, where standard directional measurements are compromised due to magnetic interference. Bending moment sensors were placed directly above the motor and only 26 ft behind the bit. These sensors delivered two perpendicular bending moment measurements referenced to gravity high side. Transmitted to surface via mud pulse telemetry, the two signals were further processed to deliver the well tool face and - with the help of a mathematical BHA model - the dogleg severity of the well.
In one case the well tool face confirmed the orientation of the whipstock and the window milled. However, in a second case, the measurement revealed a 40 degree deviation from the original whipstock orientation. The well plan was immediately adjusted to compensate for this deviation from plan. The dogleg severity information gave improved azimuth control when steering away from the existing well in sliding mode. As a result, both sidetracks achieved their directional objectives and could be steered into the target. The directional estimates derived from the bending moment measurements were later confirmed by the first valid MWD surveys and by gyroscopic survey measurements.
The paper will start with a detailed description of the directional challenges in this application. It will then introduce the concept of the bending moment measurements and the derived directional information, well tool face and dogleg severity. After a description of the implementation and directional execution of the sidetracks, the paper will conclude with a discussion of the benefits and the potential of this new directional control method, which could result in a reduction or even complete elimination of gyro runs during similar casing exits and significant rig time savings.