This study has been focusing on planning wells, which target lower Pleistocene reservoirs below a depleted Ha'py gas field. Many Non Productive time events (NPT) have been anticipated, and the challenges of losing wells and running over budget have been considered as major risks in targeting the deeper prospects.
Years of production from the main Pleistocene A20 reservoir has resulted in significant pressure depletion, while underlying largely-undeveloped Pleistocene reservoirs appear to be very promising they remain at or close to virgin conditions. In addition, the position of the platform at the centre of the field has made it necessary to drill highly-deviated wells to access remaining reserves at the crest of the field.
Detailed planning and close collaboration between the PhPC (Pharaonic Petroleum Company) subsurface and drilling teams has been necessary to understand the geological and geomechanical properties of the key formations. This has helped in selecting appropriate mud rheology and mud additives in addition to ensuring good drilling practices that maximise safety and success. The combined effects of depletion and low rock strength make it effectively impossible to drill the A20 interval with the mud weights required to minimize well bore instability. As a result, stress cage additives were employed in the drilling mud in order to reduce the potential for losses due to the large overbalance against the depleted sand. Modeling prior to drilling suggested this application lay close to the technical limit of the stress cage methodology, and was beyond anything previously attempted within the Pleistocene reservoirs in the offshore Nile Delta.
Careful execution meant we were able to successfully drill through the depleted zone, and as a result of this work, we have been able to deepen recent wells to access underlying gas resources. This success has allowed us to reduce NPT while ensuring safe well operations.
Oilfield scale costs are high because of drastic oil and gas production decline, frequent pulling of down-hole equipment for replacement, re-perforation of the scaling producing intervals, reaming and re-drilling of the plugged oil wells, stimulation of the plugged oil-bearing formation and other remedial work-over. As scale deposits around the well-bore, the porous formation becomes plugged and may be rendered impermeable to any fluids.
In most of oil and gas fields scale deposition in surface and subsurface production equipment has been recognized to be one of the major operational problem. Problem will be more critical in Water flooded fields where wells will suffered from flow restriction because of scale deposition within the oil producing formation matrix and the down-hole equipment, as well as scale deposits in the surface production equipment.
Some of the Oil Fields have been water-flooded with formation seawater. Compatibility tests have indicated probable deposition of scale in surface and subsurface production equipment. This paper outlines the physical and theoretical prediction for down-hole scale deposition in the water flooded fields.
Water is the main substance, which is responsible for scale build up problem. In order to study the circumstances behind the scale build up problem, following the new methodology which can be applied to predict the different types of scale build up before start to be precipitated. From the samples of the complete water analysis reports, Scale Indexes were calculated to define the different scales that can be precipitated at different production nodes/conditions.
This paper showed that different types/amounts of scale accumulation can be precipitated from the selected water samples since the super saturation conditions of water occurred. It also described the control of scale inhibition programs which could be carried out to control down-hole scale deposition and scale inhibition treatment that could be implemented to overcome the scale deposition, before scale problem will be occurred. Scale control can also been controlled/managed properly by continues updating the new scale index calculations methodology described in the probable problematic water flooded reservoir.
Some of the Oil Fields have been water-flooded with seawater. Compatibility tests have indicated probable deposition of scale on surface and subsurface production equipment. This paper outlines the physical and theoretical prediction for down-hole scale deposition in example OIL wells. It also describes the control of scale inhibition programs which carried out to control down-hole scale deposition by using the formation squeeze technique.
Scale deposition on surface and subsurface oil and gas production equipment has been recognized to be a major operational problem. Scale contributes to equipment wear and corrosion and flow restriction, thus resulting in a decrease in oil and gas production. Experience in the oil industry has indicated that many oil wells have suffered flow restriction because of scale deposition within the oil/gas-producing formation matrix and the down-hole equipment, as well as scale deposits in the surface production equipment and, generally in primary, secondary, and tertiary oil recovery phase.
An increasing number of deviated wells are being drilled to maximize production and hydrocarbon recovery in the mature reservoirs of the Gulf of Suez (GoS). Successfully drilling a high-angle well in a tectonically disturbed and structurally complex area like the GoS is very challenging, especially in depleted reservoirs. Selecting the optimal mud weight is absolutely essential. Stress orientation and magnitude also have a major impact on wellbore stability.
The region poses significant drilling challenges that vary widely from reactive shale and salt creep to stress-related instability. From the findings of multiple wellbore stability projects we conducted in the GoS, we review the dominant mechanisms of wellbore instability in the GoS. We provide a summary of the failure mitigation measures and an overview of stress magnitude and orientation in the region, demonstrating how it impacts the knowledge of the most stable drilling direction.
Understanding the main causes of rock failure in the GoS resulted in improved drilling efficiency and reduced drilling costs. We show an example, where a new, nearly horizontal (86º) well was successfully drilled through the Asl formation with less than half a day of non productive time during the entire drilling process.
We conclude that acquisition of new, high-quality data would considerably reduce the uncertainty surrounding drilling complex wells in the area and reduce their cost.
Borehole instability, in most of the cases, is a direct reflection of earth's in situ stress state. It is well known that the stress distribution around the wellbore induces deformation depending on many factors ranging from wellbore pressure history and rock strength to the trajectory orientation.
A stress direction map is generated for the GoS from observations of borehole breakout detected in multi-arm-caliper logs and other log data base, viz., electrical Images and sonic logs. In vertical wells, the maximum tangential stress around borehole can produce breakouts and their orientation indicates the direction of minimum in situ horizontal stress (Sh). In the case of deviated wells, a stress-tensor diagram defines Sh direction with reasonable accuracy, provided wells cover wide range of deviation angle and azimuth
The current study indicates that Sh in GoS is aligned along two major trends. The main NNE - SSW trend, with average orientation of N10degE, exists in most of the region.The second trend is aligned NE - SW and observed locally at the central eastern and south-western part of GoS, with an average orientation of N50degE. Most studies of the structural and tectonic history of the GoS have identified two age significant orientations for this extensional rift. The early to middle Miocene rifting, responded to a Sh direction of N55-60degE (rift-climax). The younger stress fields of the Late Miocene and Pliocene times rotated progressively counterclockwise to a N15-25degE direction that persisted into early-late Pleistocene time. The dominant in situ stress orientation trend, identified in this study, therefore, is mainly controlled by this younger stress field of the GoS rifting.
In situ stress directions have strong impact in drilling high angle wells in GoS. Proper placement of well trajectory with respect to in situ stress reduces instability in drilling. The paper exhibits example of directional sensitivity of well trajectory and successful drilling campaign based on the developed stress map.
Drilling in Gulf of Suez is difficult due to wellbore instability, lost circulation and time dependent shale stabilization related problems. Drilling troubles in this region generally originates from high earth stresses and abundant natural fractures and faults associated with this tectonically active region. Presence of salts and evaporates with depleting reservoir pressure of a mature field aggravate the problem. Operators in this region always experienced drilling difficulties which sometime leads to well abandonment and costs over-runs in millions of dollars. Planning for the present well was the first attempt to drill a horizontal section in the porous and oil bearing Asl sand. Therefore, the main objective of the current study was to assess the risk of wellbore instability which may occur while drilling and recommend the remedial action plan for any risk encountered.
Wellbore stability analysis has a major impact on the well design and planning the orientation of trajectory for safe and stable well and successful drilling operation. Traditional drilling practices based on pore-pressure of the reservoir and fracture gradient does not necessarily proved successful especially drilling horizontal wells. The failure criterion works in a completely different way for a horizontal well compared to a vertical well in the vicinity. Therefore, a safe vertical offset well inevitably never assures that the identical drilling design and practice will safely drill a horizontal well. The stress distribution and direction works differently for a vertical and a deviated or horizontal well. A rule of thumb is that the drilling gets more and
more difficult with decreasing width of safe and stable mud window as the well becomes deviated and the situation worsen as the well turns horizontal. Adding to this complexity the direction of the trajectory with respect to in situ stress distribution and variation poses a major role in drilling a safe horizontal well.
The case history presents a geomechanical risk analysis for a planned horizontal dual lateral well. The study is based on stress regime and well failure with the significance of choosing proper mud weight and drilling parameters using a proper mechanical earth model from a nearby offset well. It includes an assessment of the major risks expected during drilling the horizontal section and also indicates magnitude of failure that can happen while drilling, based on the trajectory sensitivity analysis. The planned well was drilled without any wellbore stability related problem. The present study suggests the importance and benefits of a proper well stability study while drilling a horizontal well in a tectonically disturbed area.
The paper discusses historical data related to downhole scaling, corrosion and surveillance methods to identify affected wells. Efforts to minimize production impact due to increased corrosion seen late in the field life along with longer term corrosion mitigation efforts are also reviewed. Examples of how tubing was originally protected by thin film scale accumulation and emulsion flow during early field life production are also presented. Increasing October's completion corrosion manageability is a key challenge facing the field. Addressing issues related to predicting future well failures and their associated production loss impact rig scheduling and procurement of expensive long-lead time completion material (Cr 13%).
The approved plan is to repair six wells per year over three years considering known well problems, remaining reserves, materials and rig availability. In early 2005, six well's were worked over and visual inspection of retrieved tubing showed an excellent match with caliper log data. The most severe corrosion is typically deep in the well and is related to high CO2 partial pressures. Corrosion risk to the casing has also been identified as potential issue and wall thickness assessments have been performed on some workovers. The paper reviews these items in greater detail and proposes forward plans for the remaining life of field.
October field is located in the Gulf of Suez (GOS) approximately 200 miles southeast of Cairo, Egypt. The field is operated by Gulf of Suez Petroleum Company (GUPCO) and currently produces 100 mbfpd at 65% water cut. Productive horizons include various sandstone formations at an average depth of 11,000'subsea. Most producing wells in the field are currently lifted by gas lift.
The field experienced severe downhole CaCO3 scaling across the sandface and completion equipment during its early life. High levels of calcium chloride in the formation water and large wellbore draw down led to numerous stimulations in the early 90's. Scaling problems continued to increase until 1997 then dramatically decreased over a two-year period. The reduction in scale related well problems were clearly evident in the acid stimulation frequency of the field. This trend was unlike other analogous fields produced by GUPCO where CaCO3, BaSO4 and SrSO4 scale still continue today. Use of formation water rather than sea water, higher FBHP's due to increasing reservoir pressure and water cut through water flooding, all contributed to the reduction of scale-related problems. To date, CaCO3 scaling problems have been practically non-existent in October field despite high water cuts (average 66.4%).
High levels of CO2 in the formation fluid and gas lift system (+3% mole fraction) along with increasing water cuts led to increasing corrosion related problems in the late 90's. Efforts have been refocused in the area of downhole corrosion control and reservoir surveillance in order to maximize production and minimize cost during late field life. Recent changes in completion design include use of Corrosion Resistant Alloys (CRA's) in an effort to mitigate the impact of CO2 corrosion.
Geology and Reservoir Properties
The main Nubia reservoir at October Field is massive oil wet carboniferous sand that has an average mid zone TVD datum of -11250 feet subsea (SS). Normal faulting has divided the field into several areas. The central part of the October Nubia is elongated six miles from the northwest to southeast. It is bounded on the western and southern sides by a large fault. The structure is further complicated by a number of smaller parallel splinter faults. (Fig.1).
The Nubia has five distinct sand layers classified as the TZ, MN, M-1, M-2A and M-2b. Each layer is separated by a continuous shale, and nearly all sands have shale or low permeability barrier that is relatively thin and discontinuous. The M-2 shale is continuous across the October Field and serves as the datum reference. These layers have 525 feet of gross thickness and 488 feet net pay thickness.
Underbalanced Drilling (UBD) techniques have been evolving since 1989 andhave been justified and documented, mostly from a drilling engineering point ofview, on the basis of improvements in drilling performance. Enhancements suchas increased rate of penetration, reductions in lost circulation and virtualelimination of differential sticking have all been shown to have a significantimpact on the associated costs. However, to date, there has been a comparativelack of documentation of the improvements attainable from a productionoptimisation and reservoir engineering aspect. Very little material has beenpublished on well data enhancement, such as productive capacity, reservoir lifeand net present value, which proponents of UBD maintain should be major driverstowards its consideration in the early phases of the analysis of reservoireconomics and modeling of well construction.
This operator has committed to a campaign of drilling onshore wells, usingUBD techniques for both drilling and completion, in a well-cemented, abrasiveCambrian sandstone reservoir. This formation is characterized by relativelypoor porosity and horizontal permeability and a comparative lack of fracturingthat would normally preclude it from consideration as a good candidate for UBD,though it does have a depleted reservoir pressure.
The results obtained, in a safe and economic manner, have far exceededoperator expectations. By comparing two wells, one drilled using standardoverbalanced drilling methods, the other, a very close offset well, drilledwith UBD techniques, this paper will document an increase in well productivityin the order of twenty-five fold. It will go on to discuss the productionincreases obtained over multiple wells, 6 in total at the time of thispublication, which have been limited only by the surface handling capabilities,highlighting the changes in field development planning that have resulted fromthe successful application of UBD techniques.
Through-tubing bridge plug (TTBP) water shut-off (WSO) workovers in the October Field have resulted in an average incremental initial production increase of 2500 bopd per job. Average water cut (WC) was reduced from 55% to 16%. Seventy-eight WSO workovers have been completed since December 1991. Technical and economic success approach 90%. Just under $4.8 million dollars has been spent for an average cost of $61,500 per job. Costs paid out in less than two days using a normalized $13 per barrel crude price. Based on results achieved during the past 4.5 years, these WSO workovers establish the October Field as a notable and on-going case history for lower zone water control.
Water production from the October Field has gradually increased during the past decade. As a result, steeper production declines and gas lift operational problems developed. Based on reservoir characteristics, lower zone water was isolated using TTBP's conveyed by way of portable mast electric line units. A dump bailer was used to place a 14 foot cement cap over the TTBP to provide a permanent pressure seal. After a 24-hour shut in cement cure period, wells were almost always returned to production at a significantly higher oil rate and dramatically reduced WC. The cost of a rigless TTBP WSO workover is much less than conventional rig deployed WSO work which averaged over $500,000 per job. Prior to December 1991, rig WSO's were the only method used in the October Field. Hence, rigless WSO workovers have become vital for cost control. Rigless WSO work has also become a useful reservoir management tool for maximizing oil production and minimizing water production thereby conserving reservoir energy and optimizing lift gas.
The October Field is located offshore in the Gulf of Suez (GOS) approximately 200 miles southeast of Cairo and 70 miles north of the operating base in Ras Shukheir, Egypt (Figure 1). The October Field area is the largest of seven major producing areas in the GOS operated by the Gulf of Suez Petroleum Company (GUPCO); a joint venture between Amoco Egypt Oil Company and the Egyptian General Petroleum Corporation. Combined GUPCO GOS production averaged 365,000 bopd during early 1996. Gas lift is the most widely used form of artificial lift. Original oil in place (OOIP) for all fields approached 10 billion barrels by 1996.
This paper discusses the economical, operational and environmental aspects of the reduced hole size drilling now used in offshore operations in Gupco and other major petroleum companies operating in the Gulf of Suez Area Egypt. The results demonstrate that reduced hole size drilling saves cost : use of slim hole reduces time related intangible savings, fixed tangible savings, and tangible equipment savings.
The advantages of smaller hole size and the reduction in the volume and size of oil wet drilling cuttings help minimize the environmental impact associated with the use of oil base mud. The reduction in drilling fluid volume and treatment cost, higher rates of penetration, better hole cleaning capabilities, savings in consumables (such as bits, mud, cement and diesel oil), less tangible cost, and easier equipment mobilization are interacted to produce significant operational gains. This results in savings of 40 to 50 percent of well costs versus the cost of conventional wells drilled in the same area.
Although substantial saving were realized, there are elevated risks with the major one being the lack of a good contingency in the event unexpected hole condition or geological condition require an extra casing to be run prior to reaching the total depth. Drilling 6" hole size (or less) for long sections is difficult. Usually, very slow drilling ROP is associated with erratic directional responses, and can restrict use of MWD tools. Moreover, more drill string failures are likely to occur.
Effective preplanning between the drilling, exploration, and engineering to accurately define possible geologic targets and their potential drilling problems can minimize these risks associated with drilling slim holes and provide higher levels of success in meeting objectives.
in summary, slim hole drilling offers significant operational and environmental advantages. And cost savings relative to the conventional well design were realized in the Gulf of Suez - Egypt.
A complete study to determine the economic benefits of the slim hole well program used in the exploratory well Tanka-3
This study shows that the slim hole well program saved approximately $476M relative to drilling the well with a conventional well program.