Bautista, Ramiro Oswaldo Vasquez (Schlumberger) | Gonzalez, Vanessa Carolina Sanchez (Schlumberger) | El Hawy, Ahmed (Schlumberger) | Al Zarafi, Alaa (Schlumberger) | Al Busaidi, Adil (Schlumberger) | Liu, Ruikun (Petroleum Development of Oman) | Al Shidhani, Ali (Petroleum Development of Oman) | Picha, Mahesh (Petroleum Development of Oman) | Al Rashdi, Hussain (Petroleum Development of Oman)
As in most of the Sultanate of Oman fields, faulted Shuaiba fields contain formations that are extremely faulted and folded. These conditions are a result of the extensive and complex tectonic activities that broke the rock into many structurally deformed blocks. Several studies have been conducted to identify the best drilling and geosteering methods to use in the area. An additional challenge in faulted Shuaiba fields is the bounding of the target reservoir by two dense and sticky layers with similar gamma ray, resistivity, and density. With such reservoir character, differentiating between the top and bottom to make the correct geosteering decision is a real challenge when using conventional logging-while-drilling and standard drilling technologies.
A deep-directional boundary mapping tool enabled determining the borehole position inside the steeply dipping carbonate reservoir. Based on the mapping tool's directional measurements, the trajectory was adjusted to avoid exiting the reservoir from the top or bottom, thus continuously keeping the borehole within the reservoir sweet spot. A hybrid rotary steerable system (RSS) tool enabled achieving high doglegs over a short distance in response to the steep and sudden formation dip changes. If a sidetrack was found to be necessary, the hybrid RSS provided the ability to perform an openhole sidetrack in the same string to as deep as 897 m from the 7-in. liner shoe. At the same time, well design, bottomhole assembly (BHA) design and drilling parameters and envelopes were optimized, allowing new historical field records to be achieved in such challenging drilling environment, specifically, the a faulted Shuaiba fields, and in nearby Qarn Alam cluster fields.
Due to the difficulty in mapping the reservoir boundary in faulted Shuaiba fields, the operator's geological model was determined to be insufficient. With the high-resistivity contrast in faulted Shuaiba fields, the deep-directional boundary mapping tool enabled the geosteering engineer to detect the top and bottom of the reservoir to a distance up to 2.5-m true vertical depth (TVD). The ability to detect the top and bottom of the reservoir provided reasonable time to react to any sudden changes in the formation. Introducing the directional boundary mapping tool made it possible to update the geological model based on the data obtained from the tool.
During the prejob modeling, the well placement team, drilling team, and the operator's reservoir management team jointly set the geosteering objectives and assessed the risk of sidetracking the well, selected the appropriate BHA, and determined if the well would be drilled in the flank zone area. Drilling in the flank zone area was important due to the highly faulted area and sudden formation dip changes.
Due to having a better understanding of the true vertical depth (TVD) and azimuth of the faulted Shuaiba reservoirs and being able to update the structural model based on the results and boundary mapping after drilling each well, the number of required sidetracks decreased. The hybrid RSS tool enabled the well placement team to make the quick changes in the trajectory needed to avoid the reservoir top or bottom. When the sidetrack was needed, the sidetrack point could be at any position of the trajectory due to the hybrid RSS tool's capability.
Ross, T. S. (New Mexico Institute of Mining & Technology) | Rahnema, H. (New Mexico Institute of Mining & Technology) | Nwachukwu, C. (New Mexico Institute of Mining & Technology) | Alebiosu, O. (ConocoPhillips Co) | Shabani, B. (Oklahoma State University)
Steam injection—a thermal-based enhanced oil recovery (EOR) process—is used to improve fluid mobility within a reservoir, and it is well known that it yields positive results in heavy-oil reservoirs. In theory, steam injection has the potential of being applied in light-oil reservoirs to enable vaporization of in-situ reservoir fluids, but field developments and scientific studies of this application are sparse. Conventional displacement methods like water-flooding and gas-flooding have been applied to some extent, however, oil extraction in such reservoirs relies on recovery mechanisms like capillary imbibition or gravity drainage to recover oil from the reservoir matrix. Furthermore, low-permeability reservoir rocks are associated with low gravity drainage and high residual oil saturation.
The objective of this study is to evaluate the potential of steam injection for light (47°API) oil extraction in naturally-fractured reservoirs. It is theorized that this method will serve as an effective tool for recovery of light hydrocarbons through naturally-fractured networks with the benefit of heat conduction through the rock matrix. This research investigates the application of light-oil steamflood (LOSF) in naturally- fractured reservoirs (NFR).
A simulation model comprised of a matrix block surrounded by fracture network was used to study oil recovery potential under steam injection. To simulate gravity drainage, steam was injected through a horizontal well completed in the upper section of the fracture network, while the production well was completed at the bottom of the fracture network. The simulation included two different porous media: (1) natural fractures and (2) matrix blocks. Each of these porous media was assumed to be homogeneous and characterized based on typical reservoir properties for carbonate formations. This study also analyzed the impact of different recovery mechanisms during steam injection for a light-oil sample in NFR, with reservoir sensitivity examined, based on varying amounts of vaporization, injection rate, permeability, matrix height and capillary pressure. Of these, vaporization was found to be the dominant factor in the application of LOSF in NFR, as described in detail within the results.
Hawy, Ahmed El (Schlumberger) | Picha, Mahesh Shrichand (Is'Haq Habsi, PDO) | Soliman, Fathy (Is'Haq Habsi, PDO) | Haeser, Patrick A C M (Is'Haq Habsi, PDO) | Hadhrami, Moosa Al (Is'Haq Habsi, PDO) | Kindi, Adil Al (Is'Haq Habsi, PDO) | Eljenni, Mounir (Is'Haq Habsi, PDO) | Busaidi, Ibrahim AL (Schlumberger) | Busaidi, Adil Zahran Al (Schlumberger) | Bazara, Magdi (Schlumberger) | Omara, Ahmed Sadig (Schlumberger)
As conventional drilling learning curves mature from drilling simple vertical wells to deviated wells to complex multilateral horizontal wells, the boundaries needed to be broken to reach much deeper depths rather than consuming the time in drilling multiple shorter laterals. Horizontal ERD wells in Qarn Alam cluster were planned to be drilled in four sections where the 17.5-in section is drilled vertically followed by a deviated 12.25-in section and continued by landing in 8.5-in section and finally the 6.125-in horizontal lateral. Many attempts of performance improvement initiatives were executed over many years however there were always flaws and inconsistency in drilling performance delivery. As the need of ERD grew, a detailed offset wells analysis had to be performed where all the deficiencies and issues had to be pin pointed, RCA (Root Cause Analysis) had to be performed and plans for success had to be laid out. From challenges achieving required dog legs in the top sections with increased risks of axial and lateral vibrations, to the difficulties faced in the landing section drilling through unconsolidated and reactive shales, to the difficulties transferring weight to the bit at deeper depths in the horizontal laterals drilling highly porous zones of sticky limestones resulting in severe torsional vibrations. A new approach of drilling had to be executed with a renovated set of drilling parameters envelopes, revised trajectory designs, re-engineered BHA designs, right choice of fit for purpose bits and effective real-time performance monitoring.
The majority of enhanced oil recovery (EOR) projects are being executed in the the U.S., Canada, Venezuela, Indonesia and China. The volume of oil produced by EOR methods increased considerably from 1.2 MMBD in 1990 to 2.5 MMBD in 2006 (Sandrea and Sandrea 2007). Current total world oil production from EOR is approaching 3 MMBD representing about 3.5% of the daily global oil production (Sandrea and Sandrea 2007). Thermal and CO2 methods are the major contributors to EOR production, followed by hydrocarbon gas injection and chemical EOR. Other more esoteric methods, e.g., microbial, have only been field tested, without any significant quantities being produced on a commercial scale. In recent years, the number of EOR projects has increased with escalating oil prices.
The number of EOR projects in the Middle East (ME) has also increased over the past decade. In some countries like Oman, there has been no choice but to implement EOR projects aggressively due to dwindling ?easy oil.? Other countries in the region have also started to think EOR, and are including them in their strategic short-, medium- and long-term development plans. Furthermore, there are many projects on the drawing board and appropriate screening studies and EOR pilots are being pursued region-wide. This paper reviews the current ME EOR projects from full-field development to field trials, including those on the drawing board. The option of advanced secondary recovery (ASR) — also known as improved oil recovery (IOR) — technologies before full-field deployment of EOR is also discussed. A case is made that they are a better first option before deployment of capital-intensive EOR projects. The ME‘s general drive towards ?ultimate? oil recovery — instead of immediate oil recovery — is highlighted in the context of EOR. Some of the enablers for EOR in the ME are also discussed in the paper. It highlights the opportunities and challenges of EOR specific to the region.
Company Profile Series - No abstract available.
The Oudeh Shiranish reservoir in Syria contains 5.1 billion bbls of 12-16 oAPI crude oil. However primary recovery factor is estimated to be only 5 to 7% of the original oil in place. To increase oil recovery, waterflood, VAPEX, microbial treatment and cyclic steam stimulation (CSS) were examined. Eventually, CSS was selected for a pilot test despite the depth of the reservoir, approximately 1600 meters, was deeper than most successful CSS projects in the world.
The CSS pilot was implemented in September 2006 and suspended in November 2009. The project expanded from 2 to 24 wells. Low steam quality at the bottom of the well proved to be the most prominent challenge due to a combination of heat loss in the wellbore and relatively low steam injectivity. Only hot water reached the bottomhole when steam was injected through casing. Injection into tubing improved steam quality. Vacuum insulated tubing (VIT) produced the best, increasing steam quality to between 20 and 40% at a wellhead steam quality of 80% and an injection rate of 200 m3 CWE/day. The high pressure required to inject into the Shiranish reservoir at close to or higher than initial reservoir pressure conditions means that the latent heat of vaporization is low, compared to the typical CSS injection pressure, resulting in a less effective heating process.
In the study, a new thermal simulation model was developed to examine history-matching parameters, match the well and pad performances and optimize operations if the pilot were to be continued. Excellent history matches were achieved. Forecast indicated that Shiranish CSS performance was positive and could increase oil recovery by up to 100% over cold production.
Steam injection in naturally fractured formations has been drawing considerable interest for more than three decades. It is believed that the steam heats the rock, which then undergoes a thermally induced wettability reversal. Hot water can then spontaneously imbibe into the water wet rock matrix, resulting in favorable oil recoveries. In this study, the applicability of steam injection in an oil wet undeveloped Iranian extra-heavy oil fractured carbonate reservoir is discussed. A geological model calibrated with results of a handmade model was used to study the optimum operating conditions under continuous steam injection. It was observed that under this operating strategy in which the main oil production mechanism is heat transfer, steam injection rate and existence of layers which are open to flow, injection and production pattern are directly related to success of the process and because of high viscosity of oil at the reservoir temperature its influences on final recovery is negligible. Initial pressure of the undertaken reservoir is 927 psi at 1700 ft depth. The gravity of the oil is 7.24 °API with viscosity of about 2700 cp at reservoir temperature. This field is a highly fractured carbonate reservoir with 3.6 billion barrel estimated oil in place. It was further observed that during 50 years which this reservoir has been undertaken to study under discussed recently found strategy, crude oil production reaches to more than 900 barrels per day.
Nengkoda, Ardian (Petroleum Development Oman) | Habsi, Mohd (Petroleum Development Oman) | Salmi, Ahmed (Petroleum Development Oman) | Annamalai, Ilangovan (Petroleum Development Oman) | Ahmed, Dilshad (Petroleum Development Oman) | Sariry, Sameer (Petroleum Development Oman) | Hadhrami, Hamoud (Sultan Qaboos University)
The X field of Oman is a highly fractured carbonate field. The main oil bearing reservoir is the Shuaiba/Kharaib formation. Full development of the field will result in large water production that will have to be disposed off. Plan is to inject the produced water into the Al Khlata sands. The availability of sufficient water disposal capacity is a crucial element of the X steam project. If this capacity is constrained, water production from the X field is limited and it may not be possible to maintain the oil rim at the completion depth of the fracture rim producers. This may cause the oil production of the whole field to be deferred. For the base case, the total forecasted water production ranges from 63,000 to 74,000 m3 /d for 30 years. During pilot plant operation in year 1998-2000 and cold production, the formation damage and loss injectivity have been reported at produced water disposal wells. The main objective of this study is to ascertain the cause of rapid injectivity loss and input design for facilities selection. The assessment are cover the oil and solid particle size, fluid chemistry and compatibility, suspended solid in disposed water, the impact of oil in disposed water, fine migration (critical velocity test) and proper produced water treating facilities selection (equipment and technology).
Nengkoda, Ardian (Petroleum Development Oman) | Ahmed, Dilshad (Petroleum Development Oman) | Reerink, Hendrikus (Petroleum Development Oman) | Sariry, Sameer (Petroleum Development Oman) | Al-Riyami, Maisoon Mohammed (Petroleum Development Oman) | Dobretsov, Sergey (Sultan Qaboos University)
The X Field steam-injection project in Sultanate of Oman is the world's first full-field steam-injection project based on thermally assisted gas/oil gravity drainage (TAGOGD) in a fractured carbonate field. The project scope includes drilling some wells and installing facilities to treat water and generate around 18,000 tonnes per day of steam, the plant targeted to be started up in around year 2010. Additional facilities will be built to process the incremental oil and gas produced at the field as well as disposing of excess produced water in deep reservoirs. The X field, which was discovered around year 1970 contains a moderately viscous crude in rock that is rather impervious to its flow. The EOR recovery process being applied - TAGOGD - is based on injecting steam into the formation's fractures to heat the low-permeability oil-bearing rock. As the rock is heated, gas is liberated and the viscosity of the oil is reduced, flowing much more easily into the fractures under the action of gravity. This feature of the project allows the number of wells, and hence development costs, to be kept to a minimum. The paper explains the selection of green chemicals as an opportunity for water treatment facilities of Steam EOR process. Green chemicals are a class of compounds that are biodegradable and less toxic and the selection started with facilities expectation. For most water treatment and boiler applications, the majority of the chemical compounds used tend to be inorganic and non-biodegradable. This is primarily because facilities needs a strongly alkaline source to prevent corrosion. As a result, most of the chemicals have a pH of 8.5 or above depending upon inhibition. In order to applied green chemicals, we need to develop a matrix and inspect industrial applicable green chemicals based on MSDS, technical expectation and OPEX. Toxicity and biodegradability are listed on the sheets. One final thing is the attempt to be green is more of an attitude and application of existing technology.
X Field is located in central Sultanate of Oman south of the western Hajar Mountains. This large oil accumulation is trapped in shallow Cretaceous limestone units at a depth of around 200-400m subsea. The anti-clinal structure is a result of a deep salt diaper, with significant crestal faulting and fracturing. The field was discovered in around 1970 and contained 16° API oil with a viscosity of 220cP has been produced from the 29% porosity, low permeability (5-14mD) limestone. During the primary production the first year showed a large peak in oil mainly from emptying of the fracture network with a minor contribution from fluid expansion due to pressure reduction. At the end of the first year, production had declined to a very low sustainable rate interpreted to be from gravity drainage, from a combination of gas-oil (GOGD) from the secondary gas cap and oil-water (OWGD) below the fracture gas-oil contact (FGOC). The reservoir then consists of a matrix with very little drainage and a fracture network with a thin oil rim below the secondary gas cap and above the fracture oil-water contact (FOWC), Figure 1.
Primary production performance such as that of X Field is only expected to recover some 3-5% of the oil in place over any reasonable time frame due to low matrix permeability and high oil viscosity on gravity drainage rates. Recoveries via steam were discounted as development options due to the pervasive fracturing observed in the field which would encourage the flooding agents to completely bypass the matrix.