Africa (Sub-Sahara) A drillstem test was performed on the Zafarani-2 well--located about 80 km offshore southern Tanzania. Two separate intervals were tested, and the well flowed at a maximum of 66 MMscf/D of gas. Statoil (65%) is the operator, on behalf of Tanzania Petroleum Development Corporation, with partner ExxonMobil Exploration and Production Tanzania (35%). The FA-1 well--located in 600 m of water in the Foum Assaka license area offshore Morocco--was spudded. The well targets Eagle prospect Lower Cretaceous resources. Target depth is 4000 m. Kosmos Energy (29.9%) is the operator, with partners BP (26.4%),
Africa (Sub-Sahara) Tullow Oil announced in mid-August that first oil has flowed from the Tweneboa, Enyenra, and Ntomme (TEN) fields offshore Ghana, which was on time and on budget for the project's development plan approved by the government in May 2013. The company expects oil output to ramp up gradually through the rest of the year toward a production facility capacity of 80,000 B/D. Tullow is the operator of the TEN fields with a 47.18% stake. Its joint-venture partners are Anadarko (17%), Kosmos Energy (17%), Ghana National Petroleum Corporation (15%), and PetroSA (3.82%). Asia Pacific Rosneft has made a discovery at the PLDD well in the Wild Orchid gas condensate field in Block 06.1 of the Nam Con Son Basin offshore Vietnam. The discovery is being evaluated for the volume of reserves and commercial attractiveness, and there is a potential synergy with the nearby Rosneft-operated Lan Tay production platform, the company said.
Hammad, Muhammad (Pakistan Petroleum Limited) | Ahmad, Muneeb (Pakistan Petroleum Limited) | Siddiqi, Sarmad S. (Pakistan Petroleum Limited) | Siddiqui, Amir M. (Black Gold Oilfield Services) | Kuzyutin, Roman (TGT Oilfield Services)
One of the main challenges in a water drive gas reservoir is to track fluid movement as water breakthroughs occur frequently with depletion. The understanding becomes more challenging when the structure contains seismic/sub-seismic faults with the associated drive mechanism being edge water. Moreover, surveillance options are also limited for such reservoirs if they are producing through short string of a dual completion.
Dual string completion is a cost-efficient technique as multiple reservoirs can be completed in a single wellbore. However, surveillance / logging cannot be performed across perforation intervals of upper reservoir due to operational concerns. As a result, the short string production can only be surveyed through the long string with the help of tools which have deep scanning radius extending beyond tubing and casing into the formation. One example of these advanced tools is Spectral Noise Logging (SNL) combined with High Precision Temperature (HPT) logging which have been used worldwide for such applications.
This paper presents SNL-HPT results of two dual string wells completed in Eocene age carbonate reservoir. A total of nine wells are producing from the reservoir and the Gas water contact (GWC) was not encountered in any of the wells. Selected wells are located on either side of the structure with Well A producing 1.0 MMscfd gas and 1300 bbls/d water while Well B is producing 2.0 MMscfd gas and 800 bbls/d water.
The reason of high water production from both wells was initially attributed to the presence of a high permeability streak in lower part of the reservoir and/or possibility of channeling behind casing. However, results of the SNL-HPT in both wells indicate signatures of fault or fracture flow. The major water production is coming from the middle and lower part of reservoir.
Based on these results, the trajectory of one development well was optimized. The perforation interval of another well was also decided in accordance with the SNL-HPT findings, which resulted in water-free gas production.
Quantification of reservoir flow profile in short string of dual completion well is possible through noise and temperature logging. This information would help in deciding appropriate workover strategy in existing wells and completion design of new development wells.
The under balanced drilling technology has been under applied to the oil and gas well since the first cable tool well drilling. By the advent of rotary system the drilling fluid modified into mud system for controlled and smooth drilling operations. The under balanced technology revived again in mid-70’s due to the fore most need of such technology that can enable monitoring of reservoir fluid influx while drilling in progress and minimize reservoir damage. Some of the major prospect of under balanced drilling includes depleted zones, sub-normal zones and naturally fractured reservoirs. Where the prevailing myth about UBD Technology is its utilization in naturally fractured reservoirs, this paper will help to unfold enhance reservoir production achieved by UBD technology in conventional reservoirs.
The purpose of this paper is to acknowledge the UBD Technology in conventional reservoirs, specifically. The prospects of application will be discussed with a major focus on mature reservoirs (reduced formation damage in depleted formations) and newly developed fields. Early Screening for the right reservoir and different screening criteria for the application of UBD technology in conventional reservoirs will help the readers to understand the limitations and applicability. The economic and technological advantages will be discussed along with value added by UBD technology in the form of increase reservoir production in normal pressure reservoirs which mostly get damaged to some extent with conventional drilling techniques.
The paper will briefly describe the scope of UBD in Lower Indus and Middle Indus Basin. Through the work that has been done in similar reservoirs in Middle East, analogies will be developed. For further understanding, feasibility criteria of projects in local context will be considered that will enable the operators to take decision accordingly. The paper will also briefly explain the application of under balanced technology in normal pressure reservoirs with its limitations depending upon the UBD equipment safe pressure ratings in relation to reservoir pressures.
IntroductionThe common believe that Underbalanced drilling is a modern technology is merely a myth. In fact, the very first oil well drilled in Pennsylvania; USA (1859) was underbalanced1. The cable tool drilling has utilized underbalanced drilling technique for more than half of the century. In 1920, after the advent of rotary drilling technology, overbalanced drilling was introduced to enhance safety and well cleaning.
For many years, geologists and engineers have used volumetric methods to quantify or estimate hydrocarbon volume contained in reservoirs. The economic producibility of the reservoirs, also depend on the flow characteristics. The overall level of uncertainty of the estimation depends on the uncertainty of the parameters that determine the oil volume such as porosity and the reservoir characteristics such as pay thickness. However, uncertainty of estimation increases when estimating hydrocarbon in place for complex fluids systems (i.e. heavy oil) since mobility can have an adverse effect on fluid movement. Determination of net pay cut-offs should be based on parameters that include flow and storage capacity.
Considering the requirement to establish a relationship between petrophysical cut-offs and rock types to estimate hydrocarbon in place, five different cases were used to quantify net pay parameters of the reservoir in the Cerro Negro field, Venezuela. The workflow that was applied:
1. Identification of petrophysical rock types (PRT) from porosity and permeability data using core-based and log-derived petrophysical analysis,
2. Definition of the relationship between PRT and facies
3. Determination of pay cut-offs for reservoir and each PRT using conventional and contemporary methodologies,
4. Comparison of the conventional and contemporary methodologies results,
5. Estimation of pay cut-offs impact on the prediction of rock types and reservoir petrophysical properties in the estimation of volumetric.
This study demonstrates that the definition of PRT distribution is controlled by pore throat size instead of facies. From the six rock types defined in the field just three rock types (1, 2, and 3) are oil producing rock reservoir. The OOIP results vary significantly over a range of 500 MMstb, depending on which of the parameters are used as pay cut-offs.
In conclusion, estimating OOIP by applying petrophysical rock typing is an improved way to decrease uncertainty than OOIP estimation by reservoir unit. The results demonstrated that the choice of good pay cut-offs was the key to reduce the uncertainty in the estimation of the OOIP in the Cerro Negro field.
Valzania, Soraya (ENI E&P) | Kfoury, Moussa (ENI E&P) | Grandis, Marco Giacomo (ENI E&P) | Valdisturlo, Antonio (ENI E&P) | Fanello, Giovanna (ENI E&P) | Guerra, Laura (ENI S.p.A) | Salah, Heikal (ENI) | Amjad, Kashif (ENI Pakistan Ltd) | Sultan, Mir Asif (ENI Pakistan Ltd)
Kadanwari field in Middle Indus Basin (Pakistan) was discovered in 1989 and brought on stream in 1995. The producing reservoirs are Cretaceous Lower Goru sands D-E-F-G. The gas production started from better quality E and F sands; after 2004 layer G started to drain western block of the field, with the first hydraulic fracture job made in Pakistan (well A). Layer G represents a complex target for petrophysical characterization; reservoir sandstones are micro-porosity rich, with variable presence of Chlorite affecting flow properties. Positive results encouraged the operator to drill & frac well B and to consider possibility to extend gas production throughout western block, including sand reservoirs of variable quality, from moderate to tight. The paper describes how reservoir study faced layer G complexity and how production data of wells A and B allowed a post fracjob evaluation integrating well-test data and frac-job interpretations into 3D dynamic model. After history match, the computed GOIP suggested an infilling program in G sand reservoir, with side-tracks of existing wells and new wells, all hydraulically
fractured. So far, one sidetrack and one new well have been drilled; results fully confirmed the complexity of local geological setting. The sidetrack revealed rock quality slightly better than expected (frac not necessary). Pilot well C targeted G-Sand in a sweet seismic anomaly in western area, a gas flare was observed during DST pre-frac. Mini-Fall Off was conducted to estimate closure pressure and effective mobility, but permeability computed from MFO was not conclusive due to important filtrate invasion. DST post hydraulic fracture job confirmed commercial gas rate production higher than 1 MMscfd with a peak of 3.5 MMscfd. The successful pilot well results open new horizon to improve reserve from tight sand of Lower Goru formation.
Yaqut -1 well is located in Safed Koh Lease of Dewan Petroleum Pvt Ltd. The well was a Re-entry Well. Original well was drilled in 1984 and was classified as dry well.
Dewan Petoleum decided to re-enter the same well and drill down 1356m of 6" hole to test the potential of Chiltan limestone as primary target and Sembar and Lower Goru sands as secondary targets.
The Well is located in tectonically stressed/ active area with fractured formations with under-hydrostatic head. This is the cause of severe losses even at Normal Hydrostatic head. The same case happened also with offset well drilled to same depth. Cementation of liner/ casing was very poor which generated many operational issues in post-completion life of the well.
Keeping this in mind, we worked on different options of slurry design, mechanical barication i.e use of External Casing Packers, Expandable Rubber Sleeves etc and multistage cementation. The geometry of 6" hole of about 1356m long interval and 5" Liner length of 2278m, did allowed only to manipulate with Slurry weights and discarded all other options. The final option of 7.9ppg Slurry was finalized after authentic Lab test results and ensuring slurry properties.
Designed slurry was pumped with only 28bbl loss out of 140bbls. The USIT Log was carried out which showed best cementation results.
This paper will discuss in detail the comparison of cementation results of Yaqoot-1 well with offsets. Detailed discussion of slurry designs considered for subject well along with application in under-hydrostatic fractured formations. Lab results of slurry design and USIT Logs have also been discussed in this paper to conclude the strategical justification Ultra Light Slurry Design.
Expandable technology applied as a production string, facilitates increased fracturing, and improved conductivity, enhanced hydrocarbon production. A solid expendable system can provide an integral component in new wells and re-entry wells where low permeability reservoirs need isolation and separation for selective hydraulic fracturing or re-fracturing. This system can optimize the fracturing parameters by maintaining large diameters and providing seals for selective multi zone or zonal isolation purpose. Expandable systems provide an efficient means to isolate trouble zones and preserve hole size when wellbore tapering hinders completion. Expandables used to repair the casing have extended the life of these wells without compromising the necessary hole size.
Before swellable, inflatable packers with mechanical shifted sliding sleeves were used for isolation, as well as to provide a frac and then production flow path. These systems typically require multiple trips in and out of the well bore, and tie up both rig and frac equipment, adding to higher project economics. In the past few years, an assortment of single-trip, multiple-zone isolation completion systems (modified production packers coupled with ball-actuated farce sleeves) have been developed. The application of a solid expandable system realized another step in adding value and further bolstered project economics by unlimited number of zones or sections to be fraced because no sliding sleeves or incrementally sized balls are required.
This paper explains how solid expandable system with swellable technology can be helpful to facilitate multizonal isolation, first time fracturing and re-fracturing, multi zone fracturing, and large diameter production conduits. Integration and system development of this technology will also be discussed to illustrate the effectiveness of solid expandable system in cost effective way.
At present, the rapidly growing energy demand worldwide and the higher depletion rates of existing reserves as compared to their discoveries are a major cause of gap between supply and demand. This situation of increasing gap between demand and supply has promoted the world to explore and develop unconventional resources of gas. Unconventional gas reserves include tight gas, coal bed methane (CBM), and shale gas. These resources cannot be produced economically by conventional techniques due to low productivity and low gas prices. From these unconventional resources, tight gas reserves have a huge potential for future production. Worldwide accepted definition of TGRs is "Unconventional gas resources having permeability less than 0.1md??.There is bright prospects of TGRs in lower Indus basin of Pakistan. (Fig.1-3)